The Alberta Utilities Commission (AUC) issues a decision at the end of each regulatory proceeding. A decision takes into consideration all information from the application and hearing process. The result is approval or denial of the application in full, in part, or with conditions.
The following decision summaries are provided by the Office of the Utilities Consumer Advocate (UCA) and are intended to provide a general overview of more significant proceedings. The Alberta Utilities Commission (AUC) publishes the full reports and official decisions for all proceedings on its website.
AUC Decision 23793-D01-2019, June 25, 2019
On June 30, 2018, ATCO Pipelines, a division of ATCO Gas and Pipelines Limited, filed an application with the Alberta Utilities Commission (“Commission”) requesting approval of its revenue requirements of approximately $290 million for 2019 and $315 million for 2020 respectively, which are to be recovered from customers within ATCO Gas & Pipelines service territories. In the application, ATCO Pipelines requested approval of various costs including the costs for its proposed quality control initiatives of approximately $2.8 million for 2019 and $3.7 million for 2020.
Following an open and public process, the Commission, the UCA and other intervenors identified a number of issues with ATCO Pipelines’ application. Accordingly, the Commission denied ATCO Pipelines request and ordered ATCO Pipelines to make a number of changes to its application, including removing the costs associated with the proposed quality control initiatives for each of 2019 and 2020 respectively.
AUC Decision 24111-D01-2019, June 10, 2019
On December 4, 2018, Direct Energy Regulated Services (“DERS”) filed an application with the Alberta Utilities Commission (“Commission”) requesting approval to recover $1.1 million in costs, which were incurred because of changes to its billing system arising from ATCO Gas and Pipelines (“ATCO”) routes realignment program associated with aerial meter reading by ATCO on behalf of DERS. In the application, DERS sought to recover the cost through a charge of $0.023 per site per day on customer bills from August 1, 2019 to October 31, 2019.
Following an open and public process, the Commission, the UCA and other intervenors identified issues with DERS’ application. Consequently, the Commission denied DERS recovery of the $1.1 million asserting that such recovery will constitute retrospective ratemaking, which is not permitted under the current regulatory regime in Alberta.
AUC Decision 20514-D02-2019, June 5, 2019
On June 4, 2015, the Alberta Utilities Commission (“Commission”) initiated the ATCO Utilities Information Technology Common Matters Proceeding to examine prices related to master services agreements (MSAs) between the ATCO Utilities and Wipro Solutions Canada Limited (Wipro) for the provision of information technology (IT) services to the ATCO Utilities. In August of 2014 ATCO sold ATCO I-Tek, ATCO’s IT services company to Wipro for approximately $204 million. ATCO also contracted with Wipro for IT services and entered into 10-year MSAs.
The prolonged and complicated four-year proceeding that ensued was concluded when the Commission decided, on June 5, 2019, that the ATCO Utilities had failed to act prudently in their consideration of the IT sourcing alternatives available to them at the time and that the requirement for the MSA service provider to purchase ATCO I-Tek served as a restriction on competition, limited the pool of potential bidders (because it excluded from the process all those interested in bidding only on the MSAs), and resulted in the MSA prices being higher than they would have otherwise been. Having found that the resulting MSA prices were not at Fair Market Value, the Commission has ordered a reduction of 13 per cent to the first year of the MSAs, 2015, and further reductions in each of years 2 through 10 of the MSAs. This Decision impacts several other AUC proceedings and will have a very significant cost impact on ATCO Utilities and its subsidiaries.
AUC Decision 22635-D01-2018, December 21, 2018
On May 5, 2017, Direct Energy Regulated Services (“DERS”) filed with the Alberta Utilities Commission its energy price setting plan (“EPSP”) setting out how the monthly charges for the energy it procures from May 1, 2018, to April 30, 2020, will be determined. DERS provides energy to regulated rate option (“RRO”) customers within the service territories of ATCO Electric and ATCO Gas. In the EPSP, DERS requested approval of a fixed risk margin of $7.97 per megawatt hour (MWh) for electricity as well as the inclusion of an approved after-tax return margin of $2.83/MWh in its monthly energy charges from May 1, 2018, to April 30, 2020 inclusive. The fixed risk margin of $7.97/MWh, which DERS determined based on its perceived financial risk exposure from providing electricity to RRO customers, was a deviation from the Commission’s approved adaptive methodology, that adjusts with the market on a lagged basis, for calculating the risk margin for RRO providers.
