FortisAlberta Inc. 2022 Phase II Distribution Tariff Application July 8, 2021 - Decision 25916-D01-2021
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Decision 25916-D01-2021 FortisAlberta Inc. 2022 Phase II Distribution Tariff Application July 8, 2021
Alberta Utilities Commission
Decision 25916-D01-2021
FortisAlberta Inc.
2022 Phase II Distribution Tariff Application
Proceeding 25916
July 8, 2021
Published by the:
Alberta Utilities Commission
Eau Claire Tower
1400, 600 Third Avenue S.W.
Calgary, Alberta T2P 0G5
Telephone: 310-4AUC (310-4282 in Alberta)
1-833-511-4AUC (1-833-511-4282 outside Alberta)
Email: info@auc.ab.ca
Website: www.auc.ab.ca
The Commission may, within 30 days of the date of this decision and without notice, correct
typographical, spelling and calculation errors and other similar types of errors and post the
corrected decision on its website.Contents
1 Decision summary ................................................................................................................ 1
2 Introduction .......................................................................................................................... 1
2.1 Procedural summary ..................................................................................................... 3
3 Transmission cost allocation ............................................................................................... 4
3.1 Load settlement data ..................................................................................................... 7
3.2 Line loss studies ............................................................................................................ 8
3.3 Transmission billing capacity and energy forecast ....................................................... 9
4 Distribution cost allocation ................................................................................................. 9
4.1 Use of customer metering data (such as metered demand or energy) to determine
customer peak demands instead of transformer size................................................... 11
4.2 The operation and use of the property retirement unit multiplier study ..................... 13
4.3 Sub-functionalizing costs between shared system and local facilities ........................ 17
4.4 Allocation of metering costs ....................................................................................... 20
4.5 Calculation and allocation of the farm transmission amounts .................................... 21
4.6 Reallocation of costs between small capacity customer rate classes .......................... 24
5 Rate design and bill impacts ............................................................................................. 26
5.1 Bill impacts and revenue-to-cost ratios....................................................................... 26
5.2 Customer rate classes .................................................................................................. 28
5.3 Other rate design proposed changes ........................................................................... 30
5.4 Billing determinants forecast methodology ................................................................ 33
6 How should the costs attributable to integrated operations with REAs be treated in
Fortis’s distribution tariff? ............................................................................................... 34
6.1 Fortis’s costs that are attributable to integrated operations with REAs ...................... 36
6.1.1 Accuracy and completeness of data on REA-owned assets used in the CAM
model............................................................................................................... 38
6.1.2 Determination of costs associated with integrated operations with REAs ..... 41
6.2 Are there integrated operation-related costs that should not be borne by Fortis’s
customers?................................................................................................................... 43
6.2.1 Why is this an issue in this proceeding? ......................................................... 43
6.2.2 Analysis........................................................................................................... 44
6.3 When should these costs be removed from Fortis’s regulated revenue requirement? 52
7 Terms and conditions ........................................................................................................ 53
7.1 Compliance with prior Commission directions .......................................................... 54
7.2 Security requirements ................................................................................................. 55
7.3 Quotation package ...................................................................................................... 56
7.4 Easements ................................................................................................................... 58
7.5 PILON and customer exit provisions.......................................................................... 58
7.5.1 Transmission PILON ...................................................................................... 60
7.5.2 Distribution PILON ........................................................................................ 61
7.6 Adjustments of bills in the event of a billing error ..................................................... 62
Decision 25916-D01-2021 (July 8, 2021) i8 Order ................................................................................................................................... 64
Appendix 1 – Proceeding participants ...................................................................................... 65
Appendix 2 – Oral argument and reply argument – registered appearances ....................... 67
Appendix 3 – Summary of proceeding process ........................................................................ 68
Appendix 4 – Summary of Commission directions.................................................................. 69
List of figures
Figure 1. Conductors on a transformer service pole.............................................................. 16
Figure 2. Sub-functionalization into three distribution cost components ............................ 18
Figure 3. Feeder 542S-2002L, Ownership Map...................................................................... 35
List of tables
Table 1. 2021 transmission access cost forecast ...................................................................... 5
Table 2. Summary of transmission cost allocation for distribution-connected load ........... 6
Table 3. Transformer on-peak utilization factors by rate class .......................................... 11
Table 4. Property retirement unit values for line components ............................................ 14
Table 5. Property retirement unit multipliers ...................................................................... 15
Table 6. Summary description of Fortis’s proposed approach to sub-functionalization for
its distribution system costs...................................................................................... 17
Table 7. Typical bill impacts by rate class (proposed 2021 PBR rates vs. annual 2021 PBR
rates) ........................................................................................................................... 26
Table 8. Range of revenue-to-cost ratios and corresponding bill impacts, with removal of
the proposed cost reallocation between small capacity rate ................................. 28
Table 9. Proposed transmission rate structures by component .......................................... 30
Table 10. Weighting between fixed and variable transmission charges (existing vs.
proposed) ................................................................................................................... 31
Table 11. Proposed distribution rate structures by component and proposed changes ..... 31
Table 12. Weighting between fixed and variable distribution charges (existing vs.
