Rates – General Tariff Application – Capitalization – Utility Asset Disposition Decision
In this decision, the AUC set out its determinations regarding ENMAX Power Corporation’s (“EPC”) application for approval of a negotiated settlement agreement (“NSA”) regarding its 2018-2020 general tariff application (“GTA”) and the six issues excluded from the NSA.
The AUC accepted EPC’s NSA. Of the six issues excluded from the NSA, the AUC denied EPC’s proposed new flow-through deferral account and Remington Project deferral account and changes to its existing major storms and natural disasters deferral account. The AUC affirmed its earlier ruling that all matters regarding Substation No. 1 are to be removed from the revenue requirement for this GTA. The AUC did not approve EPC’s proposed treatment for capital leases but upheld its proposed treatment of intercompany interest revenue. Finally, the AUC provided guidance with respect to the application of EPC’s capitalization policy through its accounting practices and confirmed that only assets that are used and required to be used are to be capitalized into rate base.
Background
On December 12, 2018, EPC filed an application with the AUC for approval of its 2018-2020 GTA for the period of January 1, 2018, to December 31, 2020. It sought approval for, among other things, a 2018 revenue requirement of $85.68 million; a 2019 revenue requirement of $95.67 million; and a 2020 revenue requirement of $106.36 million.
It reached an NSA that encompassed all aspects of EPC’s 2018-2020 GTA with the exception of Excluded Matters that are discussed further below.
Statutory and AUC Requirements for a Negotiated Settlement
The Electric Utilities Act authorizes the AUC to establish rules in respect of negotiated settlements, including settlements dealing with rate-related matters. The AUC has established rules for negotiated settlements in Rule 018: Rules on Negotiated Settlements.
The AUC noted that the NSA resulted in reductions to EPC’s applied-for GTA revenue requirement totalling $7.80 million. The AUC also noted that the parties to the NSA agreed to the following additional process items:
(a) In future transmission business cases filed with the AUC, EPC will separate “arc flash” projects from “life cycle replacement” projects;
(b) EPC committed to examining possible distribution solutions to assess whether they are more cost-effective, including non-wires alternatives (such as storage and distributed generation), prior to proposing transmission projects that are primarily driven by distribution considerations;
(c) EPC will hold a technical meeting, with Parties and AUC staff invited to participate, on its proposed Substation No. 1, including a presentation on the Substation No. 1 Redevelopment Project with an examination of the alternatives considered and representation from both EPC distribution and EPC transmission. Minutes of the technical meeting would constitute part of the public record; and
(d) The Parties agreed to propose to the AUC that it allow an additional round of information requests for Proceeding 23966 on the Excluded Matters, to a maximum of 40 questions between the Utilities Consumer Advocate (“UCA”) and Consumers’ Coalition of Alberta (“CCA”) to be completed in conjunction with any information requests from the AUC on the NSA. Parties would make their submissions to the AUC on any additional process steps for dealing with the Excluded Matters.
Based on the AUC’s assessment of provisions of the NSA, along with the detailed analysis of the application and IR responses, the AUC found that the NSA, taken as a whole, was not patently against the public interest or contrary to law and should result in rates and terms and conditions that are just and reasonable, as required by Section 8 of Rule 018. Accordingly, the AUC approved the NSA as filed.
Excluded Matters
Major Storms and Natural Disasters Deferral Account
The AUC previously approved the major storms and natural disasters (“MSND”) deferral account in Decision 2014-347. In this application, EPC proposed to modify the scope and language of the deferral account by including the phrase “and revenues lost” after “Costs caused,” and replacing the word “significant” with the word “material.” The applied-for changes to the description for the MSND deferral account result in the following description:
Costs caused, and revenues lost, by major storms or natural disasters that occur in 2018 through 2020 for Transmission that cause material damage to EPC’s infrastructure (net of amounts recovered through insurance or government relief).
