Decision D Rebasing for the PBR Plans for Alberta Electric and Gas Distribution Utilities. First Compliance Proceeding

Transcription

1 Decision D Rebasing for the PBR Plans for February 5, 2018

2 Alberta Utilities Commission Decision D Rebasing for the PBR Plans for Proceeding February 5, 2018 Published by the: Alberta Utilities Commission Fifth Avenue Place, Fourth Floor, 425 First Street S.W. Calgary, Alberta T2P 3L8 Telephone: Fax: Website:

3 Contents 1 Decision summary Introduction and procedural summary Background Overview of the approved PBR plans Rebasing process to set the going-in rates for the PBR plans Proposed anomaly adjustments Methodology for identifying the lowest-cost year for O&M expenditures Characteristics of permitted O&M anomalies Distribution-utility proposed O&M anomalies Specific labour cost adjustments proposed by AltaGas and ENMAX Labour cost escalation adjustments proposed by AltaGas, ENMAX, EPCOR and Fortis The ATCO Utilities and Fortis I factor and Q anomalies EPCOR s AMI anomaly Other O&M-related adjustments ENMAX bad debt anomaly ENMAX legislative requirements adjustments EPCOR Master overhead pool allocation and OMS/DMS maintenance and support anomalies Adjustments proposed by the interveners ENMAX s retirements K-bar incremental capital funding Decision D (Errata) on K-bar Incremental K-bar funding based on historical average capital additions Alternative approaches to calculating K-bar Annual K-bar calculation Process to calculate the K-bar amount for each year of the PBR term Inclusion of Q in the second component of the K-bar accounting test Parameters included in the K-bar calculation Filing dates for, and schedules in support of, the annual K-bar calculations Conclusion on K-bar Other issues pertaining to rebasing applications Common issue service quality and asset monitoring Common issue 2017 cost of debt Income tax implications for tax-paying utilities Y factor treatment for income tax Method to estimate the interim income tax amounts Fortis AltaGas The ATCO Utilities Issues specific to the ATCO Utilities Placeholder treatment for certain costs Decision D (February 5, 2018) i

4 6.4.2 Facility Charge Agreements (Rider E) Issues specific to EPCOR Calculation of the embedded cost of debt Changes in accounting treatment of certain costs Four-year average assumption for retirements and contributions in aid of construction Undepreciated capital investment in conventional meters Issues specific to Fortis Adjustment to reflect actual depreciation costs Finalization of AESO contributions Second rebasing compliance filings, going-in rates, and 2018 PBR rates Conclusion Order Appendix 1 Proceeding participants Appendix 2 Oral hearing registered appearances Appendix 3 Summary of Commission directions List of tables Table 1. O&M anomalies proposed by the distribution utilities Table 2. Fortis approved Q and proposed 2017 Q value Table 3. Approved I factor versus calendar year I factor Table 4. Table 5. Table 6. Approved forecast versus actual change in the average number of customers for ATCO Electric Approved forecast versus actual change in the average number of customers for Fortis Summary of incremental capital funding under the traditional rate base rate of return revenue requirement calculations and K-bar calculations Table 7. Summary of K-bar scenarios using different I factor and Q values in the 2018 base K-bar calculation Table 8. Calculation of O&M impact for EPCOR accounting treatment changes ii Decision D (February 5, 2018)

5 Alberta Utilities Commission Calgary, Alberta Rebasing for the PBR Plans for Decision D Proceeding Decision summary 1. This decision provides the Alberta Utilities Commission s determinations concerning the notional 2017 revenue requirement and 2018 base K-bar amount to be used for rebasing purposes, as a basis for setting the going-in rates in a subsequent compliance proceeding for the performance-based regulation (PBR) plans for Alberta electric and gas distribution utilities. It also addresses the operation of the K-bar mechanism during the PBR term. The specific utilities are AltaGas Utilities Inc., ATCO Electric Ltd. (distribution), ATCO Gas and Pipelines Ltd. (distribution), ENMAX Power Corporation (distribution), EPCOR Distribution & Transmission Inc. (distribution) and FortisAlberta Inc., collectively referred to as the distribution utilities. For the reasons outlined in this decision, the Commission directs each of the above distribution utilities to file a second compliance filing by March 1, In addition to addressing the directions set out in this decision, each distribution utility should apply for 2018 PBR rates in its second compliance filing. 2. This decision considers the compliance filings submitted by the distribution utilities pursuant to the Commission directions set out in Decision D (Errata), 1 which decision established the overall framework for the PBR plans. In this compliance proceeding, the new evidence and submissions of parties on matters not fully reviewed in the prior decision have assisted the Commission in its determination of the going-in rates and K-bar incremental capital funding. The record of this proceeding has also assisted the Commission and parties in understanding the interrelationship among the various components of the PBR plans. This evolution in understanding has led to certain mechanical refinements, discussed below, that the Commission considers better reflect its intentions in Decision D (Errata). 3. This decision is organized as follows: an introduction and procedural summary are provided in Section 2. Section 3 provides an overview of the approved PBR plans and summarizes Commission determinations on rebasing in Decision D (Errata). 4. In Section 4, the Commission denies the applied-for anomalies. 5. The calculation of the K-bar incremental capital funding is addressed in Section 5. As set out in that section, the Commission determines that refinements to the mechanics for calculating the 2018 base K-bar and the annual K-bar escalation formula set out at paragraph 255 of Decision D (Errata) are necessary. Specifically, the Commission determines that for 2018, base K-bar shall be calculated as set out at paragraph 254 of Decision D Decision D (Errata): Performance-Based Regulation Plans for Alberta Electric and Gas Distribution Utilities, Proceeding 20414, February 6, 2017, amending the decision issued December 16, Decision D (February 5, 2018) 1

