Revenue Requirement – Transmission Facility Owner – Tariff Application
In this decision, the AUC considered an application by EPCOR Distribution and Transmission Inc. (“EPCOR”) requesting approval of its transmission facility owner (“TFO”) tariff for the 2018-2019 test years.
The AUC did not approve the requested revenue requirement of EPCOR for the years 2018-2019. The AUC ordered EPCOR to refile its application by November 15, 2018.
EPCOR applied for various approvals associated with its TFO function for the 2018 and 2019 test years (the “TFO Application”). Specifically, EPCOR requested approval of:
(a) the transmission rates to be paid by the Alberta Electric System Operator (“AESO”) for the use of EPCOR’s transmission facilities over the test period;
(a) the TFO terms and conditions of service (“T&Cs”);
(b) the continued use of the following transmission reserve and deferral accounts in the test period:
(i) hearing cost reserve;
(ii) self-insurance reserve;
(iii) AESO directed projects deferral account;
(iv) transmission property, business, and linear taxes deferral account; and
(v) transmission short-term incentive (“STI”) deferral account;
and
(c) placeholders related to capital structure and rate of return on equity (“ROE”) for its transmission function.
The table below provides a summary of the updated forecast capital expenditures and capital additions for 2018 and 2019 compared to 2017 updated forecasts.
Forecast Capital Expenditures and Capital Additions for the Years 2017-2019
Transmission O&M Costs
The AUC approved the direct O&M forecast costs for 2018 and 2019, finding the test year forecasts for direct O&M to be reasonable.
EPCOR’s operating costs are comprised of direct O&M costs, administrative and general (“A&G”) expenses, and allocated corporate general and administrative expenses.
Labour Related Costs
The AUC approved:
(a) the addition of four full-time employees (“FTEs”) transferred to transmission from the Master Overhead Pool (“MOP”), finding that these positions were transferred to transmission from a shared MOP cost category to ensure that their cost treatment more accurately reflected the work performed;
(b) the reclassification of the 2.5 FTEs related to management and supervision of substation field operations staff, finding that the overall FTE total never added up to more than 100 percent of the total FTE costs on a forecast basis and, therefore, there was no risk of double recovery; and
(c) the addition of 2.4 FTEs in 2019, finding these additions to be reasonable given the growth in rate base and the continued aging of EPCOR’s fleet of assets.
However, the AUC directed EPCOR to remove the costs associated with 5.5 FTEs from the forecast revenue requirement, finding that EPCOR failed to sufficiently justify the increase in the number of O&M related FTEs.
Employee Compensation and Benefits
The AUC found that the mid-term incentive (“MTI”) program and its costs were not required for utility service. The AUC denied the requested MTI program costs for 2018 and 2019.
Contractors, Other Escalation and Materials
The AUC found that EPCOR’s proposed inflation factors for contractors, materials, and other costs were reasonable and, therefore, approved these costs as filed.
Administrative and General (“A & G”) Expenses
EPCOR requested a forecast $5.12 million A&G expenses in 2018. However, the AUC observed that in its schedules, EPCOR requested a forecast of $7.98 million for A&G expenses in 2018, and did not provide an explanation with respect to this difference between the forecasts in the application and the schedules. The AUC found that the correct forecast was not known. Accordingly, the AUC directed EPCOR in its compliance filing, to provide the correct forecast for A&G expense and to reflect those correct amounts in its compliance filing and schedules.
Corporate Services Costs
The AUC denied EPCOR’s proposal to include business development costs in its revenue requirement. The AUC determined that business development costs were not required for the provision of utility service.
Transmission Other Revenue Requirement Items
The AUC approved the forecast for transmission other revenue requirement items and the continuation of the Transmission Property, Business and Linear Tax Deferral Account. The AUC found EPCOR’s methodology was consistent with previous applications approved by the AUC. Therefore, the AUC found the forecast costs to be reasonable.
The AUC found EPCOR’s request to recover incurred costs for the project variances as an operating expense to be reasonable since the expenditures on this project were not incurred for the acquisition or construction of assets that would remain in rate base in future periods.
