Rates – Default Gas Tariff – Regulated Electricity Rate Tariff
Introduction
Direct Energy Regulated Services (“DERS”) is a business unit of Direct Energy Marketing Limited (“DEML”) and performs the natural gas default rate tariff (“DRT”) and electricity regulated rate tariff (“RRT”) functions in the service territories of ATCO Gas and Pipelines Ltd. (“ATCO Gas”) and ATCO Electric Ltd. (“ATCO Electric”), respectively.
In this decision, the AUC considered, DERS’ application requesting approval of its 2017-2018 DRT and RRT tariff for the January 1, 2017, to December 31, 2018 period (“Test Period”).
The Application
DERS requested AUC approval of:
(a) the revenue requirements (DRT and RRT);
(b) DERS’ proposed allocation methodology for corporate services costs; and
(c) resulting 2017-2018 rates on a final basis.
DERS requested approval of both the DRT and RRT revenue requirements. The revenue requirements were, segregated into energy-related and non-energy revenue requirement components, as well as an RRT risk margin and a DRT retail margin as follows:
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A DRT non-energy revenue requirement of $59.4 million in 2017 and $57.8 million in 2018;
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An RRT non-energy revenue requirement of $19.0 million in 2017 and $17.9 million in 2018;
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A DRT energy-related revenue requirement of $2.5 million in 2017 and $2.3 million in 2018;
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An RRT energy-related revenue requirement of $0.5 million in 2017 and $0.3 million in 2018;
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DRT retail margin revenue of $8.4 million in 2017 and $8.1 million in 2018; and
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RRT risk margin revenue of $5.9 million in 2017 and $5.8 million in 2018.9.
Decision Overview
In assessing DERS’ application, the AUC considered the following:
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customer site forecasts and corresponding load forecasts;
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forecasted estimates for non-labour inflation, labour inflation, energy transmission and distribution (“T&D”) rates in its service areas, and natural gas prices and forward market electricity prices;
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planned capital expenditures for 2017 and 2018;
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each of the specific cost categories making up the applied-for total energy and non-energy revenue requirement amounts; and
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DERS’s request for DRT retail margin revenues for 2017 and 2018, and for RRT risk margin revenue for 2017 and 2018.
Customer Site and Load Forecasts
The AUC confirmed its findings from previous decisions that updated information may be used for evaluating the reasonableness and accuracy of the forecasts and forecast methodologies. This can include information that becomes available during the course of a proceeding.
DERS’ customer site forecasts for 2017 and 2018 were derived using a methodology that incorporated actual data from April 2014 through March 2017.
Given that DERS would now have actual data for 2017 and at least for the first four months of 2018, the AUC directed that DERS use the following actual data and/or forecast methodologies:
(a) for 2017, the actual site counts and customer load amounts;
(b) for Jan-Apr 2018, actual site counts and load amounts;
(c) for the remaining May-Dec 2018:
(i) site count forecasts based on actual data from the preceding 36-months; and
(ii) customer load forecasts developed using the average usage per site amounts included in the application (based on 10-year average weather figures).
The AUC noted that the Alberta government instituted a price cap, which took effect June 1, 2017, which caps the regulated rate option (“RRO”) rate at 6.8 cents per kilowatt hour (kWh) for electricity, or the market rate, whichever is lower, until May 31, 2021.
DERS’ customer site forecasts for 2017 and 2018 were based on projections from data before the price cap. The AUC considered use of more recent RRT site data would reflect initial changes in customer site growth and attrition rates attributable to the price cap.
In addition, some sites in Fort McMurray were destroyed as a result of the 2016 fire, and the rebuild schedule is unclear. The AUC considered that the use of more recent RRT and DRT site data would incorporate actual rebuilds that have occurred in Fort McMurray.
Other Forecasting Parameters: Inflation, T&D Rates, and Forward Energy Prices
The AUC accepted DERS’ 3.13 per cent labour increase for 2017.
The AUC directed DERS to update its 2018 labour forecasts based on the three-year average (2015-2017) of actual labour increases.
With respect to inflation, the AUC found that:
(a) the inflation rate data relied on by DERS might not reflect current market conditions;
(b) during the course of the proceeding, actual inflation rates for 2017 became available; and
(c) the inflation rates may be trending downward.
The AUC directed DERS in its compliance filing:
(a) to use actual CPI inflation rates and commodity prices for 2017;
(b) for 2018, to incorporate the most recent CPI and commodity price forecasts at the time of filing its compliance filing to this decision; and
(c) to reflect the updated inflation rates in its compliance filing to this decision for any forecasts that apply inflation rates.
With respect to the data relied on to determine T&D rates, the AUC directed DERS:
(a) to use the actual T&D rates for the RRT and the DRT for 2017, to derive the forecast T&D charges for 2017; and
(b) to use the current T&D rates for the RRT and the DRT (at the time of this decision) in deriving the forecast T&D charges for 2018.
