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 29204-D01-2024, November 29, 2024 and 29204-D02-2025, February 12, 2025
On October 8, 2024, the Alberta Utilities Commission introduced the 2025 Rate of Last Resort (RoLR) energy price setting plan application. This initiative was designed to provide a stable and predictable electricity rate for consumers who are unable to select a competitive energy plan from Alberta's retail market. The RoLR is intended to replace the previous Regulated Rate Option monthly variable offering with a fixed rate, offering protection from market volatility. Interveners, including the UCA, entered a Negotiated Settlement Process with EPCOR Energy Alberta GP Inc., ENMAX Energy Corporation, and Direct Energy Regulated Services (RoLR providers).
Outcome
On November 11, 2024, The Alberta Utilities Commission approved the negotiated settlement between the RoLR providers and the Office of the Utilities Consumer Advocate regarding the 2025-2026 RoLR rates. The RoLR took effect on January 1, 2025, offering a fixed electricity rate for two years and may only be adjusted by a maximum of 10 per cent, up or down, after the end of the first two-year term. This provides customers with stability and predictability in their energy costs.
The rates for the first two-year term are set at:
- 12.01 cents/kWh for EPCOR Energy Alberta GP Inc.
- 12.06 cents/kWh for ENMAX Energy Corporation
- 12.02 cents/kWh for Direct Energy Regulated Services
These rates will apply from January 1, 2025, to December 31, 2026, unless an adjustment is required through a rate reopener proceeding initiated by the Commission, as specified in the RoLR Regulation.
AUC Decision 28939-D01-2024, September 17, 2024
On April 29, 2024, Direct Energy Regulated Services (DERS) submitted an application with the Commission requesting approval for its natural gas default rate and electricity regulated rate tariff functions for the period from January 1, 2024, to December 31, 2026, within the service territories of ATCO Gas and Pipelines and ATCO Electric Ltd. The application included requests for approval of several components, including site forecasts, customer care and billing, merchant fees, credit charges, bad debt expense, amendments to terms and conditions, and full-time equivalents and labor costs. DERS engaged in a Negotiated Settlement Process with interveners, including the UCA, to discuss and negotiate the revenue requirements and rates.
Outcome
On September 17, 2024, the Commission issued Decision 28939-D01-2024 approving the Negotiated Settlement Agreement (NSA) between DERS and the interveners. The Commission determined that the negotiated rates and terms are just and reasonable for ratepayers. The NSA results in revised revenue requirements and lower rates for DERS’ customers compared to the initial application, with adjustments to site count forecasts and several cost categories.
AUC Decision 28300-D01-2024, May 22, 2024
In Proceeding 28300, the Alberta Utilities Commission (Commission) considered whether ATCO Electric Distribution (AED) and ATCO Gas Distribution (AGD) charged distribution utility rates that were not just and reasonable during the second generation of Performance Based Regulation (known as PBR2) from 2018 to 2022. PBR is a form of energy regulation and is used to regulate distribution utilities in Alberta. Under PBR, utilities are incentivized to find efficiencies in their work, and to pass those efficiencies on to customers through rates. This proceeding was initiated by the Commission after the UCA provided a letter demonstrating that both utilities achieved returns on equity (ROE) that exceeded thresholds for review set out in the PBR2 plan.
In this stage one proceeding, the Commission set out to determine if there was a flaw with the PBR2 plan. This flaw would be in the design of the plan or in the plan’s operation. Should it be determined that a flaw existed that resulted in rates that were not just and reasonable, the proceeding would advance to a stage two proceeding to determine the appropriate remedy.
Outcome
After an open and public process, the Commission issued its decision. The Commission found that AED and AGD charged rates that were not just and reasonable in PBR2. The UCA actively participated and successfully provided evidence and testimony that the Commission considered in rendering its decision. The Commission determined that a flaw existed with the PBR2 plan and that the proceeding would need to proceed to a stage two to determine the appropriate remedy. The Commission found that each utility had unquantified savings that led to ROEs that exceeded the review thresholds and rates charged to customers that were not just and reasonable. The Commission also determined that the remedy should only apply to 2021 and 2022 rates, as those were the years in which the review thresholds were exceeded.
The UCA has registered to participate in Proceeding 29064, the stage two review for this proceeding. AED and AGD have also filed an application for a review-and-variance of this decision.