Rate Base
The AUC approved the 2015, 2016, and 2017 rate base additions as filed, for the purposes of determining the revenue requirement for the test period. The AUC directed EPCOR to update its 2018 opening rate base to reflect the 2017 actual amounts for the life cycle projects, which were initially estimated using a three-year average.
EPCOR requested approval of its opening 2018 net transmission rate base of $673.44 million. The table below shows a comparison of approved to actual closing rate base amounts for the prior test period, from 2015-2017.
Table: Transmission Rate Base 2015-2017
Capital Additions
The AUC approved EPCOR’s forecast capital expenditures and capital additions for the years 2018 and 2019 for the purpose of calculating the forecast revenue requirement in the test years, subject to the AUC’s directions summarized below.
Substation Feeder Additions
This project was an ongoing project to install circuit breakers and current limiting reactors to meet requirements for new distribution feeders at transmission substations. New distribution feeders were required to ensure sufficient capacity was available for load growth. Work associated with thirteen new feeders was forecast for this test period.
The cost forecasts for the feeder addition projects were based on a bottom-up approach, which the AUC previously accepted as reasonable. While the selection of feeders to be added in a given period was based on load forecasts which inherently were uncertain, the AUC found that EPCOR’s methodology for evaluating load requirements and tracking design load exceedances was reasonable.
The total number of feeder additions in the test period was unclear: The application stated thirteen feeder additions with two of those serving specific large customers and the remaining 11 serving regional load; however, the list of feeder additions only included nine feeders.
The AUC directed EPCOR to provide a complete list of feeders to be added in the test period (i.e. 2018 and 2019 only), with the substation clearly associated to each listed. The AUC also directed EPCOR to provide an update to the actual or forecast in-service date of each feeder addition, and an updated capital addition forecast for each.
Non-AESO Directed Growth Projects and Performance Improvement Projects
Garneau Switchgear Replacement Project
The AUC approved the project given that the costs for the Garneau switchgear replacements were fully-funded through the customer contributions from the University of Alberta (“U of A”). The AUC found the project and the costs recovery proposed were reasonable.
The AUC accepted EPCOR’s submission that the Garneau switchgear replacement would not be undertaken in 2019, but for the U of A’s request. EPCOR Distribution & Transmission Inc.’s (“EDTI”) transmission function determined that the project was not currently required to meet distribution load requirements in the area, nor was it likely required until approximately 2028, and neither the AESO nor EDTI’s distribution function requested that this project be undertaken during the test period.
The AUC found that any reduced operations and maintenance costs associated with the new switchgear in 2019 did not justify the U of A’s proposed reduction of its customer contribution. This finding was also supported by evidence that the U of A comprised 85.5 percent of the Garneau substation peak load in 2017.
The U of A indicated that it would request a refund when the switchgear would normally be replaced due to load constraints or asset condition in 2028. The AUC approved EPCOR’s proposal to repay the U of A the net book value of the switchgear when the substation load reaches the level at which it would normally be replaced. The AUC found that this proposal would balance the costs paid by the customer and Alberta ratepayers over the life of the asset, especially given that this project was a customer directed project.
Lifecycle Replacement Projects
The AUC accepted EPCOR’s evidence that 72RS5 oil-filled pipe type cable (the “72RS5 cable”) could no longer operate at the required rating, had reached the end of its useful life and required replacement. The AUC accepted EPCOR’s proposed alternative of replacing the 72RS5 cable with an aerial line as being the lowest cost and a technically sufficient solution for the purposes of forecasting capital costs for the 2018-2019 revenue requirement. The AUC noted that the design and route were subject to AUC review in the facility application.
The AUC reviewed the cost forecast evidence and found the magnitude of the forecast capital expenditures and additions were reasonable given the project scope and location.
Rossdale Medium Voltage Switchgear Addition
The AUC was concerned by the cost increase in this project attributed to the engineering consultant error. There was insufficient information to determine whether EPCOR took all reasonable steps to mitigate the cost increase or recover damages. The AUC considered that additional information was required to determine whether the cost increases were attributable to the design consultant error. The AUC directed EPCOR to remove the $1.07 million associated with the engineering consultant design deficiencies from the 2018 capital additions.