6 (Errata), and clarified in the Commission s letter of February 6, 2017, 2 with one modification regarding the inclusion of the Q parameter in the second component of the K-bar accounting test. In each of 2019 through 2022, the K-bar amount should be calculated by way of an annual parameter adjustment to reflect the I factor, Q and weighted average cost of capital (WACC) approved for that year. 6. Section 6 addresses other issues pertaining to the distribution utilities rebasing applications, including utility-specific issues. The Commission directions on calculating the notional 2017 revenue requirement and base K-bar amount, as well as compliance filings for calculating the going-in rates and the resulting 2018 PBR rates are set out in Section 7. The Commission s conclusions on the rebasing applications are set out in Section 8. 2 Introduction and procedural summary 7. In Decision D (Errata), the Commission established the parameters to be included in the PBR plans for the distribution utilities. An overview of the PBR plans is provided in Section In Decision D (Errata), the Commission also directed each of the distribution utilities to file a compliance filing by way of a rebasing application in accordance with the directions set out in that decision, by March 31, In January 2017, the distribution utilities and the intervener groups, by way of postdisposition filings in Proceeding 20414, sought further clarity on the forthcoming rebasing schedules template and on various other issues related to the rebasing proceeding By letter dated February 6, 2017, the Commission provided parties with a rebasing schedules template and responses to the parties clarification questions to assist the distribution utilities in preparing their first rebasing compliance applications. The Commission indicated that modifications to the Commission s template, consistent with Decision D (Errata), could be proposed and examined in the first compliance proceeding The Commission also established the present Proceeding for the purpose of processing the six rebasing compliance filing applications and pre-registered the six distribution utilities as participants in the proceeding. Intervener parties that actively intervened in Proceeding 20414, The City of Calgary, the Consumers Coalition of Alberta (CCA) and the Office of the Utilities Consumer Advocate (UCA), were also registered in the proceeding. 2 Exhibit X0002, AUC letter, Rebasing schedules template and responses to parties' clarification questions, February 6, Distribution utilities letter regarding Compliance Clarification to Decision D , uploaded on January 20, 2017, by ATCO Electric; CCA correspondence January 24, 2017, uploaded on January 25, 2017; CCA correspondence January 30, 2017, uploaded on January 30, 2017; the UCA comments Proceeding 20414, uploaded on January 30, 2017; Calgary letter re Clarification Matters, uploaded on January 31, Exhibit X0002, AUC letter, Rebasing schedules template and responses to parties clarification questions, February 6, 2017, paragraph Decision D (February 5, 2018)

7 12. In correspondence dated March 20, 2017, the Commission granted the distribution utilities request for an extension to April 21, 2017, to file their respective compliance filing rebasing applications. 5 On April 21, 2017, the applications were filed. 13. On April 24, 2017, the Commission issued a notice of application and indicated that parties, other than those already registered in the proceeding, could register to participate in the proceeding by filing a statement of intent to participate (SIP) in the Commission s electronic filing system by May 4, No additional SIPs were received. Based on the initial review of the applications, the Commission established the schedule for this proceeding in accordance with a full process as set out in Bulletin In Decision D (Errata), the Commission established deadlines of July 1, 2017 and September 10, 2017 for supplemental filings to the rebasing applications to update placeholder values and to apply for 2018 interim rates. 7 However, in light of the actual filing date of the applications and the expected schedule for this proceeding, in its letter dated May 8, 2017, the Commission modified the expected dates for these submissions as further described below With respect to the July 1, 2017 update, the Commission determined that the distribution utilities should file these updates as part of their rebuttal evidence, along with accompanying explanations to address any material variances between the numbers filed in the original applications and the updated actuals, as noted in the Commission s letter of April 17, The Commission also removed from the current proceeding the requirement to file on or before September 10, 2017 a further placeholder update and the 2018 rate-calculation component. The Commission indicated that the scope of this proceeding would be limited to establishing the notional 2017 revenue requirement and base K-bar amount for each of the distribution utilities that will be used to establish going-in rates for the PBR term. The Commission also indicated in that letter that upon release of the decision for this proceeding, each distribution utility will be required to submit a separate application to calculate the 2018 PBR rates. 16. The Commission further noted that, if required, it would establish the January 1, 2018 PBR rates on an interim basis until the 2018 rates applications are processed. The Commission did so in its letter dated October 12, 2017, where it indicated that effective January 1, 2018, each of the utilities will continue with their approved 2017 PBR rates on an interim basis until and unless otherwise approved by the Commission On July 28, 2017, the Commission expanded the scope of this proceeding to include a more detailed review of how K-bar is to be implemented and, subsequently, adjusted, including an examination of the base K-bar accounting test, the parameters used in carrying out the accounting test, and the mechanics of the annual adjustment formula. In expanding the scope of the proceeding, the Commission noted: The interaction of the base K-bar accounting test with the annual K-bar adjustment formula, and the resulting effects on the available capital funding 5 Exhibit X0010, AUC letter, Rebasing application extension and registered parties to Proceeding 22394, March 20, Bulletin , Performance standards for processing rate-related applications, March 26, Decision D (Errata), paragraph Exhibit X0050, AUC letter, Process and schedule, May 8, Exhibit X0013, paragraph Exhibit X398, AUC letter, January 1, 2018 interim PBR rates, October 12, 2017, paragraph 3. Decision D (February 5, 2018) 3