DRT and RRT Revenue Requirement Cost Categories
Overview
The DRT and RRT non-energy revenue requirements consist of the following cost categories: customer operations, merchant fees, working capital, deemed income tax, credit charges, hearing cost reserve account, bad debt expense, penalty revenue, revenue offsets, unknown customer costs, full-time equivalents (FTEs) and labour costs, amortization of capital, customer information costs, other administration costs and corporate services.
The forecast for these cost categories for 2017 and 2018 was dependant on a number of forecast costs, that would require revision as a result of AUC’s directions respecting forecasting data and methodology, as set out in this decision.
This summary addresses findings of interest regarding customer operations, bad debt, and revenue offsets.
Customer Operations
Customer operations include the costs associated with providing customer contact centre services, calculating, printing and delivering bills, and processing payments. DERS categorized the customer operations costs into the following:
(a) customer care and billing (“CC&B”);
(b) bill delivery;
(c) paper, long distance and requests for service (RFS); and
(d) customer goodwill credits.
DERS forecast customer total operations costs of $49.1 million in 2017 and $48.7 million in 2018, a decrease from 2016 costs of $51.2 million. DERS said the decrease was mainly due to the reduction in the expected goodwill credits paid to customers and the reduction in customer sites.
Customer care and billing
The Commission found that:
(a) the fair market value (“FMV”) of $4.77/month/site that was approved for 2016 should remain in place for 2017 and 2018, less than the $4.82 FMV rate proposed for 2018; and
(b) the $4.77/month/site rate for 2017 and 2018 amounts to prudent cost recovery for DERS and ensures that customers are not paying for CC&B services not yet up to full performance standards.
The AUC directed DERS, in its compliance filing, to forecast CC&B costs for 2017 and 2018 using a monthly rate of $4.77 per customer site.
Customer Goodwill Credits
DERS explained that the high level of goodwill credits paid to customers in 2016 was primarily the result of challenges experienced with DERS’ billing services. DERS acknowledged that the allowable limit of credits provided to contact centre agents and supervisors was temporarily increased in 2016 while DERS dealt with a high number of escalated complaints. In addition, DERS explained that the goodwill credits paid in 2016 included credits for customers impacted by specific billing issues.
For the Test Period, DERS forecasted combined DRT and RRT goodwill credits of $0.3 million for 2017, and $0.2 million for 2018.
The AUC expressed concerns about the lack of support for increases in goodwill credit forecasts.
Recognizing DERS’ current billing system limitations, the AUC approved a nominal amount of $25,000 in each of 2017 and 2018 for charge reversals, allocated 80 percent to the DRT and 20 percent to the RRT.
Bad debt expense
Bad debt expenses forecast by DERS were broken down into three categories: bad debt, collection agency costs and cut-off for nonpayment (“CONP”).
DERS forecated bad debt expense using actual bad debt costs for recent years expressed as a percentage of total revenues. The forecast percentages for 2018 were derived using the historical percentages for 2013 and 2014. DERS stated that 2013 and 2014 were operationally stable years with more positive economic conditions, and therefore they would be the best years to use for the expected bad debt performance in 2018.
The AUC found that:
(a) the drivers of DERS’ bad debt forecasts were likely unrelated to the third-party service provider’s past performance and instead, were primarily due to changes in the economy; and
(b) there was insufficient evidence on the record to conclude that the CC&B service quality and performance issues were the driver for increased bad debt costs, as argued by the customer groups.
The AUC directed DERS, in the compliance, to update the forecasts for 2017 and 2018 for CONP using the 2016 actuals and applying the non-labour inflation rates.
The AUC approved the following percentages of revenue for forecasting bad debts and collection agency costs for 2017 and 2018:
Forecasting bad debts costs for the DRT:
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2017 at 0.70 percent; and
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2018 at 0.64 percent;
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Forecasting collection agency costs for the DRT:
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2017 and 2018: at 0.13 per cent.
The AUC directed DERS to use these percentages in its compliance filing and apply them to the updated total revenue figures for 2017 and 2018.
Revenue offsets
Revenue offsets include fees charged by DERS directly to customers for items such as connections, i.e., new accounts and moves, reconnections and dishonored cheques.
The AUC denied DERS’ proposal to eliminate the retailer reconnection fee as of May 1, 2018. The AUC considered that until DERS received approval to eliminate the retailer reconnection fee as part of an application to amend its approved terms and conditions, the retailer reconnection fee was still a valid Commission approved charge that must be applied by DERS in accordance with the approved terms and conditions.
Working capital
The need for working capital is a result of the lag between the payments to suppliers and the receipt of revenues from customers. DERS defined its working capital revenue requirements as “… the carrying costs in support of DERS’ daily operations.”
The AUC approved the results of the lead-lag study and the resulting lag days that DERS used in its calculation of the forecast working capital costs for 2017 and 2018. The AUC considered that the methodology DERS used to forecast its working capital was reasonable and consistent with well established practice in the utility industry in Alberta.