AUC Decision 28369-D01-2024, March 27, 2024
In this proceeding, ATCO Pipelines (AP) filed its General Rate Application (GRA) for its 2024-2026 natural gas transmission rates. AP originally applied for revenue requirements of $358.6 million in 2024, $371.4 million in 2025, and $388.1 million in 2026. Revenue requirements are recovered from customers via transmission rates. AP also applied to capitalize and collect return for construction work in progress for their Yellowhead Mainline Project (Yellowhead Project) and to establish an Identified Growth Account to collect for an increase in capital expenditures related to the Yellowhead Project. The Yellowhead Project will construct 200 KM of gas pipeline west of Edmonton, to connect a portion of AP’s pipeline system to Nova Gas Transmission Ltd.’s (NGTL) system at January Creek to interconnect the two systems.
Outcome
Interveners, including the UCA, entered into a Negotiated Settlement Process (NSP) with AP. From this process, the interveners and AP agreed to terms that reduced AP’s revenue requirement to $353.3 million in 2024, $365.2 million in 2025, and $381.1 million in 2026. This is a total reduction of $18.5 million to be recovered from customers from 2024-2026. The NSP did not result in an agreement on the two issues relating to the Yellowhead Project. These issues were brought to the Commission for testing and a decision.
After an open and public process on the Yellowhead Project issues, the Commission issued its decision. It denied AP the ability to capitalize and collect return for construction work in process. The decision also denied the creation of the Identified Growth Account. The UCA successfully provided evidence and testimony that the Commission considered in its decision. The Commission found in its decision that there was insufficient evidence on the need for AP to collect revenues for those two items.
As part of the agreement reached during negotiations, the period for this GRA will be reduced to 2024 and 2025 only, since the two Yellowhead Project issues were denied by the Commission.
AUC Decision 28831-D01-2024, June 25, 2024
On February 7, 2024, Apex Utilities Inc. (APEX) purchased the gas distribution assets owned by the Village of Boyle (Boyle) for $2.3 million. On February 12th, 2024, APEX filed an application with the Commission requesting approval of the acquisition, a new franchise agreement and the corresponding franchise rate rider schedule that would be applicable to the Village of Boyle customers.
Outcome
The Commission issued its decision on June 25, 2024. The Commission approved APEX’s application, including approval of the franchise agreement and the franchise rate rider schedule. The franchise agreement and the franchise rate rider schedule will apply to gas distribution services provided by APEX within the municipal boundaries of Boyle. However, because of the material rate increase that Boyle customers will experience as a result of the transaction, the Commission directed APEX to implement rate mitigation measures for Boyle customers. The Commission determined that the total bill increase resulting from the transaction is 19.08% and is considered rate shock. Therefore, APEX is only allowed to increase customer’s bills to a maximum of 10% on January 1, 2025, and again on July 1, 2025.
AUC Decision 28457-D01-2024, March 14, 2024, and 28457-D02-2024, June 26, 2024
On September 28, 2023, EPCOR Energy Alberta GP Inc. (EEA), filed an application requesting approval of its non-energy charges, price schedules, miscellaneous fees, a deferral account and regulated rate tariff terms and conditions of service for the 2023-2025 period.
Outcome
EEA had initially requested revenue requirements of $31.72 million in 2023 and $28.56 million in 2024. Revenue requirements are recovered from customers through the rates they charge customers. Interveners and EEA entered into a Negotiated Settlement Process to negotiate the application. The majority of the items were settled between parties during the negotiations except for EEA’s recovery of non-energy credit costs which was an excluded matter to be settled by the Commission. EEA had applied to recover $0.29 million for 2023 and $0.28 million for 2024 in non-energy credit costs associated with providing financial security to the distribution system operators.
The Commission issued its decision on June 26, 2024, which approved the Negotiated Settlement Agreement for 2023-2024 and denied EEA’s application for the non-energy credit costs. The approved revenue requirement reductions as a result of the negotiations with interveners is approximately $1.31 million (4.1%) in 2023 and $1.24 million (3.9%) in 2024.
AUC Decision 28174-D01-2024, February 12, 2024 and 28174-D02-2024, June 19, 2024
On April 28, 2023, AltaLink Management Ltd. (AltaLink), filed its general tariff application for AltaLink, PiikaniLink and KainaiLink for the 2024-2025 period. AltaLink, in its capacity as General Partner of AltaLink Limited Partnership, is also the general partner of PiikaniLink and of KainaiLink. AltaLink initially requested approval of revenue requirements of $887.5 million in 2024 and $904.2 million in 2025. AltaLink recovers the costs of providing electric transmission service through its transmission tariff. As part of the application, AltaLink requested permission to seek a Negotiated Settlement Agreement (NSA) via a negotiated settlement process (NSP) with interveners.