proposed) ................................................................................................................... 32
Decision 25916-D01-2021 (July 8, 2021) iiTable 13. Fortis’s costs that are attributable to REAs as a result of integrated operations 37
Table 14. Change in cost allocation results for feeder 542S-2002L after correction of errors
..................................................................................................................................... 40
Table 15. Amount charged under Fortis’s PILON provisions compared to notice period
enforced...................................................................................................................... 59
Table 16. Amount of kW reductions due to customers downsizing or salvaging their
connection .................................................................................................................. 60
Table 17. Number of customers that neither provided adequate notice nor paid the PILON
charges ....................................................................................................................... 60
Decision 25916-D01-2021 (July 8, 2021) iiiAlberta Utilities Commission
Calgary, Alberta
FortisAlberta Inc. Decision 25916-D01-2021
2022 Phase II Distribution Tariff Application Proceeding 25916
1 Decision summary
1. This decision provides the Alberta Utilities Commission’s determinations on
FortisAlberta Inc.’s Phase II application. At a high level, the Commission approves Fortis’s
proposals on the following, subject to certain modifications outlined in this decision:
• Transmission cost allocation
• Distribution cost allocation
• Rate design
2. The Commission does not approve Fortis’s proposals on the following:
• Reallocation of shared system costs among small capacity rate classes
• Revenue-to-cost ratios and resulting bill impacts
• Terms and conditions
3. With respect to the distribution costs related to rural electrification associations (REAs),
the Commission finds that the costs attributable to serving REAs, as described in Section 6,
should be addressed under the integrated operating agreements (IOAs). With the exception of
load settlement costs attributable to and recovered from REAs, REA farm transmission credits,
and the REA distribution system use credit, REA-related costs must be removed from the rates
charged to Fortis’s distribution customers at the time of its 2023 cost-of-service application. In
addition, the Commission directs Fortis to return any costs attributable to REAs that it recovers
under the IOAs dollar-for-dollar, by a Y factor during the remainder of the current performance-
based regulation (PBR) period.
4. Fortis is directed to submit its compliance filing to reflect the determinations in this
decision on or before September 8, 2021.
2 Introduction
5. Fortis requires revenue to pay for the costs it incurs in operating its electric distribution
business, as well as the costs and charges imposed on it for accessing the electric transmission
system. Fortis obtains this revenue from its distribution tariff. A distribution tariff specifies the
Decision 25916-D01-2021 (July 8, 2021) 12022 Phase II Distribution Tariff Application FortisAlberta Inc.
rates charged to each customer rate class for service as well as the terms and conditions of
service.1 Fortis must apply to the Commission for approval of its distribution tariff.
6. Setting customer rates in a distribution tariff involves two phases.
7. In Phase I, the Commission determines a utility’s total revenue requirement.2 A revenue
requirement is the total costs the utility incurs to provide service to its customers. It includes
transmission and distribution costs. Transmission costs are what Fortis must pay, on behalf of its
customers, to the Alberta Electric System Operator (AESO) for transmission service.
Distribution costs are the costs Fortis incurs to construct and operate its electric distribution
system.
8. In Phase II, the Commission approves the methodology to allocate the total revenue
requirement to various groups of customers (referred to as customer rate classes). These cost
allocations are then used to inform how to structure the charges (i.e., rate design) customers are
billed for utility service so that, when aggregated across all of its customers, the utility collects
its revenue requirement. The Commission also approves the rate design in Phase II.
9. It is generally accepted that there is no single correct rate design for a given utility or its
customers when it comes to distribution tariffs because a number of rate design principles must
be taken into account. These principles are often summarized as:
• Cost causation. Meaning customers pay utility bills that reflect the costs of providing
utility service to that customer.
• Non-distortion. Meaning utility rates set effective price signals to allow customers to
efficiently determine how much utility service to consume, leading to economically
efficient outcomes.
• Cost recovery. Meaning the utility is afforded a reasonable opportunity to recover its
prudently incurred costs (i.e., revenue requirement).
• Avoidance of undue discrimination. Meaning similar customers are treated similarly,
dissimilar customers are treated dissimilarly, and all customers are treated justly. This
is sometime referred to as fair apportionment of costs.
• Predictability. Meaning customers’ bills will not fluctuate over time beyond a
reasonable level. This is referred to in this decision as bill impacts.
1
Terms and conditions of service govern the relationship between the owner of the electric distribution system
and its eligible customers for electricity service, and are the regulatory equivalent of contract terms and
conditions between the utility and its customers. The Commission typically approves the terms and conditions
of service in Phase II proceedings as they are a key component of a utility’s distribution tariff (see the Electric
Utilities Act, Section 1(1)(zz) and (aaa)).
2
Fortis’s revenue requirement for this application is generally established under the PBR plan approved for the
2018-2022 term in Decision 20414-D01-2016 (Errata): 2018-2022 Performance-Based Regulation Plans for
Alberta Electric and Gas Distribution Utilities, Proceeding 20414, February 6, 2017, amending the decision
issued December 16, 2016.
Decision 25916-D01-2021 (July 8, 2021) 22022 Phase II Distribution Tariff Application FortisAlberta Inc.
• Transparency and simplicity. Meaning customers know what they are paying and why
they are paying it.3
10. In discharging its duty to set just and reasonable rates, the Commission must balance
these often competing and contradictory principles within the context of the particular rate
design application.
11. In this proceeding, the central issues the Commission must determine are:
• Whether Fortis’s proposed transmission cost allocation and resulting percentages
provide for a just and reasonable allocation of Fortis’s transmission access costs among
its customer rate classes and rural electrification associations (REAs) interconnected
with its distribution system. This is addressed in Section 3.
• Whether Fortis’s proposed distribution cost allocation and resulting percentages
provide for a just and reasonable allocation of Fortis’s distribution costs among its
customer rate classes and REAs interconnected with its distribution system. This is
addressed in Section 4.
• Whether Fortis’s proposed rate design and bill impacts, resulting from Fortis’s
transmission and distribution cost allocations, balance the rate design principles and
provide for just and reasonable rates. This is addressed in Section 5.
• Whether Fortis’s proposed terms and conditions of service are just and reasonable. This
is addressed in Section 7.
12. Fortis’s service area overlaps with the service areas of certain REAs, who provide
electrical service to their cooperative members. In determining the issues with respect to Fortis’s
distribution cost allocation and rate design, the Commission had to determine:
• Whether there are costs Fortis incurs as a result of integrated operations with REAs that
should not be borne by Fortis’s customers through its distribution tariff.