Centralized Corporate Services and Allocation Methodology
Allocation Methodology
Direct Energy (“DE”) allocates corporate service costs to DERS for centralized support and administrative functions received from DE. DERS engaged KPMG LLP (“KPMG”) to undertake a corporate services stand-alone study in late 2015 to establish the total annual costs that would be required to replace the centralized support and administrative functions services received by DERS if DERS was a stand-alone entity.
Corporate services costs were allocated to DERS from DE in two phases. In the first phase, total DE corporate shared service costs are allocated to all DE subsidiaries, divisions, and lines of business (“LOB”) in three steps as outlined below:
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Step 1: Direct charges – removes and assigns costs that can be directly tied to an LOB. This includes costs that directly accrue to an LOB, all operations and depreciation cost centres and all corporate cost centres, which are 80 per cent or higher, attributable to a single LOB.
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Step 2: Driver based charges – includes allocation of remaining corporate shared services costs that can be associated to LOBs based on specific drivers determined by DE. Drivers include head count, per cent time spent on certain activities, and server count.
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Step 3: Indirect allocations – allocation of the remainder of corporate shared services costs are based on modified operating profit, which is an internal DE measure defined as contribution margin less direct charges.
In the second phase, the corporate costs allocated to North American Home in the first phase are then allocated to DERS. For shared service costs that apply to the regulated business, DERS determines if those costs should be allocated using a driver-based methodology or an indirect allocator.
80 percent and 20 percent of DERS’ share of corporate service costs were then allocated to the DRT and the RRT, respectively, based on the split of DRT sites to RRT sites, which has a historic ratio of 80/20.
Based on this allocation method, DERS reported forecast corporate service costs of $4.772 million in 2017 and $4.872 million in 2018.
AUC Findings re Corporate Services Costs and Allocation Methodology
The AUC said that it generally agreed that in large corporate organizations, efficiencies are gained by centralizing certain shared services such as human resources, information technology and finance, which can be shared among subsidiaries and affiliates.
The AUC approved the total amount of corporate costs for 2017 and 2018, given that this was a new corporate costs allocation methodology and DERS provided some explanation concerning the proposed allocators.
The AUC went on to specifically consider DERS’ supporting information for its allocation methodology. The AUC noted its direction from Decision 2957-D01-2015 that DERS “… provide further explanation and details of the actual costs, the rationale to support the cost allocators for each service, the volume of work received by DERS, the mechanism for tracking actual corporate costs and the associated variances in its next DRT and RRT application.”
The AUC found that the level of transparency directed in Decision 2957-D01-2015 had not been provided to its satisfaction. The AUC therefore directed DERS to provide further explanation and details of the actual costs, the rationale to support the cost allocators for each service, the volume of work received by DERS, the mechanism for tracking actual corporate costs and the associated variances in its next DRT and RRT application.
Reasonable Return and Non-Energy Risk Margin
DERS Request for a non-energy risk margin
In requesting a non-energy risk margin, DERS submitted that it has significant risk in respect of its forecast for non-energy costs. DERS defined non-energy risk as the “… risk DERS faces as a result of external factors that create unfavourable and unreasonable exposure to additional costs that could not have been reasonably forecast.” DERS categorized its risks into three areas:
(a) energy price and load,
(b) site attrition, and
(c) unexpected costs (e.g. unforeseen natural disasters such as floods and forest fires).
Commission Findings: Non-energy risk margin
The AUC noted that:
(a) the Regulated Rate Option Regulation expressly provides that reasonable return is to be exclusive of a risk margin pursuant to Section 5(1)(b)(ii); and
(b) there was no similar provision in the Gas Utilities Act or the Default Gas Supply Regulation that requires the setting of a risk margin separate from return, nor is there a prohibition against setting a risk margin separate from the return margin.
The AUC considered that DERS’ application addressed both the DRT and RRT and DERS had chosen to apply for non-energy risk margins for both the default gas supply and the RRO.
The AUC denied DERS’ request for non-energy risk margin revenue for 2017 and 2018 for the DRT and the RRT, based on its finding that all of these risks identified by DERS related to the energy operations of the RRT, and not to the non-energy operations of DERS’ RRT.
The AUC therefore directed DERS, in its compliance filing, to exclude any non-energy risk margin revenue.
DRT reasonable return
Section 6(1)(b)(i) of the Regulated Rate Option Regulation, provides that an RRT must allow for a reasonable return for the obligation on the RRO provider to provide electricity services. As a result, the RRO providers are permitted to charge customers an amount for a reasonable return for service.
Section 5(a) of the Default Gas Supply Regulation provides an equivalent provision with respect to default gas suppliers.
The AUC found that both regulations required it to set a reasonable return.
Reasonable return for DRT
The AUC considered that DERS’ evidence had not sufficiently supported the use of the requested $0.034/GJ figure amount. The AUC found that due to the lack of support for $0.034/GJ, and given the lack of any alternatives, the methodology and percentage approved for 2012-2016 to determine the DRT reasonable return charge should be used for 2017-2018.