Return on Rate Base
Given that EPCOR’s application had already incorporated an ROE and deemed equity ratio of 8.5 percent and 37 percent, respectively, for the years 2018 and 2019 consistent with the AUC’s findings in Decision 22570-D01-2018, there was no requirement for EPCOR to update its applied-for ROE and deemed equity ratio. Accordingly, the AUC approved EPCOR’s 2018-2019 ROE and deemed equity ratio on a final basis, as filed.
Cost of Debt
The AUC found that EPCOR’s forecast interest expense calculation on its long-term debt was consistent with the application of the mid-year convention. The AUC agreed with EPCOR’s explanation that the effect of applying the mid-year convention to the determination of its interest expense was that all debt was assumed to have been issued mid-year and, thus, attracted six months of interest expense in both the year the debt was issued and the year in which the debt matured.
Determination of the Forward Curve Interest Rates
The AUC found that forward curve yields derived using the most recent data available for the month of June was a reasonable approach to determining EPCOR’s cost of debt and was consistent with the AUC’s previous findings. Therefore, the AUC based its determination on the average of the June 1 to June 6, 2018, one- and two- year forward curve fields on a 30-year Government of Canada bond. The average one-year yield was 2.34 percent, and the average two-year yield was 2.35 percent.
The AUC directed EPCOR to reflect 2018 and 2019 forward curve interest rates in the amounts of 2.34 percent and 2.35 percent, respectively.
Determination of the Credit Risk Premium (or Credit Spread)
EPCOR proposed a credit risk premium of 1.50 percent based on the use of the average spread of a group of comparable utilities, which included FortisAlberta, FortisBC, Nova Scotia Power. The AUC found TransCanada and Westcoast, all of which were rated A (low) by DBRS (originally known as “Dominion Bond Rating Service”).
The AUC considered the range of credit spreads of Westcoast and TransCanada compared with the range of credit spreads among the two Fortis companies and Nova Scotia Power, and found that the divergence between the five companies was at an unacceptable level for comparative use. For this reason, the AUC found that Westcoast and TransCanada were not close comparators for the purposes of determining EPCOR’s credit risk premium.
The AUC found that the determination of EPCOR’s credit risk premium should be based on the average of the credit spreads of FortisAlberta, FortisBC and Nova Scotia Power (the “Approved Credit Risk Premium”). The AUC considered these companies to be equivalent in risk to EPCOR because FortisAlberta, Fortis BC and Nova Scotia Power were all rated A (low), and because the range of the lowest to highest credit risk spreads was found to be within an acceptable level compared to that of Westcoast and TransCanada.
The AUC directed EPCOR to apply the Approved Credit Risk Premium of 1.25 percent for the years 2018 and 2019 in its compliance filing.
Depreciation and Amortization
The AUC was of the view that the rationale justifying the Alberta Energy and Utilities Board’s decision to approve EPCOR’s depreciation methodology at the outset of EPCOR’s regulation under the AUC’s predecessor remained valid.
The AUC was satisfied with EPCOR’s proposal to adopt AltaLink’s currently approved average service lives for EPCOR’s similarly constructed ISO Rule 502.2 related assets. EPCOR proposed to increase the average service lives of six other accounts that were designed and constructed under the functional specifications of ISO Rule 502.2.
The AUC directed EPCOR to confirm whether it intended to mirror the 65-year average service life of AltaLink’s conductors and devices for its Heartland asset, or if EPCOR was satisfied with an average service life of 67 years as proposed.
The AUC approved:
(a) EPCOR’s proposal to refund the Heartland-related reserve surplus over a period of two years, being the years 2018 and 2019;
(b) EPCOR’s proposed changes to the average service lives of eleven asset accounts; and
(c) EPCOR’s transmission working capital forecast for 2018-2019, subject to any required adjustments.
Order
The AUC directed EPCOR to refile its application to reflect the findings, conclusions and directions in this decision.