Following an open and public process, the Commission, the UCA and other intervenors identified a number of issues with DERS’ 2018-2020 EPSP including, but not limited to, potential over-compensation of DERS for its role as an RRO provider due to its proposed fixed risk margin, lack of transparency in how DERS determined the risk margin and the use of a fixed risk margin rather than the existing adaptive risk margin. Accordingly, the Commission denied DERS’ request and ordered DERS to calculate its monthly energy charges based on the existing adaptive risk margin and to include an after-tax return margin of $2.83/MWh of electricity.
AUC Decision 22570-D01-2018, August 2, 2018
Decision 22570-D01-2018, issued August 2, 2018, by the Alberta Utilities Commission (“the Commission”) is also known as the “2018 Generic Cost of Capital” decision. This decision set the approved return on equity (ROE) for the years 2018, 2019, and 2020 for all of the regulated distribution and transmission utilities in Alberta as well as the deemed equity to debt ratios (also known as capital structure). The cost of capital generic proceedings, held periodically, essentially determine the amount of profit the utilities are entitled to earn. The utilities subject to generic cost of capital decisions include AltaGas Utilities Inc., AltaLink Management Ltd., ATCO Electric Ltd., ATCO Gas & Pipelines, ENMAX Power Corporation, EPCOR Distribution and Transmission, FortisAlberta Inc., the City of Lethbridge, the City of Red Deer and TransAlta Corporation.
Following an open and public process that included an oral hearing, the Commission considered extensive evidence from all parties, including the UCA, pertaining to factors such as Canadian capital market conditions, financial models, risks faced by the utilities and global economic conditions. It then rendered its decision setting the approved return on equity (ROE) at 8.5% for the years 2018, 2019, and 2020. For comparison, the Commission had previously set the ROE to 8.5% in 2017 and 8.3% in 2016, under Decision 20622-D01-2016, the 2016 Generic Cost of Capital Decision. Decision 22570-D01-2018 also set out the deemed equity to debt ratios at 33% equity and 63% debt for all of the companies except AltaGas Utilities Inc., whose equity ratio was set at 39% to accommodate its slightly higher business risks compared to other utilities.
AUC Decision 23275-D01-2018, July 5, 2018
On January 18, 2018, EPCOR Energy Alberta (“EEA”) filed with the Alberta Utilities Commission (“Commission’) an application to recover approximately $1.7 million in costs its incurred for hiring subject matter experts and legal counsel to support it during the regulatory intervention of its 2018-2021 Energy Price Setting Plan (EPSP). In the application, EEA sought the Commission’s approval to allow it to recover the $1.7 million through rates from its regulated rate option (“RRO”) customers.
Following a written proceeding, the Commission and the UCA identified certain issues with EEA’s cost recovery application pertaining to its external consultant and legal fees. The Commission determined that some of EEA’s costs were unnecessary and therefore reduced the amount to be recovered by EEA from RRO customers by about 39 percent (or $660,000).
AUC Decision 21608-D01-2018, June 5, 2018
In Decision 21608-D01-2018, dated June 5, 2018, the Alberta Utilities Commission (“the Commission”) determined that while all five of the criteria to qualify for a “Z factor” rate adjustment had been met to compensate ATCO Gas and Pipelines Ltd. (“ATCO Gas”) for the costs it incurred as a result of the 2016 Regional Municipality of Wood Buffalo wildfire (“wildfire”), it was subject to a certain adjustment proposed by the Office of the Utilities Consumer Advocate (“UCA”). On July 28, 2017, ATCO Gas had filed its Z factor application to recover $11.199 million through a Z factor rate adjustment. ATCO Gas was looking to recover $11.079 million in operations and maintenance (O&M) costs and lost revenue, and $120,000 in revenue requirement amounts associated with capital asset replacements of $2.2 million.
In reaching its Decision, the Commission determined that the characteristics of the wildfire were of a similar nature and magnitude to the nature-related events identified in ATCO Gas’s 2009 depreciation study, and thus the Commission concluded that the wildfire did not give rise to an extraordinary retirement of the destroyed assets. Therefore, the depreciation expense associated with the replaced assets will continue to be recovered from ratepayers. The Commission also deemed the applied-for capital and O&M costs to be prudent, and agreed it was incumbent on ATCO Gas to meet its obligation to supply service to active sites located downstream of destroyed areas, as well as to inactive sites to ensure facilities were in place to provide gas utility service to its customers when they returned. In regards to ATCO Gas’ claim for lost revenue, however, the Commission agreed with the UCA’s assertion that it was not clear that “but for” the wildfire, ATCO Gas would have been receiving revenues from customers of the destroyed, uninhabitable or vacant sites. It is estimated that the cost disallowance ordered by the Commission will equal $51,000.
