NRCan Report: Biennial Snapshot of Canada’s Electric Charging Network

I was the principal author for this just-released primary research report on public EV charging, sponsored by Natural Resource Canada and done in collaboration with Mogile technologies, editor of the ChargeHub database. You may find a summary below and how to get the full report is at the end of this post.

As of 28 January 2022, there were 19,502 charging ports in 7,967 locations in Canada. These include 15,718 level 2 (240 V) ports and 3,784 level 3 (DCFC) ports operated by 28 charging networks. There are also six hydrogen fuelling stations for fuel-cell electrical vehicles. 

ChargePoint, Electric Circuit, Flo and Tesla are the largest charging network operators, accounting for almost 70% of the ports. However, most of the chargers are owned by the site hosts where they are located. In addition to charging network operators and site owners, major stakeholders in the public charging infrastructure include automakers, utilities, charger manufacturers, governments, and regulatory agencies. The public EV charging ecosystem is nascent, and a few competing or complementary business models have emerged to link the various stakeholders. These business models are still evolving, and stakeholders are adapting to the evolution in the market. 

Most chargers are owned by businesses. However, there are significant differences amongst Canadian regions, with comparatively more chargers owned by different levels of governments and utilities in Québec. By contrast, the governments, the not-for-profit organizations, and the utilities own relatively few chargers in the Prairies, with ownership types in British Columbian and Ontario falling somewhere in between. About 48 charging sites are on or near Indigenous lands. 

Depending on the business model used, either the charging network operator or the site owner earns revenues from charging. About half of level 2 ports are free or partially free to use. Another quarter is at $1 per hour or less. Excluding Tesla, most level 3 ports are in the $10 to $15 per hour range, often around $12 per hour.

About 60% of the charging sites are in large cities, and these sites tend to be larger and equipped with more level 2 ports (and relatively fewer level 3 ports) than rural sites. For rural sites, charger mix varies with the distance from a highway. Sites closer to a highway have relatively more level 3 chargers than any other category — they are on-the-go corridor chargers. Further out, they are destination chargers generally installed at commercial or public sites.

Food stores, restaurants, and bars, as well as health care, finance and insurance companies, are the most common amenities found within 100 m of charging sites. Automotive repair places and gasoline stations are more commonly found around level 3 sites than around level 2 sites.

With the many EV charging stakeholders having their own objectives and priorities, and often competing amongst them, interoperability is increasingly important. The ecosystem is working toward improved interoperability between the EVs and the chargers, between the chargers and the E-Mobility systems of a network operator, and between E-Mobility systems of various network operators. However, the full interoperability is clearly not achieved yet, with multiple incompatibilities present at various levels in the infrastructure. 

Usage of the charging infrastructure was estimated using data provided by some Canadian operators. Overall, Mogile assembled a dataset with nearly 2 million charging sessions in four thousand locations with level 2 or level 3 chargers (over 20% of the ports in Canada). The dataset has usage data from 2019, 2020 and 2021. Unsurprisingly, utilization of public chargers has decreased with the COVID-19 pandemic. The average duration of charging sessions has remained relatively constant, while the number of ports available to the public continued to increase. Level 3 charging sessions in the datasets lasted on average 28 minutes, and level 2 charging sessions lasted on average 2 hours and 44 minutes. There has been a slight increase in energy and power delivered from 2019 to 2021.

The weekly pattern varies greatly depending on where a charging site is located. Sites in rural areas have more charging events during the weekend, starting Friday. In general, level 2 ports are the busiest toward noon and level 3 ports are busiest in late afternoon.

Accessibility, hardware and charging issues occasionally afflict drivers attempting to charge their EVs. Most level 3 chargers are communicating to enable remote diagnostics, but some level 2 chargers are not. Cable management systems are being installed to limit potential of damage to cables and connectors. Excluding external issues such as blocked access, the typical average unavailability of communicating level 3 chargers stated by some interviewed operators is around 1%. The stated average unavailability of communicating level 2 ports is higher, around 8% or 9%. Together, these issues contribute toward the overall satisfaction of EV drivers for public charging, and drivers are more satisfied with level 2 charging than with level 3 charging based on a natural language analysis of comments left by drivers in the ChargeHub mobile app. 