8 and intended incentives, have not been anticipated or fully considered by parties and the Commission in Proceeding or in this proceeding as it has unfolded thus far. The Commission invited all parties to file supplemental evidence and supplemental reply evidence on these issues. The Commission also indicated that this further consideration of K-bar implementation and calculation mechanics might result in changes to the base K-bar accounting test and annual K-bar adjustment mechanism directed in Decision D (Errata) and the Commission s clarifications provided in its letter of February 6, The main process steps, as amended throughout the course of the proceeding, are set out in the table below: Process step Due date Rebasing applications filed April 21, 2017 Information requests (IRs) to distribution utilities May 29, 2017 IR responses from distribution utilities June 12, 2017 Intervener evidence July 7, 2017 IRs to interveners July 20, 2017 IR responses from interveners August 2, 2017 Rebuttal evidence and application update for Rule data and 2016 applied-for actual capital tracker amounts August 16, 2017 Supplemental evidence on the base K-bar accounting test and annual K-bar adjustment from all parties August 21, 2017 Supplemental reply evidence on the base K-bar accounting test and annual K-bar adjustment from all parties August 30, 2017 Oral hearing September 12 to 29, 2017 Answers to undertakings and submission of outstanding aids to cross September 28, 2017 IRs on answers to undertakings October 3, 2017 Responses to IRs on answers to undertakings October 6, 2017 Argument October 16, 2017 Reply argument November 7, On November 9, 2017, the Commission received a request from EPCOR for leave 12 to file sur-reply argument in this proceeding, in response to certain submissions contained in the reply arguments of the UCA and the CCA. EPCOR appended a copy of the sur-reply argument to its request. The Commission provided parties with an opportunity to respond to the request, and submissions were received from the UCA and the CCA on November 14 and 15, 2017, respectively. The Commission issued a ruling on November 27, 2017, denying EPCOR s request Rule 005: Annual Reporting Requirements of Financial and Operational Results. 12 Exhibit X0420, EPCOR request for limited sur-reply to UCA and CCA, November 9, Exhibit X0424, AUC letter, EPCOR request for sur-reply argument, November 27, Decision D (February 5, 2018)

9 20. In correspondence dated December 8, 2017, 14 the Commission confirmed it considers that the record development phase for the purposes of calculating its performance standards under Bulletin concluded with the filing of reply arguments on November 7, However, in light of the additional process steps associated with EPCOR s request, the Commission indicated it would extend the deadline for any intervener cost claim. 21. In reaching the determinations set out within this decision, the Commission has considered all relevant materials comprising the record of this proceeding and Proceeding Accordingly, reference in this decision to specific parts of the records for these proceedings are intended to assist the reader in understanding the Commission s reasoning relating to a particular matter and should not be taken as an indication that the Commission did not consider all relevant portions of these records with respect to a particular matter. 3 Background 3.1 Overview of the approved PBR plans 22. In Decision D (Errata), the Commission set out the parameters of the PBR plans for the six distribution utilities. There are two gas distribution utilities, AltaGas and ATCO Gas, and four electric distribution utilities, ATCO Electric, ENMAX, EPCOR and Fortis. Many parameters of this PBR framework are the same or similar to the parameters of the prior generation of PBR plans adopted by the Commission in Decision for AltaGas, ATCO Gas, ATCO Electric, EPCOR and Fortis for the years and in Decision D (Errata) 16 for ENMAX for the years The PBR framework approved in Decision provided a rate-setting mechanism (price cap for electric distribution utilities and revenue-per-customer cap for gas distribution utilities) based on a formula that adjusted rates annually by means of an indexing mechanism that tracks the rate of inflation (I) that is relevant to the prices of inputs the utilities use, less a productivity offset (X). With the exception of specifically approved adjustments, as discussed further below, a utility s revenues were not linked to its costs during the PBR term in order to provide the utility with the flexibility to manage its business in an environment that fosters incentives to seek out and realize process, operational, capital and financial efficiencies, so as to reduce costs while maintaining existing service levels. Additionally, the Commission approved certain rate adjustments to enable the recovery of specific costs where certain criteria have been satisfied that demonstrate that these costs cannot be managed under the I-X mechanism. These adjustments include an adjustment for certain flow-through costs that should be recovered from, or refunded to, customers directly (a Y factor), and an adjustment to account for the effect of exogenous and material events for which the distribution utility has no other reasonable cost recovery or refund mechanism within the PBR plan (a Z factor). The Commission also adopted a capital tracker mechanism to fund certain capital-related costs that the utility was able to demonstrate could not be funded under the I-X mechanism. Approved capital tracker amounts 14 Exhibit X0426, AUC letter, close of record, December 8, Decision : Rate Regulation Initiative, Distribution Performance-Based Regulation, Proceeding 566, Application , September 12, Decision D (Errata): ENMAX Power Corporation, Distribution Performance-Based Regulation Negotiated Settlement Application and Interim X Factor, Proceeding 21149, October 3, 2016, amending the decision issued August 3, Decision D (February 5, 2018) 5