Outcome
On February 12, 2024, the Commission approved the NSA between interveners and AltaLink in Decision 28174-D01-2024, which resulted in a $12 million reduction in revenue requirements (including a $38.5 million reduction in capital expenditures) over the 2024-2025 term, and a cost savings mechanism which will allow consumers and AltaLink to share the savings with customers on a 50:50 basis.
The majority of the issues were settled between interveners and AltaLink during the NSP except for several issues related to salvage and wildfires including a request for a wildfire damages deferral account and other issues which were excluded matters to be settled by the Commission. The Commission issued its decision on June 19, 2024, which approved the NSA for 202-2025 and denied several items related to salvage and wildfires. The Commission denied AltaLink’s request to increase its wildfire mitigation plan expenditures by $49.52 million because it did not fully substantiate the need for the expenditures and the likelihood that AltaLink’s asset deficiencies would cause ignition events triggering wildfires. The Commission denied AltaLink’s application for a deferral account and the $11 million in expenses associated with the Salvage allocation study for 2022 and 2023.
AUC Decision 27084-D02-2023, October 9, 2023
The Alberta Utilities Commission (Commission) is responsible for ensuring utility rates are just and reasonable for consumers while at the same time ensuring that utility companies have a reasonable opportunity to earn a fair return on their investment. Generic cost of capital proceedings set the approved rate of return for equity (ROE) used in setting customer transmission and distribution rates for both electric and natural gas utilities.
The Commission initiated a proceeding for the 2024 Generic Cost of Capital to consider utilizing a formula-based approach cost of capital on a go-forward basis. The formula-based approach is an ROE formula tied to changes in government bond yields and utility credit spreads. This formula-based approach is similar to the approach utilized by the Ontario Energy Board.
Outcome
The Commission issued its decision after an open and public process. The UCA actively participated in this proceeding and successfully provided information and testimony that the Commission considered in rendering key aspects of the decision. The Commission set the deemed equity ratio at 37% and a notional ROE of 9.00%, which is subject to formulaic adjustments using 30-year Government of Canada bond yields and Canadian utility spreads. The formulaic ROE for 2024 is 9.28%. The Commission will allow for reconsideration of the parameters, either at its own initiative or upon application by interested parties, if there are reasons to believe that the ROE resulting from the formula is no longer just and reasonable. The formula will be in place for the next five years, with the first review in 2028 for parameters in 2029 and beyond.
a will be in place for the next five years, with the first review in 2028 for parameters in 2029 and beyond.
AUC Decision 27388-D01-2023, October 4, 2023
The Alberta Utilities Commission (Commission) issued Decision 27388-D01-2023, set the performance-based regulation (PBR) plans for Alberta electricity and natural gas distribution utilities for the term of 2024 to 2028. This is the third generation of PBR (referred to as PBR3) following PBR1 (2013-2017) and PBR2 (2018-2022).
Under PBR, distribution utilities adjust their rates annually, using a mechanistic formula, typically over a five-year term. PBR incents utilities to seek efficiencies in providing distribution services to customers. In general, PBR utilities’ revenues are de-linked from their costs, which promote behaviors that increase productivity and decrease costs. Regulatory efficiency is also gained by decreasing the need for individual, utility specific, rate setting proceedings.
Outcome
The Commission issued its decision after an open and public process. The UCA actively participated in this proceeding and successfully provided information and testimony that the Commission considered in rendering key aspects of the decision. The Commission set the annual adjustment to an Alberta inflation factor less an industry productivity factor of 0.1 percent. An additional 0.3% is also deducted from the inflation factor, in order to further drive efficiencies, with the goal of increasing rates by less than the rate of inflation. The Commission also added an Earnings Sharing Mechanism (ESM) that will direct utilities to share earnings, above certain specific thresholds, with consumers. In addition, there are capital spending
AUC Decision 26509-D01-2022, January 19, 2022
On April 30th, 2021, AltaLink Management Ltd. (AML) filed General Tariff Applications (GTA) for AML, PiikaniLink Limited Partnership, and KainaiLink Limited Partnership. AML’s GTA had initially proposed a revenue requirement of $882.7 million in 2022 and $899.2 million in 2023, which was later updated and revised down to $877.9 million and $895.5 million, respectively. Revenue requirements are recovered from customers through transmission rates. AML had also proposed a refund through transmission rates to customers of $120 million over 2022 and 2023 due to a surplus in depreciation amounts collected previously.