The AUC denied EPC’s requested changes to the scope and language of its MSND deferral account. The AUC noted that Section 4.1 of EPC’s AUC-approved terms and conditions, which are generic to all Alberta transmission facility owners (“TFOs”), requires the ISO to pay to the TFO the amounts invoiced by the TFO “… notwithstanding any interruption or curtailment of the TFO’s Transmission Services for any reason whatsoever, including an event of Force Majeure.” The plain meaning of that section suggests that it is intended to ensure that a TFO is kept whole should events occur that could result in interruption or curtailment of service by the TFO to its customers.
The AUC also noted that EPC provided no explanation or rationale for the inclusion of lost revenues in the MSND deferral account in its application. The AUC found that EPC did not establish that it is at incremental risk for lost revenue due to an MSND event and provided insufficient support both in terms of the need for and the operation of the inclusion of lost revenues in the MSND deferral account.
Flow-through Deferral Account
EPC proposed a new flow-through deferral account, with the following description:
Costs, or revenues lost, related to amendments to the Electric Utilities Act, or the regulations thereunder, or arising from AUC approved tariffs for the Test Period for EPC or other industry participants.
EPC explained that the flow-through deferral account was intended to cover two areas:
(a) costs, or lost revenues, relating to transmission resulting from amendments to the Electric Utilities Act and the regulations thereunder; and
(b) Transmission-related costs, or lost revenues, that arise as a consequence of AUC-approved tariffs for the Test Period for any other industry participant, including the AESO, that have a financial impact on EPC.
The AUC was not persuaded of the merits of establishing the flow-through deferral account. It noted that EPC has accepted this risk in the past; that EPC had not shown that such costs and revenues represent a significant portion of EPC’s total revenue requirement or a materiality of risk; and that to the extent that a three-year Test Period increased the risk that legislative amendments will materially impact EPC, the AUC considered that the choice of a three-year Test Period for this application was under the control of EPC. It also noted that it had discontinued ATCO Electric’s use of a deferral account for legislative change in Decision 2013-358.
Remington Project Deferral Account
EPC proposed a new deferral account, the Remington Project deferral account. As explained by EPC, transmission lines 2.82L and 2.83L cross Remington Development Corporation lands. These lines and:
… associated assets were located on lands governed by a right of way (“ROW”) agreement between the City and Canadian Pacific Railway. EPC acquired the transmission lines when it was created by the City. The ROW agreements were assigned to Remington when it purchased the land from Canadian Pacific Railway. Remington subsequently terminated the ROW agreement and requested that EPC’s assets be removed from Remington’s land.
EPC submitted that the purpose of the deferral account is to recover actual costs related to the Remington Project. These costs would include cancelled project costs, dispute resolution costs, and costs for applications before the court, the AUC, and the Surface Rights Board.
EPC added that in Decision 22089-D01-2018, the AUC determined that the prudence of expenditures related to the Remington Project should be considered after issues associated with the Remington Project have been resolved. EPC clarified that it was proposing a deferral account so that, consistent with the AUC’s finding in Decision 22089-D01-2018, the prudency of the Remington Project costs could be tested at a later date.
The AUC again noted that the prudence of the Remington Project expenditures would be considered after the Remington relocation issue has been resolved. It further noted that a deferral account is not required for this prudency assessment to occur at a later date. EPC’s request for a deferral account for Remington Project costs was denied.
Substation No. 1 Redevelopment Project
EPC is the owner of Substation No. 1, which is located in downtown Calgary. Substation No. 1 was built in 1912, is currently the oldest substation in EPC’s system, and supplies the largest portion of the downtown secondary network in Calgary.
In the application, EPC stated that Substation No. 1 needs to be replaced as major equipment is ageing and nearing its end of life. EPC also identified that Substation No. 1 is becoming more difficult to maintain, proving it to be unreliable and is a safety risk to the public and EPC personnel. EPC explained that if Substation No. 1 is not redeveloped, then equipment failure will create the need for high-cost reactive replacement or repair, thereby disrupting power supply to downtown Calgary.
In its business case, EPC identified three alternatives for the redevelopment of Substation No. 1: (i) do nothing; (ii) rebuild the substation on the current site (the rebuild option); and (iii) build a replacement Substation No. 1 at an alternative site within the vicinity of the current site (the replacement option). EPC prefers the replacement option. A business case for the project was provided in EPC’s application.