The full report can be obtained at https://www.nrcan.gc.ca/energy-efficiency/transportation-alternative-fuels/resource-library/3489, under the title “Biennial Snapshot of Canada’s Electric Charging Network and Hydrogen Refuelling Stations for Light-duty Vehicles”. Alternatively, you can obtain it at https://chargehub.com/en/industry/nrcan-report.html, or contact me directly. 

NRCan Report: Public EV Charging Infrastructure Gaps

I was the principal author for this just-released primary research report on public EV charging, sponsored by Natural Resource Canada and done in collaboration with Mogile Technologies, editor of the ChargeHub database.

This report identifies three categories in the Canadian electric vehicle (EV) charging infrastructure in which gaps occur: cities, highways, and customer experience. It is based on data in the ChargeHub database, an independent, curated, user-enriched and commercially available database of public EV charging stations in North America, augmented by data from stakeholder interviews and demographic census data and geographic data. 

Generally, cities in British Columbia and Quebec have more public charging ports relative to their population than cities in other provinces, and city EV drivers use them more than drivers outside cities. As for major highways, coverage is at 61%, with most of the gaps in the Prairies. For customer experience, EV drivers consider range anxiety (a vehicle issue: “Will I be able to get where I am going?”) a less serious concern than charging anxiety (an infrastructure issue: “Will I be able to charge at this site?”).

Although the geographic coverage of the EV charging infrastructure is relatively good, the charging capacity is stretched in many areas, resulting in a suboptimal customer experience. Fast charging sites tend to be larger in cities, and Tesla fast charging sites are, on average, four times larger than non-Tesla sites. Meeting the increasing charging needs of EV drivers and promoting adoption of EVs will need to account for existing capacity utilization in the immediate area where new sites are considered, especially at peak driving times such as Fridays before a long weekend. 

Interviewees stated that public charging sites generally have a challenging intrinsic economic case for their operators and site owners, which is constraining expansion. A large portion of charging sites is currently only financially undertaken when subsidized in some way, whether by governments, by utilities, by automakers or by site owners. Business owners likely justify supporting public charging sites based on the possible indirect benefits they may bring, such as attracting drivers and customers or improving public image. In this context, stakeholders see the financial support from NRCan’s infrastructure deployment programs as essential. 

Optimizing future EV charging infrastructure deployment will need to account for not only coverage but also capacity needs. For example, adding ports to an existing site, or adding a new site in the vicinity, may be highly beneficial for EV drivers if there is regular congestion and if the new capacity can be demonstrated to relieve current or upcoming congestion. Furthermore, due to the low levels of satisfaction with customer experience for public charging, we recommend that NRCan make the driver experience a key measure in assessing the performance of the EV charging infrastructure. 

The full report can be obtained at https://www.nrcan.gc.ca/energy-efficiency/transportation-alternative-fuels/resource-library/3489, under the title “Identification of Current and Future Infrastructure Deployment Gaps”, or contact me directly. 

EV Charging Use Cases

Charging EVs can be done at many places with various complementary use cases. This is quite different than fueling combustion vehicles, where the only option is to go to a service station. I am providing here the breakdown of the common EV charging use cases that I use for analysis when reporting on the industry.

  1. Home Charging.
    • Detached homes with their own parking spaces (and access to electricity).
    • Multi-unit residential buildings (using the shared electrical infrastructure).
  2. Public Charging. 
    • At a destination (when parked for hours).
      • Commercial or public sites (such as food stores and restaurants).
      • Curbside (using public on-street parking spaces).
    • On-the-go charging (when stopping for minutes).
      • Community charging (for commuting in a city, such has at a convenience store).
      • Corridor charging (along highways for intercity travel, such as at a rest area).
        • Light duty vehicles (LDV)
        • Medium and heavy duty vehicles (MHV)
  3. Workplace Charging (while employees are at work).
  4. Fleet Charging (at a depot).
    • Light-Duty Vehicles (LDV)
    • Medium and Heavy Vehicle (MHV)

Based on energy supplied, roughly 70% of LDV charging occurs at home, with level 2 charging accounting for about 80% of home charging[i]. The rest is mostly in public places, and some charging is at workplaces. 