• If confirmed, when and how these costs should be removed from the rates charged to
Fortis’s distribution customers.
These issues are addressed in Section 6.
2.1 Procedural summary
13. Fortis had previously filed a Phase II application in 2020 under Proceeding 25201. In that
prior application, Fortis proposed an REA-specific charge to recover 50 per cent of its allocated
net distribution costs associated with the distribution systems that Fortis and the REAs own and
operate on an integrated basis. In view of the Commission’s ruling that it did not have the
authority to approve the proposed new charge as part of Fortis’s distribution tariff, Fortis
withdrew its Phase II application and sought permission to appeal the Commission’s ruling at the
3
Bonbright et al., Principles of Public Utility Rates, Second edition, page 383, as summarized in
Proceeding 24116, Distribution System Inquiry – Final Report, February 19, 2021, paragraph 322.
Decision 25916-D01-2021 (July 8, 2021) 32022 Phase II Distribution Tariff Application FortisAlberta Inc.
Alberta Court of Appeal. An appeal of this ruling was dismissed by the Alberta Court of Appeal
on July 14, 2020.4
14. Fortis filed the present Phase II application on October 19, 2020. In doing so, Fortis has
complied with the Commission’s direction to file its revised application 90 days after the receipt
of the Alberta Court of Appeal’s decision.5
15. The following parties intervened in the proceeding:6
• Alberta Federation of Rural Electrification Associations (AFREA)
• Battle River Power Co-op
• Consumers’ Coalition of Alberta (CCA)
• EQUS REA LTD.
• Energy Associates International, representing the municipalities of Canmore and
Cochrane7
• Office of the Utilities Consumer Advocate (UCA)
• Rocky REA Limited
16. In reaching the determinations set out within this decision, the Commission has
considered all relevant materials comprising the record of this proceeding. Accordingly,
references in this decision to specific parts of the record 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 the record with
respect to that matter.
3 Transmission cost allocation
17. Fortis must pay, on behalf of its customers, for transmission service provided by the
AESO. The Commission must determine whether Fortis’s proposed transmission cost allocation
and percentages provides for just and reasonable rates. In this exercise, Fortis treats its
transmission access costs separately from its distribution costs. Transmission access costs are
determined by the AESO’s charges plus payments to DCG (distribution-connected generation)
under Option M.8 Fortis allocates these transmission charges to its customer rate classes, which
are billed for these costs according to a methodology set out in its application.
18. For the reasons that follow, the Commission finds that Fortis’s proposed transmission
cost allocation methodology is just and reasonable, and is approved subject to certain
modifications identified in this section of the decision.
4
FortisAlberta Inc v Alberta (Utilities Commission), 2020 ABCA 271.
5
Proceeding 25201, Exhibit 25201-X0071, Ruling on Fortis’s request to withdraw Application 25201-A001.
6
A summary of the proceeding schedule is provided in Appendix 3.
7
Exhibit 25916-X0082, Municipal participants, December 4, 2020.
8
Fortis’s provision of DCG credits via Option M in its distribution tariff was addressed in a separate module to
this proceeding, and decided in Decision 26090-D01-2021.
Decision 25916-D01-2021 (July 8, 2021) 42022 Phase II Distribution Tariff Application FortisAlberta Inc.
19. A summary of Fortis’s 2021 transmission access cost forecast is provided in Table 1.9
The costs associated with serving the distribution-connected load is $661.6 million and is the
amount that requires methodological steps to allocate those costs to customers. The remaining
amount of $211.8 million is directly assigned to specific customers that are directly connected to
the transmission system. These latter costs are not at issue in this proceeding as they represent a
direct flow through of the AESO tariff structure and charges to customers connected to the
transmission system.
Table 1. 2021 transmission access cost forecast
($ million)
Distribution-connected load (AESO charges plus Option M) 656.6
Distribution-connected load (Interchange) 4.9
Total distribution-connected load 661.6
Transmission-connected load (Rate 65 flow-through) 211.8
Total transmission access costs 873.4
Source: Exhibit 25916-X0121, Attachment FAI-AUC-2021JAN15-001.01.
20. Fortis’s methodology to allocate the $661.6 million is summarized in Table 2. Fortis
explained that transmission access costs are sub-functionalized (column A) according to how
they are classified in the AESO tariff (column B). Fortis does its own classification (column C).
This change in classification (from AESO’s tariff to Fortis’s tariff) is required, in most cases, due
to constraints imposed by less sophisticated meters installed at customer sites and other rate
design considerations.10 Fortis then allocates its transmission costs to its customer rate classes
and REA wire owners (column D).
9
Fortis provided an updated 2021 transmission access cost forecast to account for an updated Balancing Pool
charge to align with the AESO’s Rider F rate of $2.30 per megawatt hour approved in Decision 26040-D01-
2020: Alberta Electric System Operator, 2021 Balancing Pool Consumer Allocation, Rider F Application,
Proceeding 26040, December 2, 2020; and the 2021 Independent System Operator tariff structure and rates
approved in Decision 26054-D01-2020: Alberta Electric System Operator, 2021 Independent System Operator
Tariff Update, Proceeding 26054, December 18, 2020.
10
Exhibit 25916-X0001, application, paragraph 166.
Decision 25916-D01-2021 (July 8, 2021) 52022 Phase II Distribution Tariff Application FortisAlberta Inc.