10 were collected through an annual K factor. Costs under the capital tracker programs were not subject to the same incentives as costs under the I-X mechanism because expenditures afforded capital tracker treatment were largely recovered on a cost-of-service basis. 24. Decision D (Errata) dealt with four main PBR plan parameters: (i) rebasing and the going-in rates for the next generation PBR term, (ii) the X factor, (iii) the treatment of capital additions, and (iv) the calculation of the return on equity (ROE) for reopener purposes. 25. As explained in Decision D (Errata), rebasing refers to the exercise of generally realigning revenues and costs in anticipation of, or at the end of, a PBR plan term, in order to establish new going-in rates for the next generation PBR plan. 17 As further summarized in Section 3.2, to minimize the distorting influence of the incentives that arise during the last year of a PBR term, in Decision D (Errata), the Commission decided to set the going-in rates for the PBR plans on the basis of a notional 2017 revenue requirement that is calculated using the actual pre-2017 costs, adjusted as required for anomalies In establishing the PBR plans for the distribution utilities in Decision D (Errata), the Commission kept the same methodology for the I factor as used in the PBR plans, where it is calculated as a weighted average of two inflation indexes. 19 The Commission set the X factor to be 0.3 per cent for the term, based on updated industry total factor productivity growth studies and inclusive of a stretch factor. 20 Additionally, the Commission approved the continuation of the Y factor and Z factor rate-adjustment mechanisms for the PBR term. 27. As was the case in previous generation PBR plans, in Decision D (Errata), the Commission determined that a supplemental capital funding mechanism, in addition to revenue provided under I-X, is required for the PBR plans. However, in place of the capital tracker mechanism employed in previous-generation PBR plans, the Commission adopted a capital funding model that it determined would provide the necessary incremental capital funding while significantly enhancing the incentives for the distribution utilities to plan, design and construct capital assets efficiently. Specifically, the Commission determined that incremental capital funding will be divided into two categories: Type 1 and Type 2 capital. For Type 1 capital, the Commission approved a modified capital tracker mechanism with narrow eligibility criteria, with the revenue requirement associated with approved amounts to be collected from ratepayers by way of a K factor adjustment to the annual PBR rate setting formula. For Type 2 capital, the Commission approved a K-bar mechanism that provides an amount of capital funding for each year of the next generation PBR plans based, in part, on capital additions made during the previous PBR term. 21 The revenue requirement associated with approved amounts for Type 2 programs will be collected from ratepayers by way of a K-bar factor adjustment to the annual PBR rate-setting formula. 17 Decision D (Errata), paragraph Decision D (Errata), paragraph Decision D (Errata), Appendix 5, Section 2, pages Decision D (Errata), paragraph Decision D (Errata), sections (Type 1) and (K-bar). 6 Decision D (February 5, 2018)