For detached homes with their own parking spaces installing a dedicated EVSE is generally feasible at a reasonable cost, often wall-mounted in a garage or on an external wall. EVs may also be charged at level 1, from a 120 V plug. While level 1 charging is slower, it is generally sufficient for typical daily commuting when the EV is charged overnight. 

For multi-unit residential buildings, installing chargers and their electric distribution cabling may be highly problematic. For example, the electrical service entrance may not be suitable for the additional load from large-scale EV charging. Furthermore, cost allocation amongst owners or renters may need to be negotiated. Homeowner associations may provide a forum for discussions, but their rules may also hinder installation of chargers. Therefore, EV drivers living in a condo, a strata or an apartment building may have to rely on public or workplace charging sites. 

Destination charging refers to charging when one can expect to be parked for a few hours, elsewhere than at home. For example, food stores and restaurants are commonly found around destination charging sites. These are typically level 2 chargers. 

With on-the-go charging sites, drivers expect to stay only a few minutes while charging, such as at a convenience store or at a highway rest area. These are much like legacy gas stations, and normally level 3 chargers. Many of these charging locations may serve the local community for drivers not having access to home or workplace charging. Others are for corridor charging, serving intercity travellers (like service areas for LDV) and commercial vehicles (like truck stops for MHV). 

Many workplaces are starting to offer EV charging for their employees, either at level 1 or level 2. This charging may or may not be free to the employees, and it may or may not be available to visitors. For large installations, workplace EVSEs may coordinate with the building management systems to avoid excessive demand charges. 

In addition to charging of light-duty passenger vehicles (use cases 1 to 3 above), fleet charging is an important segment. Fleet charging might include light-duty commercial vehicles, such as taxis, as well as local delivery trucks, long-haul trucks, school buses, and public transit buses. Fleet charging is a combination of level 2, such as for overnight charging of light-duty vehicles at a depot, and level 3, especially for medium-duty and heavy-duty vehicles. For large fleet depots, power requirements may reach megawatts, which may have a significant impact on the local distribution grid.


[i]        The Geography of EV Charging, Understanding how regional climates impact charging and driving behavior, FleetCarma, 2020, p. 13.

Managing Residential Light-Duty EV Charging – An Overview

Big Idea

Through behavioral or direct control approaches, managed charging encourages customers to charge at times when grid and generation capacity is available. Likewise, it discourages charging during peak demand or low renewable generation periods. In doing so, it reduces the need to build additional grid and expensive or greenhouse gas emitting generators to meet the electric system load. Managed EV charging makes optimal use of existing infrastructure, lowers costs that would otherwise be incurred, and benefits ratepayers.

Analysis

Analysts show steep forecasts of the number of light-duty EVs, in parallel with increasing space and water heating electrification, adoption of electrified industrial processes and expansion of intermittent renewable generation. It’s a perfect storm of the less-know new EV loads, the highly coordinated new heating loads, and the unpredictability of new renewable supply. 

Many electric utilities are rightly concerned by the impact EV charging may have on their resource plans, both in terms of energy and capacity, but are also starting to see that managed — or “smart” — EV charging may be part of the solution to the disruption brought about by the electrification of the economy and the intermittency of renewables. So, although the grid impact of unmanaged light-duty EV charging may, by itself, be relatively modest or even beneficial, managed EV charging may become a new tool for utilities to provide grid services (such as peak shifting or even frequency regulations) or to help optimize customer charges. 

Light-duty managed charging aims to shift EV charging to times when generation and grid capacity is available, considering the load that needs to be served, the demand on the electrical system and its markets. To effect managed charging, utilities may rely on multiple approaches, sometimes simultaneously:

  • Residential unmetered incentives.
  • Residential dynamic rates.
  • Direct residential load control (V1G).
  • Residential Vehicle-to-Grid (V2G).

Rates and incentives are behavioral approaches, attempting to nudge customer conduct, while load control systems and V2G take action on the electrical equipment itself, without customers intervening. Managed charging programs often rely on more than one option. For instance, a utility can use unmetered incentives to get customers to opt in to time-of-use rates. 