Table 2. Summary of transmission cost allocation for distribution-connected load
AESO tariff billing components AESO tariff billing Fortis’s classification of Fortis’s allocation method
(i.e., becomes Fortis’s sub- determinants transmission charges
functionalization)
[A] [B] [C] [D]
Bulk system demand charges Coincident system peak Monthly non-coincident Rate class forecast monthly
demand peak demand coincident peak demand, based
on 3-year average of historical
load settlement data
Billing capacity and point of delivery Per POD billing Annual non-coincident Rate class forecast monthly non-
(POD) charges capacity11 peak demand coincident peak demand, based
on three-year average of
historical load settlement data
and ratcheted to 90 per cent (to
align with the AESO’s per billing
capacity charges)
Metered energy charges (including Metered energy Metered energy Rate class forecast metered
the DTS tariff’s Bulk System, Local energy
System, Operating Reserve, and
Voltage Control Metered Energy
charges)
Other transmission charges Monthly capacity and Metered energy Rate class percentage of total
(including Demand Under- metered energy demand transmission services
Frequency Load Shedding Credit charges
and Interchange costs)
Source: Exhibit 25916-X0001, application, paragraphs 97-103, 108-116, and Exhibit 25916-X0121, Attachment FAI-AUC-2021JAN15-001.01.
21. The Commission observes that Fortis’s transmission cost allocation methodology is
consistent with the methods previously approved in Decision 2014-018,12 with the exception of
the methodology used to allocate billing capacity and point of delivery (POD)13 charges to
Rate 63 – Large General Service customers.14
22. In Decision 2014-018, the Commission directed Fortis to examine the costs and benefits
of using a POD-specific allocation based on hourly load data rather than load profiles for all rate
classes.15
23. In response to this direction, Fortis proposed a methodology change and applied a POD-
specific allocator to Rate 63 customers to allocate the billing capacity and POD charges. Fortis
stated that Rate 63 was chosen for the POD-specific allocation because it is the only rate class
where interval metering data is available for all sites. 16 Fortis reported that the benefits of using a
11
The AESO’s billing capacity means, at a point of delivery, the highest of: (i) the highest 15-minute metered
demand in the settlement period; (ii) 90 per cent of the highest metered demand in the 24-month period,
including and ending with the settlement period, but excluding any months during which commissioning
occurs; or (iii) 90 per cent of the contract capacity or when the settlement period contains a transaction under
Rate Demand Opportunity Service, 100 per cent of the contract capacity.
12
Decision 2014-018: FortisAlberta Inc., 2012-2014 Phase II Distribution Tariff, Proceeding 2363,
Application 1609211-1, January 27, 2014.
13
In its tariff, the AESO refers to a substation as a point of delivery (POD).
14
Exhibit 25916-X0001, application, paragraph 106.
15
Decision 2014-018, paragraphs 111-112.
16
Exhibit 25916-X0017, Appendix J, paragraph 5.
Decision 25916-D01-2021 (July 8, 2021) 62022 Phase II Distribution Tariff Application FortisAlberta Inc.
POD-specific allocation based on hourly load data for Rate 63 customers exceeds the cost of
doing so.
24. For all the other rate classes, Fortis maintained that using a three-year average of load
settlement data applied across all PODs, continues to be the most practical approach to develop
cost allocators for each rate class. Fortis explained that by using this load settlement data, it
essentially is using the best available hourly data to allocate transmission costs. Fortis explained
that using hourly load data for all other rate classes did not meaningfully improve the accuracy of
the results, as the data required is not readily available and as it is time consuming to generate
the results.17
25. The Commission finds that Fortis has complied with its direction to examine the costs
and benefits of using a POD-specific allocation based on hourly load data rather than load
profiles for all rate classes.
26. The Commission approves Fortis’s proposal to incorporate a POD-specific allocator for
Rate 63 customers and maintain the status quo for all other customer rate classes. The
Commission finds that a POD-specific allocation based on hourly load data is more precise and
better reflects cost causation in general, and it is reasonable for Fortis to adopt this approach for
Rate 63 customers because the benefits of doing so exceeds the costs. This will contribute to
setting rates more reflective of the underlying costs caused by Rate 63 customers. For all other
customers, the Commission finds that Fortis’s use of its previously approved methodology
continues to be a valid approach for cost allocation because it supports cost recovery, while
being cost effective and not upsetting the balancing of the other rate design principles (such as
non-distortion, non-discrimination, transparency, predictability and simplicity).18
27. Through the course of the proceeding, several additional issues related to Fortis’s
transmission cost allocation methodology arose, which the Commission addresses in the
remainder of Section 3.
3.1 Load settlement data
28. Returning to the summary provided in column D of Table 2, Fortis uses historical load
settlement data to develop its allocation methodology for all rates classes (except for Rate 63
customers). In past Phase II applications, the Commission approved Fortis’s methodology of
using a three-year average of the load settlement data. In this proceeding, Fortis applied an
average of 2017 to 2019 load settlement data to allocate 2021 transmission access costs. The
Commission finds that Fortis’s methodology of using a three-year average continues to be just
and reasonable; however, the issue remains as to which three years to use that would be most
appropriate for the purposes of transmission cost allocation.
29. Fortis based its application on the most up-to-date data that it had available. Fortis stated
that 2020 load settlement data would be available in the second quarter of 2021, and that it was
open to incorporating this data.19
30. The Commission finds that 2020 load settlement data would better reflect the changes in
load due to the COVID-19 pandemic and the economic downturn for transmission cost allocation
17
Exhibit 25916-X0017, Appendix J, paragraph 5.
18
Proceeding 24116, Distribution System Inquiry – Final Report, February 19, 2021, paragraph 322.
19
Exhibit 25916-X0122, FAI-AUC-2021JAN15-003(a) and (c).
Decision 25916-D01-2021 (July 8, 2021) 72022 Phase II Distribution Tariff Application FortisAlberta Inc.
purposes. This is consistent with the Commission’s practice of using the most up-to-date
information to set rates, if available.20 The Commission directs Fortis to update its schedules to
reflect the most recent 2018 to 2020 load settlement data as a part of its compliance filing to this
application.
3.2 Line loss studies
31. Fortis is required to complete distribution line loss studies for load settlement purposes
from time to time, to be in compliance with Rule 021: Settlement System Code Rules.