11 28. The Commission stated that this approach to incremental capital funding will reduce the regulatory burden associated with multiple capital tracker proceedings, provides greater certainty with respect to capital funding, thereby expanding PBR incentives to the vast majority of overall costs and allowing the PBR plan to recognize the unique circumstances of each distribution utility. 22 The determination of the annual K-bar amount for each distribution utility is considered in Section 5 of this decision. 29. Lastly, with regard to a reopener provision, which is an ROE-based mechanism to identify, assess and potentially address design or operational problems in PBR plans, the Commission stated in Decision D (Errata) that it will continue to employ the +/- 500 basis point threshold in a single year and the +/- 300 basis point thresholds for two consecutive years, relative to the allowed ROE, as warranting consideration of a reopening and review of the PBR plan. The Commission will utilize an allowed ROE for a given year, as determined by the Commission in a generic cost of capital (GCOC) proceeding, as the base ROE against which to calculate the +/- 300 or +/- 500 basis point reopener thresholds for that year. 23 The Commission also determined that the latest information available, be it the initial Rule 005 filing or a subsequent ROE restatement filed as part of the annual PBR rates adjustment filing, can serve as a basis for a reopener application. 3.2 Rebasing process to set the going-in rates for the PBR plans 30. During a PBR term, a utility s revenues are no longer linked to its costs, thereby enhancing incentives for the distribution utility to improve its productivity. However, in order to transition the distribution utilities into the next PBR term, in Decision D (Errata) the Commission established the need for this compliance filing proceeding with the objective of generally realigning the distribution utilities revenues and costs in order to set going-in rates for the next generation PBR plan. If a utility was successful in achieving efficiencies that resulted in cost savings during the preceding PBR plan, the going-in rates that result from rebasing should be lower than they otherwise would have been, thereby passing on the benefit of these savings to customers throughout the next generation PBR term In Proceeding 20414, all parties agreed on the need to ensure that the going-in rates are neither too high nor too low. Going-in rates should be sufficient when adjusted under the PBR formula for the utility to have a reasonable opportunity to recover its prudently incurred costs including a fair rate of return, while ensuring customers pay only just and reasonable rates. In Decision D (Errata), the Commission recognized the importance of setting the going-in rates and that getting the going-in rates correct is critical to the success of a PBR plan In Decision D (Errata), the Commission determined that it would not employ the utilities forecast costs in order to set going-in rates. Rather, the Commission determined that it would set going-in rates on the basis of a notional 2017 revenue requirement that represents the costs that each utility, operating under the incentives of the PBR mechanism, unencumbered by incentives inconsistent with the PBR incentives, would have incurred in The notional 2017 revenue requirement is developed using actual costs experienced during the 22 Decision D (Errata), paragraphs and Decision D (Errata), paragraph Decision D (Errata), paragraph Decision D (Errata), paragraph 34. Decision D (February 5, 2018) 7

12 previous years of the preceding PBR term for each distribution utility, with any necessary adjustments to reflect individual distribution-utility anomalies. This notional 2017 revenue requirement would not be charged to customers, but would be used for the sole purpose of establishing the going-in rates for the next generation PBR plan commencing in The Commission indicated that using actual pre-2017 costs to develop a notional 2017 revenue requirement, adjusted as required for anomalies, would best reflect expected revenues and costs, without the distorting influence of the incentives that arise during the last year of a PBR term Regarding the actual pre-2017 costs to use in determining the notional 2017 revenue requirement, AltaGas, the ATCO Utilities, EPCOR and Fortis (the utilities on the PBR plans) were directed to use actual operating and maintenance (O&M) cost data based on the utility s lowest-cost year, as described more completely below, 2016 actual closing rate base and actual non-capital tracker data, and 2017 approved capital tracker forecast data (to be updated later to approved actual data), in preparing their respective rebasing applications. Because ENMAX was not on the same PBR plan, the Commission directed ENMAX to use a time period, the period of its most current PBR plan. In preparing its application, ENMAX was directed to use actual O&M data as described below, 2016 actual closing rate base and actual non-capital tracker capital data, and 2017 applied-for capital tracker forecast data. 34. With respect to the O&M costs component of the notional 2017 revenue requirement, in view of the incentive properties of PBR, the Commission determined in Decision D (Errata) that rebasing of such costs should be based on the lowest O&M cost year during the preceding PBR term, excluding the last year of the term, 2017, restated to 2017 dollars, with adjustments as necessary to reflect material anomalies. In the Commission s view, the lowestcost year for a particular distribution utility, everything else equal, represents the largest response to PBR incentives during the previous PBR term. 35. With respect to the capital costs component of the notional 2017 revenue requirement, the Commission determined that the distribution utilities should use the 2016 actual closing rate base as a starting point and add the 2017 capital additions, divided into capital additions that are covered by I-X in 2017 and those that are subject to capital tracker treatment in 2017, in the manner described below. 36. Given the incentive properties of PBR, in developing a 2017 estimate for the non-capital tracker component of the notional 2017 revenue requirement and going-in rates, the revenue requirement would be based on the average actual capital additions over the period, restated to 2017 dollars, for the distribution utilities other than ENMAX. ENMAX was directed to use the average actual capital additions for 2015 and In both cases, the averages do not include 2017, which was the last year of the preceding PBR terms. The Commission determined that non-capital tracker costs can generally be assumed to be prudent, because they were subject to the incentive properties of the I-X mechanism. 37. Regarding the capital additions subject to capital tracker treatment, the Commission accepted on an interim basis the approved 2017 capital tracker forecast for capital additions. Because ENMAX did not have any approved 2017 forecast capital tracker capital additions, the 26 Decision D (Errata), paragraph Decision D (February 5, 2018)