However, utilities are not the only ones vying to influence the charging patterns of EV drivers. There are indeed many stakeholders vying for attention in the EV charging ecosystem: utilities, cities, charging operators, local businesses, real-estate developers, state/provincial governments, federal government, regulators, automakers, charger manufacturers, etc. For example, installation of chargers at commercial sites and the price charged to drivers (if any) is primarily driven by business considerations, such as attracting customers (a business owner objective), and not to benefit the grid (a utility objective) or to ensure sufficient charging coverage or capacity (which may be government objectives). Another example: utilities and their regulators may set electricity rates charged to public charging station owners but charging operators (which may not own the station) usually control end-user pricing and service conditions. 

Because EV charging market signals are still relatively weak and could even be in opposition, greater collaboration and alignment among EV stakeholders, with better understanding of driver behavior, will be important for the EV charging infrastructure to develop harmoniously over at least the next few years. 

Residential Light-Duty EV V2G

There’s an increasing level of interest in the industry to use the energy stored in EVs to manage demand and supply peaks, drawing on the EV batteries to support the grid, referred to as Vehicle-to-Grid (V2G). In concept, V2G is similar to using stationary batteries in people’s home as a distributed energy resource, a concept that has been growing in interest, with Green Mountain Power being the first utility with tariffed home energy storage programs[i] for customers. However, in some ways, V2G has more potential than stationary batteries, but also more challenges.

With V2G, EVs may be used as distributed grid-resource batteries. Then, a plugged-in EV with a sufficiently charged battery and a bidirectional charger may get a signal to discharge the battery when called upon to support the grid (demand response) or to optimize a customer’s electricity rates (tariff optimization). 

When associated with a home energy management system, V2G may be used as a standby power source during outages, a feature referred to as Vehicle-to-Home (V2H). V2G is also related to Vehicle-to-Load (V2L), where the vehicle acts as a portable generator. Collectively, these functions are often referred to as V2X, although they all have their own characteristics, as described below.

The Case for Residential Light-Duty EV V2G

The case for residential light-duty EVs is compelling because the batteries in modern light-duty EVs are large in comparison to their daily use, being sized for intercity travel (like going to the cottage on the weekend, or an occasional trip to visit friends and family), leaving significant excess capacity for use during peaks. For example, modern long-range EVs have batteries of 60 kWh to 100 kWh, for a range of 400 km (250 mi.) to 600 km (400 mi.) — significantly more than what is required for daily commute by most drivers. This means that light-duty passenger vehicles can leave home after the morning peak with less than a full battery and still come back at the end of the day with a high remaining state of charge for use during the evening peak. 

In terms of capacity, residential V2G compares favorably to home energy storage systems and commercial EV fleets. Indeed, home energy storage systems (like the Tesla Wall, with 13,5 kWh of usable energy[ii]) have far less capacity than modern EVs. As for medium or heavy-duty fleet EVs, they have a high duty cycle, with their batteries size usually optimized for their daily routes, leaving little excess capacity for use by a V2G system during peaks, with some exceptions, such as school buses[iii].

Extracting value from residential light-duty EV V2G can be achieved at the consumer level or at the utility level, but depending on the local regulatory framework and the energy, capacity or ancillary market structure:

  • Consumers may use V2G to leverage utility dynamic rates and net metering tariffs (or other bidirectional tariffs), charging the EV when rates are low and feeding back to the grid when rates are high. Typically, the consumer would own the V2G system. The consumer (or a third-party service company hired by the consumer) controls when the EV is charged and when it is discharged, following rules to ensure that the consumer driving needs and cost objectives are met.
  • A customer’s utility may also control the V2G system to optimize grid supply, charging the EV when wholesale prices are low or when generating capacity is aplenty, and feeding back to the grid when market prices are high or capacity constrained, therefore benefitting all ratepayers. As enticement for the consumers to participate, the utility would need to subsidize the V2G system or to have a recurring payment to the consumer.
  • In some jurisdictions, third-party aggregators may act as an intermediary between consumers and the energy, capacity or ancillary markets. Consumers are compensated by a subsidy, a recurring payment, or a guaranteed rate outcome. 