Distribution line losses account for the difference between (i) the amount of energy delivered to
the distribution system from the transmission system and (ii) the amount of energy delivered to
customers. Distribution line losses do not directly affect transmission cost allocation, but they
must be completed from time to time as part of Fortis’s distribution tariff application.
32. An updated line loss study was not provided by Fortis in this proceeding.21 Instead, Fortis
relied on its 2010 line loss study approved in Decision 2010-329.22 23
33. Fortis stated that line loss studies require a significant undertaking with expert personnel,
computer modelling, and various system studies. Fortis maintained that an updated line loss
study would not produce significantly different results from its 2010 line loss study for rate
classes, other than for the lighting rate classes. In support of this statement, Fortis identified that
its unaccounted-for energy24 continues to remain at a very low level (less than half a per cent)
over the last five years, thereby representing reasonable line loss factors, accurate estimation of
unmetered load consumption, and minimum energy theft.25
34. Fortis did state that it may be reasonable to provide a limited line loss study for the
lighting rate classes since LED streetlights have now been widely deployed across its system and
they use much less electricity. Due to the significant costs and amount of resources required,
Fortis did not support an update to its line loss study for the remaining rate classes at this time. 26
35. The Commission finds it reasonable for Fortis to rely on the results of its 2010 line loss
study for the purposes of this application, but finds it necessary for Fortis to provide an updated
line loss study for all of its rate classes in its next Phase II application. Significant time has
passed since Fortis has completed a line loss study. It is well established that customer use of
electricity is changing, which includes the result of new technologies being adopted. The
deployment of LED streetlights is a prominent example of new technology changing customer
usage patterns, but there may be others of significance. Therefore, the Commission directs Fortis
to provide an updated study of line losses for all rate classes in its next Phase II application.
20
See for example: Decision 2006-024: ATCO Electric Ltd., 2005-2006 General Tariff Application,
Proceeding 14712, Application 1399997-1, March 17, 2006, page 6; Decision 2014-138: ENMAX Energy
Corporation, 2012-2014 Regulated Rate Option Non-energy Tariff, Proceeding 2069, Application 1608745-1,
May 23, 2014, paragraph 48.
21
Exhibit 25916-X0081.01, Virtual technical meeting presentation, PDF pages 16-18.
22
Decision 2010-329: FortisAlberta Inc., 2010 Phase II, Proceeding 362, Application 1605580-1, July 22, 2010.
23
The 2010 line loss study was filed as Exhibit 25916-X0119.
24
Unaccounted-for energy is the difference between metered energy at the transmission POD minus metered
energy at the customer meter minus calculated losses.
25
Exhibit 25916-X0122, FAI-AUC-2021JAN15-002(a) and (c), and Exhibit 25916-X0081.01, Technical meeting
presentation, PDF pages 17-18.
26
Exhibit 25916-X0122, FAI-AUC-2021JAN15-002(a).
Decision 25916-D01-2021 (July 8, 2021) 82022 Phase II Distribution Tariff Application FortisAlberta Inc.
3.3 Transmission billing capacity and energy forecast
36. Fortis’s transmission cost allocation methodology takes into account forecast monthly
billing capacity and forecast monthly energy. EQUS REA submitted that some irregularities
exist for the billing capacity and energy forecast for two rate classes: exterior lighting and
irrigation. EQUS stated that months with the highest energy consumption should have the
highest billing capacity. However, this trend was not observed for the exterior lighting and
irrigation rate classes. Instead, months with the highest energy consumption had the lowest
billing capacity.
37. As an example, in Fortis’s transmission cost allocation schedules, the irrigation rate class
experienced the highest energy consumption from May to September, with July being the highest
projected energy consumption of the year. However, the billing capacity was the lowest in July,
yet peaked in September. Similarly, the exterior lighting rate class experienced the highest
billing capacity in June, yet minimal energy consumption was forecast in that month.27
38. Fortis explained that these irregularities arise due to its allocation methodology described
in Table 2. Fortis is billed by the AESO on a POD basis, and these charges are allocated to the
customer rate classes using percentage allocators. This means if billing capacity fluctuates at the
POD month-to-month, but a particular customer rate class’s billing capacity is relatively stable
(e.g., exterior lighting), then the amount allocated to that rate class will also fluctuate because it
is a percentage of the total. Therefore, the allocation of monthly billing capacity for any given
rate class is not only a function of the monthly 90 per cent ratcheted non-coincident peak (NCP)
for that rate class, but is also dependent on the monthly 90 per cent ratcheted NCPs for all other
rate classes, aggregated at the POD level.28
39. While the Commission understands the logic behind Fortis’s use of the allocators and
how they cause the seemingly anomalous results to arise, the Commission also sees merit in
EQUS’s concern. It appears counter to the principle of cost causation that cost allocation to a
customer rate class varies with the energy use and demand of other rate classes. The Commission
directs Fortis to re-examine its forecasting methodologies for its rate classes, and propose any
changes in the forecasting methodology to account for the irregularities for the exterior lighting
and irrigation rate classes, and any other similarly impacted rate classes, in its next Phase II
application.
4 Distribution cost allocation
40. Similar to the previous section, but now turning to distribution costs (rather than
transmission access costs), the Commission must determine whether Fortis’s proposed
distribution cost allocation methods and cost allocation percentages provide for a just and
reasonable allocation of Fortis’s distribution revenue requirement among its customer rate
classes and REAs interconnected with its distribution system.29 One of the key attributes of a
sound rate structure is fairness of the apportionment of total costs of service among the different
27
Exhibit 25916-X0120, schedule 4.2-E, monthly billing capacity, lines 12-13; schedule 4.2-F, monthly energy,
lines 12-13.
28
Exhibit 25916-X0126, FAI-EQUS-2021JAN15-005(a).
29
Fortis’s proposed amounts and percentages were provided in Exhibit 25916-X0021, 2017 Distribution Cost
Allocation Study, Schedule 2.1-B.