13 Commission accepted, on an interim basis, 90 per cent of its applied-for 2017 capital tracker forecast for capital additions. 38. In accordance with the provisions of Decision D (Errata), going-in rates will be adjusted effective January 1, 2018, to reflect any changes in a limited number of certain specified cost parameters. Specifically, following the determination of final approved K factor amounts in capital tracker decisions, the going-in rates are to be adjusted to reflect the approved actual additions consistent with the capital tracker mechanism in place until the end of Decision D (Errata) also permitted the distribution utilities to file applications in 2018 to update depreciation parameters. Going-in rates will also be adjusted to reflect Commission decisions on any of these applications. As well, consistent with the findings in Section 6 of this decision, going-in rates for certain utilities will also be adjusted to reflect the finalization of placeholder amounts currently under review by the Commission in separate proceedings. 39. The Commission indicated in Decision D (Errata) that it will accept Phase II applications from the distribution utilities at some point following the commencement of the PBR plans. However, rather than adjusting the going-in rates, any new approved Phase II applications to alter cost-allocation or rate-design methodologies should be filed and implemented on a go-forward basis during the PBR term, since rate-class allocations do not affect the total revenue requirement. Following the approval of any updated Phase II study for a specific distribution utility during the term of the next generation PBR plans, the Commission will not consider further Phase II applications by that utility during the PBR plan period Finally, with respect to pension, compensation, shared services, and necessary working capital costs, and accompanying cost-of-service types of studies, the Commission indicated in Decision D (Errata) that unless the distribution utilities are directed by the Commission to undertake such a study as part of the ongoing rate-regulation initiative, the Commission considered these type of costs to be no different than other operating costs, to the extent they fall under the I-X mechanism, adjusted by Q. The Commission concluded that these costs can be adequately reflected in the rebasing process through the O&M mechanism and noncapital-tracker capital cost-averaging method Proposed anomaly adjustments 41. In Decision D (Errata), the Commission determined that it would set going-in rates for each distribution utility on the basis of the utility s notional 2017 revenue requirement calculated in a manner consistent with continuing the incentives provided by the PBR framework. The notional 2017 revenue requirement is developed using actual costs experienced during the years of the preceding PBR term for each distribution utility, with any necessary adjustments to reflect individual distribution-utility anomalies. 29 This approach is designed to establish just and reasonable rates at the outset of the PBR term. 27 Decision D (Errata), paragraphs Decision D (Errata), paragraph Decision D (Errata), paragraph 46. Decision D (February 5, 2018) 9

14 42. More specifically, the Commission contemplated that anomalies 30 could be permitted to adjust the O&M component of the notional 2017 revenue requirement and to adjust for retirements 31 for the capital component of the notional 2017 revenue requirement. Sections 4.1 to 4.3 deal with the O&M anomaly adjustments proposed by the distribution utilities. Section 4.4 addresses O&M anomaly adjustments proposed by the interveners. Section 4.5 deals with the retirement anomaly proposed by ENMAX, which was the only retirement anomaly proposed in this proceeding. 4.1 Methodology for identifying the lowest-cost year for O&M expenditures 43. In Decision D (Errata), the Commission determined that the O&M component of the notional 2017 revenue requirement should be based on the lowest-cost year for O&M expenditures during the current generation PBR term, restated to 2017 dollars, with adjustments as necessary to reflect material anomalies The Commission did not prescribe a specific method to account for anomalies in determining the lowest-cost year for O&M expenditures in Decision D (Errata). However, by following the calculations embedded in the rebasing template provided by the Commission, a distribution utility would identify all anomalies, both positive and negative, in each of the subject years (2015 and 2016 for ENMAX, and 2013 to 2016 for the other distribution utilities) and adjust the actual O&M costs in each year for the identified anomalies. 33 These adjusted O&M costs for each year would then be restated to 2017 dollars using the approved I-X index and Q. Finally, after accounting for anomalies and converting to 2017 dollars, the lowest-cost year for O&M expenditures would be selected from the subject years The Commission indicated that modifications to the Commission-incorporated assumptions and embedded formulas in the template could be proposed, as long as the proposals remain consistent with Decision D (Errata) and are fully supported by evidence demonstrating the need for, and the effect of, the proposed changes In their rebasing applications, the majority of the distribution utilities adopted an approach (with individual utility variations) in which they first determined the lowest-cost year for O&M expenditures and then identified anomalies pertaining to that lowest-cost year. 36 Certain distribution utilities supplemented this approach by performing a general overview of their O&M costs for the years to determine whether there were anomalies that would identify a different lowest-cost year. 37 In support of these approaches, the distribution utilities indicated that such approaches are consistent with the Commission s determinations in 30 Decision D (Errata), paragraph Decision D (Errata), paragraph Decision D (Errata), paragraph Exhibit X0003, Appendix 1, Template for rebasing calculations, Schedule Exhibit X0003, Appendix 1, Template for rebasing calculations, Schedule Exhibit X0002, AUC Letter, Rebasing schedules template and responses to parties clarification questions, February 6, 2017, paragraphs See, for example, the approach described by AltaGas at Transcript, Volume 7, page 1339, line 16 to page 1343, line 9 (Mr. Stock). 37 See, for example, the approach described by EPCOR at Transcript, Volume 3, page 598, line 1 to page 602, line 11 (Mr. Chaudhary) (Mr. Chan). 10 Decision D (February 5, 2018)