However, the potential of V2G also depends on automakers. Automakers are announcing V2X features, such as Volkswagen[iv] and Hyundai[v]. Aware of the economic potential of V2G and their gatekeeper position, automakers will want to extract some value from it, especially as V2X would increase the number of charging and discharging cycles of the battery, possibly affecting its service life, the warranty costs and civil liability. Automakers could extract value from V2G a few ways, including with an ordering-time option, a one-time software option, or even as an annual or monthly software fee to enable to a V2G function.[vi] Here again, cooperation among automakers will be important as the V2G interfaces to the grid are being defined; there are some signs that such cooperation is starting to take place, as shown by the common position of the German Vehicle Association, the VDA.[vii]

V2G vs. V2H vs. V2L

V2G should be distinguished from Vehicle-to-Home (V2H) and Vehicle-to-Load (V2L) use cases, as V2H and V2L do not feedback power to the electrical grid to relieve grid constraints or optimize customer rates. 

  • V2H is analogous to using the EV battery as a standby generator for use during a power outage. A V2G vehicle, when coupled with a home energy management system, may also offer V2H. 
  • V2L is like using a portable generator to power tools at a construction site or a home refrigerator during a power outage. V2G vehicles may or may not have plugs for V2L, although this is an increasingly common EV feature. 

V2G and V2H or V2L have different power electronics and standards to meet. V2H and V2L are easier to implement as they do not have to meet grid connection standards, while V2G systems must meet DER interconnection standards. An example is Rule 21 in California which makes compliance with IEEE 2030.5 and SunSpec Common Smart Inverter Profile (CSIP) standard mandatory distributed energy resources.[viii] On the other hand, a V2H or V2L vehicle (or its supply equipment) needs to have a grid-forming inverter, while a V2G inverter acts as a grid-following power source.[ix] [x]

On-Board V2G (AC) vs. Off-Board V2G (DC)

Electrically, V2G (and V2H) may come in two varieties: on-board V2G (AC) and off-board V2G (DC).[xi]

On-Board V2G (AC)

With on-board V2G, the EV exports AC power to the grid, through a home EV supply equipment. For light-duty vehicles, the connector is SAE J1772; SAE J3072 defines the communication requirements with the supply equipment. The supply equipment needs to be bidirectional and to support the appropriate protocol with the vehicle and compatible with the local grid connection standards.

An issue is that the standard Type 1 SAE J1772 plug used in North America is a single-phase plug and does not have a dedicated neutral wire for the split phase 120/240 V service used in homes. This means that the J1772 plug can be used for V2G (feeding back to the grid at 240 V) but can’t be used directly (without an adaptor or a transformer) for split phase 120/240 V V2H. This issue reduces the customer value of the system, as AC V2G can’t readily be used as a standby generator for the home. 

Many EVs come with additional plugs, in addition to J1772, for 120/240 V V2L applications. Examples included the NEMA 5-15 120 V plug (common residential plug) and the twist-lock L14-30 split phase 120/240 V plug (often seen on portable generators). The Hyundai IONIQ 5[xii] and the GMC Hummer EV[xiii] are examples of vehicles with additional plugs. 

As of this writing, commercially available EVs in North America do not support on-board V2G, but some have been modified to test the concept for pilot programs.[xiv] However, many automakers have announced vehicles with bidirectional chargers, and possibly AC V2G, although there are little publicly available specifications. 

Off-Board V2G (DC)

With off-board V2G, the EV exports DC power to a bidirectional DC charger. 

Bidirectional charging has been supported by the CHAdeMO DC fast-charging standard for quite some time, and the Nissan Leaf has offered the feature since 2013[xv]. Several light-duty DC V2G pilots therefore used these vehicles. However, with the new Nissan Ariya electric crossover using CCS instead of CHAdeMO, Nissan effectively made CHAdeMO a legacy standard in North America.[xvi]

CCS is an alternative for off-board V2G, but, unfortunately, CCS does not yet support bidirectional charging. CharIN[xvii], the global association dedicated to CCS, is developing the standards for V2G charging[xviii]. The upcoming ISO 15118-20 is expected for the fourth quarter of 2021 and will include bidirectional charging. This will mark the official start of interoperability testing. However, it will take time to reach mass-market adoption since the new standard needs to be implemented and tested beforehand to overcome potential malfunctions on software and hardware side.[xix] BMW, Ford, Honda, and Volkswagen have all announced plans to incorporate bidirectional charging and energy management, with an implementation target of 2025, but it is not clear if this is for V2G AC or V2G DC.[xx]