AUC Decision 22357-D01-2018, March 16, 2018
In Decision 22357-D01-2018, dated March 16, 2018, the Alberta Utilities Commission (“the Commission”) approved EPCOR Energy Alberta GP Inc.’s (“EPCOR”) Energy Price Setting Plan (“EPSP”) for 2018 to 2021. EPCOR is a regulated rate option (“RRO”) provider, regulated by the Commission, and provides service to customers in the EPCOR and FortisAlberta Inc. service areas. The EPSP establishes the electricity pricing structure for RRO customers within the service areas.
The Commission, in this decision, approved EPCOR’s proposed “Descending Clock Auction” for procurement of energy and a new method for calculating commodity risk compensation (“CRC”) to be applied to electricity prices. During the term of EPCOR’s EPSP, electricity prices for RRO customers are subject to a price cap of 6.8 cents per kilowatt-hour under the regulation entitled, An Act to Cap Regulated Electricity Rates.
Following an open and public process, the UCA and other intervenors participated in challenging various aspects of the application. Ultimately, the Commission approved many aspects of EPCOR’s proposals. The Commission indicated its expectation that the first procurement auction under the 2018-2021 EPSP will begin in September 2018, and that the first month for which energy rates will be determined is January 2019. In the meantime, EPCOR will continue purchasing electricity under its current, previously approved EPSP.
AUC Decision 22394-D01-2018, February 5, 2018
In Decision 20414-D01-2016 (Errata), dated February 6, 2017, the Alberta Utilities Commission (“the Commission”) established the parameters for the second generation of performance-based regulation (PBR) plans to be implemented for the 2018-2022 period for six Alberta distribution utilities: AltaGas Utilities Inc., ATCO Electric Ltd., ATCO Gas and Pipelines Ltd., ENMAX Power Corporation, EPCOR Distribution & Transmission Inc., and FortisAlberta Inc. (“the Utilities”). The Commission directed each utility to file an application to comply with its directions by March 31, 2017.
The parameters established in Decision 20414-D01-2016 (Errata) include: (1) setting going-in rates for the next PBR term on the basis of a 2017 notional revenue requirement using the actual lowest operating and maintenance (O&M) costs for the previous years of the first PBR term with adjustments for anomalies (2) criteria to determine if certain costs qualify as anomalies for the purpose setting going-in rates and (3) calculation of return on equity (ROE). The PBR scheme establishes the initial revenue requirement with an annual formulaic adjustment for each of the six utilities.
On April 21, 2017, the Utilities filed applications with the Commission seeking approval of their going-in rates for the 2018-2022 PBR term. Additionally, the Utilities sought approval of costs associated with their proposed O&M anomalies and the corresponding methodologies used to determine them.
Following an open and public process, the Commission, the UCA, and other intervenors identified a number of issues with the methodologies used by the utilities to determine their O&M costs as well as the anomalies. Consequently, the Commission directed the six utilities to remove from the 2017 notional revenue requirements all proposed costs associated with the O&M anomalies. When combined, this resulted in approximately $153 million of costs that were disallowed to be recovered from customers through rates over the 5-year term.
Transmission Facilities Cost Monitoring Committee
The Transmission Facilities Cost Monitoring Committee (TFCMC) was established by the Minister of Energy in July 2010 and is responsible for reviewing records related to cost, scope, schedule and variances of Alberta transmission facility projects that are forecast to cost in excess of $100 million.
The TFCMC has 13 members representing the following:
The Committee releases reports semi-annually:
- Review of Cost Status of Major Transmission Projects in Alberta - June 2018
- Review of Cost Status of Major Transmission Projects in Alberta - December 2017
- Terms of Reference
- Review of Cost Status of Major Transmission Projects in Alberta - June 2017
- Review of Cost Status of Major Transmission Projects in Alberta - December 2016
- Review of Cost Status of Major Transmission Projects in Alberta - June 2016
- Review of Cost Status of Major Transmission Projects in Alberta - December 2015
- Review of Cost Status of Major Transmission Projects in Alberta - June 2015
- Review of Cost Status of Major Transmission Projects in Alberta - December 2014
- Review of Cost Status of Major Transmission Projects in Alberta - June 2014
- Review of Cost Status of Major Transmission Projects in Alberta - December 2013
- Review of Cost Status of Major Transmission Projects in Alberta - June 2013
- Review of Cost Status of Major Transmission Projects in Alberta - December 2012
- Review of Cost Status of Major Transmission Projects in Alberta - June 2012
- Transmission Cost Recovery Subcommittee Report - June 2012
- Review of Cost Status of Major Transmission Projects in Alberta - December 2011
- Review of Cost Status of Major Transmission Projects in Alberta - June 2011