15 paragraphs 52 and 53 of Decision D (Errata), and are simpler than thoroughly identifying all of the anomalies in each of the subject years. 47. ENMAX, Fortis and the ATCO Utilities indicated that identifying all of the anomalies in each of the subject years would be too time-consuming. 38 AltaGas, Fortis and EPCOR pointed out that thoroughly reviewing all subject years for anomalies would require a detailed line-byline examination and explanation of all cost changes and, therefore, is beyond the scope or intention of the rebasing process approved by the Commission in Decision D (Errata) Additionally, ENMAX and the ATCO Utilities stated that identifying anomalies in each year is not necessary because of the sizeable difference between the lowest-cost O&M year compared to the other years. 40 The ATCO Utilities submitted, for example, that no amount of anomalies could have rendered 2013, 2014 or 2015 the lowest-cost O&M year due to the step change that occurred at the end of 2015 (2016 was $46 million lower for ATCO Electric and $17 million lower for ATCO Gas). 41 ENMAX stated that, because its 2015 O&M expenditures were approximately $10 million higher than its 2016 O&M expenditures, ENMAX does not expect that 2015 would be lower than 2016 after adjusting for anomalies During the hearing, Mr. Bell, on behalf of the UCA, expressed some skepticism with respect to the amount of effort the utilities indicated would be required to identify anomalies in all years. In Mr. Bell s view, anomalies are large, material and unique items and the utility should, therefore, already be aware of them. 43 However, the UCA acknowledged the time constraints under which the distribution utilities would be at this point in the proceeding if they were to identify the lowest-cost year for O&M expenditures using the approach incorporated in the Commission s template. As a result, the UCA appeared to accept the approach taken by many of the utilities Mr. Thygesen, on behalf of the CCA, accepted that, due to the size of the reductions in the ATCO Utilities and ENMAX s O&M costs in their respective lowest-cost years, using the approach incorporated into the Commission s rebasing template probably would not have made any difference to the outcome for these distribution utilities. However, for Fortis, EPCOR, and AltaGas, because the differences in O&M costs for the years 2013 to 2016 were less dramatic, 38 Exhibit X0075, EPC-AUC-2017MAY29-003(a)-(b); Transcript, Volume 2, page 327, line 7 to page 332, line 10 (Ms. Sullivan); Exhibit X0119, AE-AUC-2017MAY29-003(a)-(b). 39 Exhibit X0173, AUI-AUC-2017MAY29-003(a)-(b); Transcript, Volume 2, page 327, line 7 to page 332, line 10 (Ms. Sullivan); Transcript, Volume 3, page 601, line 18 to page 602, line18 (Mr. Chaudhary). 40 Exhibit X0075, EPC-AUC-2017MAY29-003(a)-(b); Exhibit X0119, AE-AUC-2017MAY29-003(a)-(b); Transcript, Volume 5, page 952, line 5 to page 953, line 8 (Ms. Bayley). 41 Exhibit X0412, ATCO Utilities reply argument, paragraph 15; Transcript, Volume 5, page 952, line 9 to page 953, line 8 (Ms. Bayley); Exhibit X , ATCO Electric updated rebasing template, Schedule 3.0 and Exhibit X , ATCO Gas updated rebasing template, Schedule Exhibit X0075, EPC-AUC-2017MAY29-003(a)-(b). 43 Transcript, Volume 8, page 1470, line 16 to page 1471, line 15 (Mr. Bell). 44 Except in the case of AltaGas, which the UCA submitted should be remedied in the manner outlined in its evidence. See Exhibit X0192, UCA evidence of Mr. Bell, pages Mr. Bell suggested that AltaGas should not limit its examination of O&M costs to labour costs in the determination of its lowest-cost year for O&M expenditures, because as stated by AltaGas, its 2016 actual O&M costs are only slightly different from its 2013 costs, and an examination of all O&M costs may reveal anomalies that might show a greater difference between 2013 and 2016 costs. Decision D (February 5, 2018) 11