Decision 25916-D01-2021 (July 8, 2021) 92022 Phase II Distribution Tariff Application FortisAlberta Inc.
ratepayers.30 This relates to the principles of setting rates that reflect cost causation and avoiding
undue discrimination. Broadly speaking, if a customer caused the costs, that customer should pay
for those costs.
41. Fortis’s distribution cost allocation study relied on results obtained from Fortis’s
Component Analysis Method (CAM) model to allocate the majority of Fortis’s distribution
system costs. At a high level, the CAM model analyzes the individual components in a
distribution feeder,31 and allocates each component (or segment of feeder) to the customers
served downstream of that component.32 When there are multiple downstream customers served
from a single component, the component is proportioned to each downstream customer based on
each customer’s estimated annual average on-peak demand, as further explained below. The data
inputs used in the model (discussed in sections 4.1 and 4.2 of this decision) include where
customers are located, their estimated on-peak demand, the connectivity of each component with
one another, attributes for each component, and the costs of the individual distribution system
components. Fortis’s CAM model informs significant aspects of Fortis cost allocation study,
including how cost components are sub-functionalized (partially discussed in Section 4.3) and
then allocated (partially discussed in sections 4.4 to 4.6).
42. In this application, Fortis expanded its CAM model to include, for the first time, all of its
distribution feeders, whereas previously its CAM model only included a sample of feeders.33
43. The Commission has reviewed the cost allocation study submitted by Fortis as well as the
filings submitted by interveners, and with the exception of certain aspects of the study discussed
below, the Commission approves the cost allocation study as filed. This is because the CAM
model methodology, as filed in this application, remains relatively unchanged from what has
been approved in previous applications. In addition, the Commission finds that the accuracy of
the CAM model results has been improved compared to previous Phase II applications by virtue
of Fortis including all feeders in the model, rather than a sample.
44. The Commission’s directions in this section with respect to the CAM model are provided
to further refine the CAM model, and assess the changes Fortis has made since its last approved
Phase II.
45. As part of allocating its distribution system costs to its customers, Fortis also allocated
costs to REAs interconnected with Fortis’s system, although Fortis did not apply to charge REAs
for these allocated costs. Having modelled all of its feeders, including those serving REAs, Fortis
was able to more accurately allocate the costs attributable to REAs than in its previous Phase II
applications. As part of the Commission’s review of Fortis’s cost allocation study, the
Commission has determined that the methodology used by Fortis to allocate costs to REAs is
reasonable for the purposes of its application in this proceeding. The Commission’s reasons for
30
Bonbright et al., Principles of Public Utility Rates, Second Edition, page 383.
31
Distribution feeders are composed of the power lines (underground or overhead), transformers, and related
components through which electricity is normally supplied from a single source (typically a medium voltage
breaker at a substation) to customers.
32
Exhibit 25916-X0015, application, Appendix H - Review of Component Analysis Method CAM Model,
paragraph 15.
33
Exhibit 25916-X0015, application, Appendix H - Review of CAM Model, paragraphs 9-10.
Decision 25916-D01-2021 (July 8, 2021) 102022 Phase II Distribution Tariff Application FortisAlberta Inc.
this determination are provided separately in Section 6.1 of this decision due to the related nature
of the other issues addressed in Section 6.
4.1 Use of customer metering data (such as metered demand or energy) to determine
customer peak demands instead of transformer size
46. To allocate the cost of a distribution system component that serves multiple customers,
Fortis’s CAM model uses each customer’s average on-peak demand.34 A customer’s average on-
peak demand is calculated based on the customer’s transformer size (or allocated portion for
shared transformers) and its rate class specific transformer on-peak utilization factor, rather than
actual individual customer metering data.
47. The transformer on-peak utilization factors are themselves calculated based on the
average total on-peak demand for each rate class (derived from load settlement data for the
period 2014-201635) divided by the total capacity (i.e., kilovolt ampere (kVA)) of all
transformers used by each rate class.36 When calculating the total capacity of all transformers
used by a rate class, transformers that serve multiple rate classes were proportioned among each
customer/rate class based on each connected customer’s rate class specific average on-peak
demand per site.37
48. Table 3 shows the transformer on-peak utilization factors calculated by Fortis.
Table 3. Transformer on-peak utilization factors by rate class
On-peak utilization factor
Rate class
(%)
Residential - Rate 11 19.7
Farm - Rates 21 and 22 15.2
Irrigation - Rate 26 3.4
Small General Service - Rate 41 12.3
Oil and Gas - Rate 45 17.6
General Service - Rate 61 21.6
Large General Service - Rate 63 22.9
REA Wire Owners 15.2
Source: Exhibit 25916-X0016, Appendix H - Review of CAM Model, paragraph 49, Table 10.
49. The CAM model uses the calculated transformer on-peak utilization factors, along with
the size of transformer each customer is connected to, to calculate each customer’s average on-
peak demand. By this method, every customer of the same rate class with the same transformer
size (assuming a dedicated transformer) will be assumed to have the same average on-peak
demand. For example, every residential customer served from a 10 kVA transformer (with no
other classes of customers served from that transformer) will have a calculated average on-peak
demand of 1.97 kilowatts (kW). This means that the customer’s on-peak demand used in the
CAM model is not dependent on its actual metered values that were used for billing.
34
“On-peak” means the period of time from 8 a.m. to 9 p.m., inclusive, during each business day throughout the
year. For more details, see Decision 2006-099, page 25.
35
Exhibit 25916-X0015, application, Appendix H - Review of CAM Model, paragraph 48.
36
Exhibit 25916-X0015, application, Appendix H - Review of CAM Model, paragraph 47.
37
Exhibit 25916-X0212, FAI-AUC-2021MAR08-003.
Decision 25916-D01-2021 (July 8, 2021) 112022 Phase II Distribution Tariff Application FortisAlberta Inc.