The AUC noted that on July 15, 2019, it directed EPC to establish a deferral account for the Substation No. 1 project. It noted that expenditures related to this project would eventually be reflected as actual costs in a future GTA, and that establishing a deferral account would allow testing of the prudency of actual costs in that proceeding. The AUC further noted that on December 18, 2019, EPC filed a facility application for permits and licences to construct and operate a new Substation No. 1 on an alternative site, to alter six transmission lines, and to decommission the existing Substation No. 1 on the current site. The facilities application is currently being considered in Proceeding 25206 (“Facilities Proceeding”).
On January 31, 2020, in response to a request from the UCA to file evidence on the Substation No. 1 project on the record of the current rates proceeding, the AUC held that any concerns with the AUC approving EPC’s forecast costs associated with the rebuild option or the proposed replacement option (collectively, the Substation No. 1 issue) could be addressed within the Facilities Proceeding, and that any rate implications related to the Substation No. 1 redevelopment project could be addressed in a future rate proceeding when actual costs for the project become available and when EPC requests that prudently incurred costs be included in rate base.
The AUC reiterated its finding that no forecast capital expenditures or capital additions related to the Substation No. 1 project are to be included in EPC’s 2018-2020 application and attendant schedules. It directed EPC to revise its minimum filing requirement schedules and construction work in progress continuity schedules showing the exclusion of 2018-2020 forecast capital expenditures of $65.62 million and the exclusion of forecast capital additions of $40.0 million, with respect to land purchased for the Substation No. 1 replacement option, in its compliance filing to this decision.
The AUC directed EPC to seek approval for the costs associated with the Substation No. 1 project, and to file a business case in support of that project, in a future GTA, after a decision has been rendered in the Facilities Proceeding.
IFRS 16 Capitalized Leases
In its application, EPC explained that the international financial reporting standards (“IFRS”) 16 standard for leases came into effect January 1, 2019, and that EPC is required to comply with IFRS. EPC requested the implementation of the IFRS 16 standard in this GTA which would result in office and vehicle lease costs, with terms longer than one year being treated and classified as a capital lease, rather than as an operating expense. EPC identified that it has eight vehicle leases and one office lease that are affected by IFRS. EPC included the IFRS standard changes in its application that result in lease expenses previously included in operations and maintenance, now being included in rate base and, as a result, are included in depreciation expense and return.
The AUC noted that under Section 101(2) of the Public Utilities Act, EPC had to seek the approval of the AUC to capitalize any of its leases. It further noted that under Rule 026: Regulatory Accounting Procedures Pertaining to the Implementation of the IFRS, utilities shall maintain the existing accounting practice regarding the treatment of deemed finance leases.
Pursuant to Rule 026, future regulatory accounting and regulatory reporting requirements established by the AUC will be aligned as much as possible with IFRS. However, the AUC noted that Rule 026 also establishes that IFRS requirements will not be the sole driver of regulatory requirements. The methodologies used by the AUC to establish just and reasonable rates have not always been the same as those used for external financial reporting purposes.
The AUC considered that the requirement for EPC to adopt IFRS 16, in and of itself, was insufficient in the circumstances to justify a change in accounting treatment of leases for regulatory reporting purposes. In addition, the AUC found that EPC did not adequately explain why the change to IFRS 16, which results in a higher annual revenue requirement, is in the public interest, particularly given that IFRS 16 does not affect the amount it pays to its lessor.
The AUC also disagreed with EPC’s assertion that there is no reasonable justification for different treatment between utilities who purchase and lease assets.
Based on the foregoing, the AUC denied EPC’s request to adopt IFRS 16 (leases) for regulatory purposes. In its compliance filing, EPC was directed to continue to use its previously approved methodology for reporting leases (as O&M costs) and to revise its lease forecast costs such that the amount of revenue requirement to be collected from customers by EPC does not vary from the annual payment amount EPC pays to its lessor.