16 the approach incorporated into the Commission s rebasing template possibly could have resulted in a different lowest-cost year for O&M expenditures. 45 Mr. Thygesen, however, did not recommend that the utilities be required to pursue the more rigorous approach to identifying their lowest-cost year for O&M expenditures Mr. Thygesen 47 and Mr. Bell 48 also expressed concerns about the distribution utilities cherry picking cost increases and ignoring similar or mirror image cost decreases. The UCA and the CCA both expressed disbelief that there were no or very few, negative anomalies, especially when some of the utilities included $100,000 or $150,000 positive anomaly adjustments in their applications. 49 Mr. Bell was not convinced that the utilities spent any amount of effort in identifying negative anomalies, and indicated that information available to the UCA through, for example, Rule 005 reporting, did not provide the granularity necessary to highlight potential negative or positive anomalies. 50 Calgary had a similar concern As set out in Section 4.3 of this decision, EPCOR and ENMAX were the only distribution utilities to identify negative anomalies. 52 Most of the reasons provided by the distribution utilities to explain why so few, or no, negative anomalies were identified were similar to the reasons provided for conducting a general overview in identifying the lowest-cost year for O&M expenditures, summarized earlier in this section. Additionally, AltaGas submitted that identifying negative anomalies was not necessary because O&M costs were not expected to be much less than the amount the PBR formula provided, or be less than the amounts in the lowest-cost year for O&M expenditures. 53 AltaGas also indicated that some instances of cost decreases were the result of the efficiency initiatives that the utility undertook and not the result of anomalies. 54 ENMAX submitted that the fact that there are many more positive anomalies should not be surprising given that the starting point is the lowest actual cost year for O&M expenditures In the Commission s view, the approach of identifying the lowest-cost year for O&M expenditures and then applying the anomaly adjustments relevant to that year, accompanied by a general overview of anomalies or lack thereof in the remaining years, was not as rigorous as the approach incorporated by the Commission in its rebasing schedules template. The Commission s template involved identifying all of the anomalies, both positive and negative, in all of the subject years (2015 and 2016 for ENMAX, and 2013 to 2016 for the other distribution utilities). 45 Transcript, Volume 9, page 1591, line 21 to page 1593, line 15 (Mr. Thygesen). 46 Transcript, Volume 9, page 1591, line 21 to page 1593, line 15 (Mr. Thygesen). 47 Exhibit X0195, CCA evidence of Mr. Thygesen, paragraphs Exhibit X0192, UCA evidence of Mr. Bell, page Transcript, Volume 8, page 1470, line 24 to page 1472, line 3 (Mr. Bell); Transcript, Volume 9, page 1593, line 16 to page 1594, line 4 (Mr. Thygesen). 50 Transcript, Volume 8, page 1470, line 24 to page 1472, line 3; page 1563, lines 5-16 (Mr. Bell). 51 Exhibit X0196, Calgary evidence, paragraph In response to a Commission IR, Exhibit X0075, EPC-AUC-2017MAY29-003(c), ENMAX identified a change in revenue offsets due to a new pole attachment agreement that would result in cost savings of $600,000 in 2016, which could be seen to pass the test for an anomaly. However, as clarified in the oral hearing, Transcript, Volume 1, page 30, line 24 to page 31, line 15 (Mr. Barrett), ENMAX was not proposing it as an anomaly in its rebasing application because the Commission did not identify revenue offsets as a category of costs or revenues that qualify for anomalies. 53 Exhibit X0241, AltaGas rebuttal evidence, paragraph Transcript, Volume 7, page 1342, lines (Mr. Stock). 55 Exhibit X0400, ENMAX argument, paragraphs 123 and Decision D (February 5, 2018)

17 Identifying anomalies pertaining to only one year, in isolation, may have resulted in distribution utilities ignoring potentially material positive or negative anomalies in other years. 54. Despite these observations, the Commission accepts the general overview approach most of the distribution utilities chose for identification of the lowest-cost year for O&M expenditures. The Commission is satisfied that this approach is a reasonable response to the fact that the Commission did not prescribe a specific method for accounting for anomalies in determining the lowest-cost year for O&M expenditures in Decision D (Errata), and parties were invited in this proceeding to propose modifications to the Commission-incorporated assumptions and embedded formulas in the template, as long as the proposals remained consistent with the principles of the decision. The Commission is satisfied that this approach is generally consistent with the principles reflected in Decision D (Errata). Further, neither the CCA nor the UCA opposed the general acceptance of this approach. 55. Based on the foregoing, the Commission accepts the lowest-cost year for O&M expenditures identified by each of the distribution utilities for the purposes of calculating the O&M component of each of their notional 2017 revenue requirements. 4.2 Characteristics of permitted O&M anomalies 56. In Decision D (Errata), the Commission stated: 52. The Commission is prepared to adjust the 2017 notional revenue requirement estimate obtained by utilizing prior lowest actual O&M expenditures for a particular distribution utility should the distribution utility or interveners provide evidence demonstrating to the satisfaction of the Commission that specific and identifiable adjustments are required to account for unique existing or anticipated material cost anomalies. Allowing for these adjustments that may result in the 2017 costs being lower or higher than they would otherwise be, permits the Commission to recognize the unique circumstances of each distribution utility. The Commission retains its discretion to determine what it considers to be reasonable going-in rates for each distribution utility Throughout the O&M rebasing section in Decision D (Errata), the Commission repeated that the proposed anomaly adjustments are to be material, could be present or anticipated and that these adjustments could result in both cost additions or reductions to notional 2017 costs The Commission also indicated that it does not consider that an adjustment to O&M costs and non-capital tracker capital costs is required to going-in rates to reflect actual 2017 costs because the application of the I-X mechanism and Q adjustment to the rebasing amounts determined using the mechanisms referred to above, plus any adjustments for anomalies, should be sufficient for the purposes of determining going-in rates. 58 Further, the Commission indicated that going-in rates should not be based on the distribution utilities cost forecasts Decision D (Errata), paragraph Decision D (Errata), paragraphs 36, 46, 52 and Decision D (Errata), paragraph Decision D (Errata), paragraph 285. Decision D (February 5, 2018) 13