Outcome
The Commission issued its decision on January 19, 2022, after an open and public process. The Commission made a number of reductions to the proposed revenue requirement for operations and maintenance but denied AML’s proposed $120 million refund to customers. While this refund was strongly supported by all interveners, the Commission did not approve the refund on the grounds that refunds of this nature should only be used in exceptional circumstances. The Commission also denied AML’s request to recover $97 million in proposed net salvage costs stating that there was insufficient detail for these costs provided in its Application.
AUC Decision 26844-D01-2021, December 3, 2021
On September 10, 2021, ENMAX Power Corporation (EPC) filed its 2022 Performance-based Regulation (PBR) Rates Adjustment Application with the Alberta Utilities Commission (Commission). In its application, EPC identified a calculation error in its previous transmission access charge deferral account (TACDA) for the years 2015-2019. EPC proposed to correct its error by collecting a net amount of $10.27 million in 2022 from its customers through a rate rider.
Outcome
On December 3, 2021, after an open and public process, the Commission denied the use of the deferral account to correct historical and previously approved amounts. As a result, $10.27 million will not be recovered from EPC’s customers.
AUC Decision 26589-D01-2021, November 24, 2021
On June 17, 2021, ENMAX Power Corporation (EPC) filed its Type 1 Capital Tracker Treatment Application to recover costs associated with infrastructure relocation and connection costs incurred due to the City of Calgary’s (Calgary) Green Line expansion of their light rail transit (LRT) service. Type 1 capital costs are defined by the Alberta Utility Commissions (Commission) as extraordinary and required by a third party. In step with Decision 20414-D01-2016, the Commission granted a placeholder funding mechanism for EPC to alleviate cash flow concerns with the understanding that EPC risks a cost disallowance should the expenditure later be deemed not eligible for this additional capital funding.
Outcome
On November 24, 2021, after an open and public process, the Commission denied EPC’s application, stating it did not meet the criteria for a Type 1 capital expenditure and did not agree with EPC that the Green Line expansion was an out of the ordinary cost with respect to its usual operations. In addition, the Commission did not find enough institutional separation between the City of Calgary and EPC to be considered a third-party request. The Commission ordered EPC to refund the amounts collected through the placeholder-funding mechanism back to consumers. The refund to consumers is $5.37 million in addition to the disallowance of $25.18 million in rate base additions.
AUC Decision 26356-D01-2021, June 30, 2021
On March 1, 2021, the Alberta Utilities Commission (Commission) initiated Proceeding 26356 with the purpose of evaluating previous performance-based regulation (PBR) plans for Alberta’s electric and gas distribution utilities.
Outcome
On June 30, 2021, after an open and public process, the Commission determined that there will be a third term of PBR in Alberta after a cost of service (COS) year in 2023 to set going-in rates. The Commission made this determination after evaluating the previous two PBR terms against its five key principles: utility operational efficiency, the utilities’ ability to receive a fair return, the level of clarity of the PBR plan in its direction and application, the PBR plan’s ability to recognize the uniqueness of each utility, and the equity of the plan in sharing its benefits between utilities and consumers. The Commission found that on most of these principles PBR was successful.
AUC Decision 26090-D01-2021, June 7, 2021
On November 17, 2020, the Alberta Utilities Commission (Commission) initiated Proceeding 26090 to discuss the future of Distributed Connected Generation (DCG) credits and their impact on utility distribution tariffs. The role of DCG credits was examined in light of rising transmission tariffs over the past decade. DCG Credits are paid by utilities to generators connected to distribution systems, who either self supply electricity to meet their own needs or export electricity. The amount provided in DCG credits is recovered from all customers of the distribution utility that provides the credits.
Outcome
On June 7, 2021, after an open and public process, the Commission did not agree with the arguments put forth by DCG operators that DCG credits provide value or quantifiable benefits to ratepayers. The Commission ordered that effective January 1, 2022, DCG credits would begin to phase out through 20% reductions in annual DCG credits and complete removal of all credits by January 1, 2026.