Electricity – Rates
Application
ATCO Electric Ltd. (“AE”) and FortisAlberta Inc. (“FortisAB”) applied for 2023 cost-of-service (“COS”) review. The proposed rates will also serve as going-in rates for the third term of performance-based regulation (“PBR”). The applications also put forward hybrid methodologies for forecasting 2023 costs. The hybrid approach uses mechanistic and non-mechanistic approaches to arrive at their respective forecasts. Under the mechanistic approach, the utilities forecast costs by calculating the average of actual costs incurred in the 2018 to 2020 period and then escalating that average by certain escalation factors such as inflation and customer growth. Under the non-mechanistic approach, the utilities forecast from the bottom up, which is a traditional way to forecast costs under COS regulation.
Decision
The AUC required a compliance filing before issuing a final decision. In addition to responding to the AUC’s directions, the utilities were directed to include in their respective compliance filings the calculation of 2023 rates based on the approved revenue requirement. Each utility was further directed to include in its compliance application all information that typically accompanies the calculation of rates.
Applicable Legislation
AUC Bulletin 2021-04: Stakeholder consultations to evaluate performance-based regulation in Alberta and to determine process to establish 2023 rates for distribution facility owners (1 March 2021)
AUC Rule 005: Annual Report Requirements of Financial and Operational Results
AUC Decision 26354-D01-2021 – Process to Establish 2023 Rates for Alberta Electric and Gas Distribution Utilities (8 June 2021)
AUC Decision 25916-D01-2021 – 2022 Phase II Distribution Tariff Application (8 June 2021)
AUC Decision 26521-D01-2021 – Revised Regulatory Accounting Treatment for Alberta Electric System Operator Customer Contributions (6 October 2021)
Pertinent Issues
Under the approach applied in this proceeding, if a utility faced any challenges managing its costs such that its earnings were below the approved return on equity (“ROE”), the COS rebasing allows the utility to make its case to the AUC to set rates that will allow it a reasonable opportunity to earn the approved rate of return in the future. This was not the case for either AE or FortisAB as they earned more than their approved ROE in most years of the second term of PBR.
The Industrial Power Consumers Association of Alberta (“IPCAA”) and the Consumers’ Coalition of Alberta (“CCA”) proposed that any earnings above the approved ROE must be passed on to customers in their entirety because such earnings reasonably approximate the achieved efficiencies and associated cost savings. The AUC disagreed. The AUC noted that achieved ROEs are not driven entirely by efficiencies. Further, the proposal of the IPCAA and the CCA would effectively implement an after-the-fact earnings/sharing mechanism (“ESM”). The AUC also disagreed with the proposal because the introduction of an ESM to the PBR plan, after the elements of the second term of PBR were established, and without considering the interaction of an ESM with all other elements of the plan, may have a deleterious effect on the incentives to reduce costs. Finally, the AUC determined that introducing an ESM after-the-fact would undermine the credibility of the AUC. The proposal of the interveners would amount to the retroactive confiscation of earnings above the approved ROE, without addressing any such considerations.
AE and FortisAB submitted that they do not systematically track efficiencies gained for individual projects or programs in real-time. Both utilities argued that it was impractical, inefficient, and not cost-effective to track whether specific programs achieve intended efficiencies. Utilities prepare business cases for major projects and programs. Often the very rationale for the initiatives underlying the business cases relate to efficiency gains and cost savings projected to be realized by implementing a new process or technology. The AUC, therefore, did not find it credible for the utilities to suggest that they are unable to assess potential efficiency gains at the project approval stage and subsequently track if efficiencies are realized.
FortisAB and AE used escalation factors to simplify variance explanations for the 2023 cost forecast under the non-mechanistic approach. Also, for cost categories forecasted under the mechanistic approach, the utilities used the escalation factors to adjust the historical average actual costs to arrive at the 2023 forecasts. The AUC noted that the reasonableness of the 2023 revenue requirement forecasts contained in the rebasing applications is dependent in large part on the reasonableness of the escalation factors used by the utilities.
AE and FortisAB applied for approval to receive the costs of designing and implementing Demand-Side Management (“DSM”) programs. The AUC denied AE’s Emissions Reduction and Energy Efficiency program and FortisAB’s low-income DSM initiative, customer education, and awareness of smart services and technologies initiatives. FortisAB’s managed electric vehicle (“EV”) charging pilot was approved.
FortisAB requested approval of capital additions in the forestry protection project which it argued would reduce the risk of wildfire ignitions caused by FortisAB’s system. The investments would diminish the occurrence of significant losses and costs associated with such projects. The AUC approved the associated capital additions and accepted the explanations regarding the deviation of the forecasts from the escalated 2013-2017 average capital additions.
FortisAB’s Advanced Metering Infrastructure (“AMI”) meters record customer energy and demand data, along with voltage and current data, providing visibility of
the distribution system at an individual site level. In 2024, FortisAB’s current AMI vendor will be ceasing production of the Power Line Carrier (“PLC”) used by FortisAB for its current AMI system. FortisAB was able to negotiate the continued supply of the PLC AMI meters until 2024 and operational support for the PLC AMI system until the end of 2029. As decommissioning of 3G cellular networks in Alberta is planned to begin in 2023, FortisAB anticipated the need to transition to a new metering system that uses a combination of radio-frequency and cellular technology and can replace both the existing PLC and 3G AMI systems.
The AUC found that ATCO Electric’s cautious approach with relatively little spending in the 2017-2021 time period, followed by a staged implementation of Advanced Distribution Management System projects, AMI meters and Asset Modernization projects in the 2022-2028 time period, to be reasonable.
FortisAB proposed the addition of a new Remote Community Reliability Program beginning in 2023. This program is required to provide increased reliability to remote communities that experience below-average reliability. FortisAB suggested approval of the forecast additions as it would be allowed to own and operate an energy storage facility under to Bill 22 – Electricity Statutes (Modernizing Alberta’s Electricity Grid) Amendment Act, 2022 (“Bill 22”). Bill 22 passed third reading on May 12, 2022 and received Royal Assent, but Bill 22 has not come into force at the time of this decision. FortisAB further did not meet the criteria established by Bill 22 for distribution utilities to own and operate an energy storage facility. The AUC therefore decided that it is not reasonable to include these costs as part of FortisAB’s 2023 forecast revenue requirement.
AE requested approval of capital additions in 2023 for a proposed Light Detection and Ranging (“LiDAR”) project, to increase efficiency in completing ground-based patrols and for optimization modeling and risk-based vegetation management. The AUC accepted the capital additions but did not accept the submission from AE that the project would not likely decrease expenditures in the future. The AUC noted that it expects that AE’s investments in this technology would allow AE to find opportunities to reduce costs, particularly as AE indicated that LiDAR would optimize modeling and risk-based vegetation management.
AE proposed a new capital Grid Modernization Program, to ensure its distribution system can accommodate a fundamental shift in grid usage that will be brought about by a rise in Distributed Energy Resources and EVs, decarbonization efforts, changing customer expectations and behaviours, and a changing and challenging climate. AE noted that it had applied for grant funding in the 2022-2024 period through Natural Resource Canada’s Sustainable Resource Electrification Pathways program. At the time of the hearing, AE had secured funding of 50 percent of its expenditures for one project, and applications for the remaining two projects of the GMP were in progress. The AUC found AE’s GMP as reasonable and approved the 2023 forecast capital additions, subject to adjustments to reflect the approval of the Natural Resource Canada grant for the ADMS project and any other subsequent grants for Asset Modernization and AMI projects.