Intercompany Interest Revenue
EPC applied to discontinue its prior practice of including intercompany interest revenue as part of its revenue offset. EPC stated that its previous inclusion of intercompany interest revenue, in its revenue offset, was in error. In prior applications, EPC treated the interest income earned under its cash concentration system as a revenue offset. In reaching the revenue offset amount, EPC did not include any of the related and offsetting intercompany interest expense.
The AUC noted that the intercompany interest revenue earned as a result of internal cash management policies and procedures (EPC’s cash concentration system) was not in pursuit of performing transmission utility service. Therefore, the AUC agreed with EPC’s view that ratepayers are not entitled to benefit from the proceeds of intercompany interest nor should they bear the correlating expense (if any). The AUC approved EPC’s request to discontinue its prior practice of including intercompany interest revenue as part of its revenue offset.
Sections 4.2 and 4.3 of EPC’s Capitalization Policy
EPC’s Fixed and Intangible Asset Capitalization Standard (“Capitalization Policy”) and attendant accounting treatment were examined during this proceeding, both before and after the establishment of a negotiated settlement process.
Prior to the NSP, the CCA questioned why EPC had proposed to capitalize an anticipated land purchase required for its Substation No. 1 capital project given that the project, as a whole, was not forecast to be completed or in service during the Test Period. EPC responded that because the land would be used to provide services for the redevelopment of the Substation No. 1 project, it was appropriate for the $40 million forecast land cost to be capitalized and included in rate base in 2020, the year of purchase.
The UCA questioned whether the criteria under which EPC adds assets to rate base was “when the asset is complete, connected to the system, and energized, or at some earlier time.” EPC responded that the requirement for an asset to be added to rate base was when the asset becomes “presently used, reasonably used or likely to be used in the future.” EPC indicated that the timing of capitalization was irrespective of whether energization or connection to the transmission system had occurred. Specifically, EPC noted the example of duct banks as being an instance where EPC “capitalizes civil assets that are considered complete and connected to the system that do not contain energized cable, as energization is not applicable at the time …”
The AUC rejected the claim of EPC’s experts that under Rule 026, International Accounting Standards (“IAS”) 16, Property, Plant and Equipment is recognized as an asset if there is a probability of future economic benefits as binding on the AUC’s determination of rate base for regulatory purposes. As noted in Rule 026, Appendix 1, “The guiding principles … will be used when considering any proposed changes to the existing provisions of this rule or when developing and establishing any new provisions to this rule.” The AUC considered that Rule 026 and IAS 16 could only provide guidance to the AUC in certain circumstances.
The AUC also rejected arguments regarding paragraph 327 of the Utility Asset Disposition Decision (“UAD Decision”) as constituting evidence that the requirement for when assets should be removed from rate base, should apply equally to when an asset should be included in rate base. The AUC disagreed that the UAD Decision was intended to either replace or complement the capitalization policies and practices of Alberta utilities as a standard by which assets would be added to rate base for regulatory purposes.
In the UAD decision, the AUC discussed the requirement for all Alberta gas and electric utilities that assets be used or required to be used to provide service to the public in an operational sense. In that decision, the AUC held that “used or required to be used” means “presently used, reasonably used or likely to be used in the future.” If and when a capital expenditure becomes “used or required to be used” is a factual determination, which the AUC makes based on the evidence before it.
The AUC was not satisfied by EPC’s explanations that the land for Substation No. 1 Redevelopment Project, the land for Substation No. 45 – New Quarry Park Project, or the civil work related to duct banks required in EPC’s direct assigned Downtown Calgary Transmission Reinforcement Project, are used or required to be used.
The AUC noted that there was no evidence in the current proceeding that points to a long-term or systemic issue with EPC’s capitalization policy or practices that would otherwise lead the AUC to question EPC’s 2018 opening rate base amounts. The AUC directed that commencing with 2018, EPC is to capitalize to rate base only assets that are “used or required to be used.” The AUC noted that it expects EPC to interpret and apply this direction consistent with the findings provided in this decision with respect to the land and duct bank examples. EPC was further directed to effect and confirm its compliance with this direction in its compliance filing to this decision. Further, the AUC held that this direction applies to the projects at issue identified in this decision, and to any similar work or capital project of which EPC is aware in the current and any future proceedings.