50. Fortis was of the view that customer on-peak demands calculated based on transformer
sizes are more appropriate for cost allocation than actual metering data. Fortis submitted that
installed transformer sizes reflect the capacity requirements of the site when the service was
installed, and metered demands may not reflect long-term usage of the site and could vary
significantly over time (i.e., between cost allocation studies), creating volatility in the CAM
model’s results between different study periods.38 Additionally, Fortis explained that when
completing system planning, it uses transformer sizes to allocate a feeder’s load rather than
meter readings for non-interval metered customers.39 Fortis also submitted that using customer
metering data in the CAM model to determine peak demands, rather than transformer sizes,
could take one or more person-years of experienced staff or consultants’ time to implement even
for a single sample feeder.40 In Fortis’s view, this approach would theoretically be more precise,
but may ultimately result in similar cost allocation results.41
51. Rocky REA was of the view that the CAM model’s lack of use of actual customer usage
data results in a disconnect between changes in an individual customer’s consumption and the
proportion of shared system costs allocated to that customer.42 Rocky REA contended that if
Fortis’s CAM model does not contain actual customer usage data, then it could not be used to
undertake the type of analysis required to complete a regrouping of customers into different
customer rate classes, such as the capacity-based rate classes that Fortis envisions it will need to
move to over time (as discussed further in Section 4.6).43 When questioned by the Commission
as to what inaccuracies could result from Fortis’s approach, Rocky REA submitted that
inaccuracies may arise because the CAM model allocates costs at the individual feeder level,
rather than at a broad utility level. Rocky REA submitted that to assess the magnitude of the
impact, an analysis would need to be completed on some subset (or sample) of feeders. Until that
analysis is done, the accuracy of the current CAM model remains unknown, and any changes in
allocations based on this model may prove to be materially incorrect.44
52. The Commission does not agree with Rocky REA’s assertion that no customer usage data
was used in the CAM model. This is because aggregate load settlement data was used to
calculate the transformer utilization factors for each rate class. These transformer utilization
factors were then used to estimate each customer’s consumption. However, Rocky REA seems to
be arguing for actual, per customer, load settlement data to be used. The Commission agrees with
Rocky REA that Fortis’s approach has not been quantitively assessed to ascertain how the results
produced by their method compare to the more accurate results that would be obtained from
using actual individual customer load settlement data to determine their average on-peak
demands. The Commission also agrees with Rocky REA that the current approach may not be
suitable if the CAM model is to be used to analyze the appropriateness of future regroupings of
customers into different rate classes, as the utilization factors themselves are dependent on how
customers have been grouped into different rate classes. In the Commission’s view, performing
such an analysis for a small sample number of feeders would not be as onerous as Fortis has
suggested. From the information filed, the CAM models are generally a collection of Excel
spreadsheets (with additional back-end visual basic programming) for each feeder, with the
38
Exhibit 25916-X0081.01, Virtual technical meeting presentation, PDF page 31.
39
Exhibit 25916-X0087, Virtual technical meeting summary notes, paragraph 17.
40
Exhibit 25916-X0122, FAI-AUC-2021JAN15-011(c).
41
Exhibit 25916-X0122, FAI-AUC-2021JAN15-011(a).
42
Exhibit 25916-X0172, Rocky REA - VIDYA Evidence, PDF pages 21-22.
43
Exhibit 25916-X0172, Rocky REA - VIDYA Evidence, PDF page 23.
44
Exhibit 25916-X0206, ROCKY-AUC-2021MAR08-001.
Decision 25916-D01-2021 (July 8, 2021) 122022 Phase II Distribution Tariff Application FortisAlberta Inc.
average on-peak demand values contained in columns for each customer.45 It should not be
overly onerous to complete an analysis for a small sample of feeders, where these values are
substituted with those determined using another method (such as being derived from load
settlement data) and observe what effect it has on the results. When the Commission provided
Fortis its understanding of the necessary steps to complete such an analysis, and asked Fortis if
the steps provided were accurate, Fortis submitted it was unable to provide a response.46
53. In view of the above, in order to further establish the accuracy of the method, the
Commission directs Fortis in its next Phase II application to complete an analysis and
comparison of the CAM cost allocation results, on a sample of 10 feeders, using actual load
settlement data. The Commission considers that completing the analysis for the feeders for which
Fortis has supplied working CAM models in this proceeding (namely 28S-2057L, 131S-412LW,
320P-350L, 821S-2895T, 602S-2077L, 55S-2007L, 191S-338LN, 217S-366L, 235S-478LW and
385S-112LS) should be sufficient to provide insights into any differences that arise, while not
being onerous to complete.
4.2 The operation and use of the property retirement unit multiplier study
54. As discussed above, Fortis’s CAM model allocates each of the main components in
Fortis’s distribution system to the customers served by those components. Fortis then determines
several different costs associated with these allocated components. The costs determined by
Fortis include replacement cost new (RCN), original cost and accumulated depreciation.47 The
first cost Fortis determines is RCN. Fortis then uses a distribution price index, data on asset
vintages, and its depreciation parameters, to determine the original cost and accumulated
depreciation amounts.48 These costs are then used to derive allocators, such as for return and
depreciation, that are used in Fortis’s cost allocation study.
55. Fortis calculates property retirement unit values and then uses these values as the
assumed RCN values for each component. The property retirement unit values are calculated
based on a three-year average of the unit costs to construct the components in each property unit
type. The table below illustrates the property retirement unit values for line components used in
the CAM model.
45
See for example Exhibit 25916-X0023, CAM Working Model 131S-412LW, sheet “5 Input - Tx & Cust,”
column “Calculated Avg. Customer On-Peak kW.”
46
Exhibit 25916-X0122, FAI-AUC-2021JAN15-011(c).
47
Exhibit 25916-X0021, 2017 Distribution Costs Allocation Study, Schedule 2.1-G1.
48
Exhibit 25916-X0015, Appendix H - Review of Component Analysis Method (CAM) Model, paragraphs 28-31.
Decision 25916-D01-2021 (July 8, 2021) 132022 Phase II Distribution Tariff Application FortisAlberta Inc.
Table 4. Property retirement unit values for line components
Per unit cost
Property retirement unit cost category
($)
Overhead conductor (meters) 4010916 18.46
Underground conductor (meters) 4010917 77.38
Non-wood pole 4010901 3,814.22
Switch – Overhead single phase 4010910 3,978.58
Switch – Overhead three phase 4010911 19,752.14
Switch – Underground single phase 401091 7,271.94
Switch – Underground three phase 4010913 37,834.86
Switch – Underground 3 PH SUPV 4010920 126,622.99
Wood pole 4010900 W.O. Lighting 4,322.83
Source: Exhibit 25916-X0022, Schedule 3.1 - CAM Working Model 1-Feeder 28S-2057L, sheet “4 Input – PRU.”
56. Each asset in Fortis’s geographic information system has an assigned property retirement
unit type and quantity. The CAM model multiples the allocated quantity of each property
retirement unit type of assets by property retirement unit values to determine the total RCN value
of the distribution assets used by each rate class of customers for each feeder.49
57. Fortis explained that property retirement unit categories can be composed of multiple
asset types with significant variations in unit costs. For example, there are different conductor
sizes for overhead and underground lines, and for wood poles there are different pole classes and
heights. Additionally, the number of distribution line phases (i.e., single- or three-phase) varies
among line segments.50
58. To better account for these variations, and how the use of these variations may differ
from rate class to rate class, Fortis conducted a property retirement unit multiplier study to
determine rate class specific property retirement unit multipliers. The property retirement unit
multipliers were used by Fortis to adjust the overhead conductor, underground conductor, and
wood pole property retirement unit costs determined by CAM for each rate class.51
59. At a high level, to calculate the property retirement unit multipliers, Fortis:
(a) Determined the estimated unit costs of constructing various common overhead and
underground line configurations.
(b) Calculated the lengths of each line configuration used by each rate class.
(c) Multiplied the unit costs (a) by the quantities (b) to determine estimated
construction costs for each rate class.
(d) Determined the number of poles and meters of overhead and underground
conductor used by each rate class. These quantities were multiplied by the property
retirement unit amounts for these items to determine property retirement unit costs.
49
Exhibit 25916-X0015, Appendix H - Review of Component Analysis Method (CAM) Model, paragraph 24.
50
Exhibit 25916-X0016, Appendix I - Property Retirement Units Multiplier Study, paragraph 4 and Table 2.
51
Exhibit 25916-X0081.01, Virtual technical meeting presentation, PDF page 32.
Decision 25916-D01-2021 (July 8, 2021) 142022 Phase II Distribution Tariff Application FortisAlberta Inc.
(e) Compared the calculated estimated construction costs (c) with the property
retirement unit costs (d) to determine property retirement unit multipliers for each
rate class, and normalized the results.52
60. The results of the study are reproduced in Table 5.
Table 5. Property retirement unit multipliers
Rate class Property retirement unit multiplier
Residential - Rate 11 0.94
Farm - Rates 21 and 22 1.08
Irrigation - Rate 26 1.00
Small General Service - Rate 41 0.92
Oil and Gas - Rate 45 1.02
General Service - Rate 61 1.00
Large General Service - Rate 63 1.10
REA Wire Owners 1.19
Source: Exhibit 25916-X0016, Appendix I - Property Retirement Units Multiplier Study, paragraph 10, Table 5.
61. In response to an information request, Fortis supplied an Excel sheet containing its
calculations for the property retirement unit multipliers.53 From the provided Excel sheet, the
Commission noted that the total metres of line used to calculate the estimated construction costs
differed from the total amount of line used to calculate the property retirement unit costs for each
rate class. For example, for the residential rate class there was a discrepancy of 6,611 km (or
15 per cent) between the total length of conductors used in the estimated construction cost
calculation and the property retirement unit cost calculation.54 Fortis explained that the
discrepancy was due to neutral conductors55 not being specifically delineated when determining
the quantity of lines of each conductor configuration.56
62. The Commission notes that all the overhead conductor configurations used by Fortis in
its property retirement unit multiplier study state that a neutral conductor is present. 57 However,
from Fortis’s responses, it appears that this is not the case, and that some line segments have a
neutral conductor and others do not. Fortis did not explain why it did not make a distinction
between conductor configurations with and without a neutral conductor.
63. Given that it appears Fortis has the necessary data to make the distinction, Fortis should
correct the property retirement unit multiplier study to properly account for neutral conductors.
For example, Fortis may adjust the study by bifurcating the conductor configurations into ones
with, and ones without, a neutral conductor, and determining the appropriate unit costs for each
configuration and associated quantities by each rate class. Alternatively, if the cost of adding a
neutral conductor to a line is not materially impacted by the primary conductor size and
configuration, Fortis could instead remove the cost of the neutral conductor from the conductor
configurations used in calculating the estimated construction costs, and add an additional
52
Exhibit 25916-X0122, FAI-AUC-2021JAN15-012(a).
53
Exhibit 25916-X0114, FAI-AUC-2021JAN15-012, Attachment 1.
54
Exhibit 25916-X0223, FAI-AUC-2021MAR30-002(b), further response.
55
Neutral conductors are conductors that are not energized, and typically strung farther down on a distribution
pole. They are generally used for grounding.
56
Exhibit 25916-X0223, FAI-AUC-2021MAR30-002(b), further response.
57
Exhibit 25916-X0016, Appendix I - Property Retirement Units Multiplier Study, paragraph 7, Table 2,
Line Configurations 1-4.
Decision 25916-D01-2021 (July 8, 2021) 15You can also read