A critique of off-board V2G is the high cost of bidirectional DC chargers.[xxi] A solution may be to combine the bidirectional charger with a solar inverter, integrating power electronics for residences with both solar panels and EV charging. The dcbel r16 is an example of such an integrated approach[xxii], combining a Level 2 EV charger, a DC bidirectional EV charger, MPPT solar inverters, a stationary battery charger/inverter and a home energy manager in a package that costs less than those components purchased individually.[xxiii]


[i]        See https://greenmountainpower.com/rebates-programs/home-energy-storage/powerwall/ and https://greenmountainpower.com/wp-content/uploads/2020/11/Battery-Storage-Tariffs-Approval.pdf, accessed 20210526

[ii]       See https://www.tesla.com/sites/default/files/pdfs/powerwall/Powerwall%202_AC_Datasheet_en_northamerica.pdf, accessed 20211008.

[iii]      While medium and heavy vehicles like trucks and transit buses generally have little excess battery capacity, school buses during summer are an exception, as many remain parked during school holidays. See, for example, https://nuvve.com/buses/, accessed 20211208.

[iv]       See https://www.electrive.com/2021/01/27/vw-calls-for-more-cooperation-for-v2g/, accessed 20211220.

[v]        See https://www.etnews.com/20211101000220 (in Korean), accessed 20211210.

[vi]       For example, Stellantis targets ~€20 billion in incremental annual revenues by 2030 driven by software-enabled vehicles. See https://www.stellantis.com/en/news/press-releases/2021/december/stellantis-targets-20-billion-in-incremental-annual-revenues-by-2030-driven-by-software-enabled-vehicles, accessed 20211207,

[vii]      See https://www.mobilityhouse.com/int_en/magazine/press-releases/vda-v2g-vision.html, accessed 20211210.

[viii]     See https://sunspec.org/2030-5-csip/, accessed 20211006.

[ix]       See https://efiling.energy.ca.gov/getdocument.aspx?tn=236554, on page 9, accessed 20211208.

[x]        “EV V2G-AC and V2G-DC, SAE – ISO – CHAdeMO Comparison for U.S.”, John Halliwell, EPRI, April 22, 2021.

[xi]       See http://www.pr-electronics.nl/en/news/88/on-board-v2g-versus-off-board-v2g-ac-versus-dc/, accessed 20211008, for an in-depth discussion of on-board and off-board V2G.

[xii]      See https://www.hyundai.com/worldwide/en/eco/ioniq5/highlights, accessed 20211006.

[xiii]     See https://media.gmc.com/media/us/en/gmc/home.detail.html/content/Pages/news/us/en/2021/apr/0405-hummer.html, accessed 20211008.

[xiv]     See https://www.energy.ca.gov/sites/default/files/2021-06/CEC-500-2019-027.pdf, accessed 202112108.

[xv]      See https://www.motortrend.com/news/gmc-hummer-ev-pickup-truck-suv-bi-directional-charger/, accessed 20211008.

[xvi]     See https://www.greencarreports.com/news/1128891_nissan-s-move-to-ccs-fast-charging-makes-chademo-a-legacy-standard, accessed 20211008.

[xvii]    See https://www.charin.global, accessed 20211008.

[xviii]   See https://www.charin.global/news/vehicle-to-grid-v2g-charin-bundles-200-companies-that-make-the-energy-system-and-electric-cars-co2-friendlier-and-cheaper/, accessed 20211008.

[xix]     Email received from Ricardo Schumann, Coordination Office, Charging Interface Initiative (CharIN) e.V., 20211015

[xx]      See https://www.motortrend.com/news/gmc-hummer-ev-pickup-truck-suv-bi-directional-charger/, accessed 20211008.

[xxi]     See, for example, https://thedriven.io/2020/10/27/first-vehicle-to-grid-electric-car-charger-goes-on-sale-in-australia/, accessed 20211012.,

[xxii]    See https://www.dcbel.energy/our-products/, accessed 20211012. 

[xxiii]   See https://comparesmarthomeenergy.com, accessed 20211210. 

IEEE Webinar: The Utility Business Case to Support Light Duty EV Charging

I presented this webinar on December 2nd. The link to the recording and the slides is here.

Let me know what you think!

A New Kind of Electrical Load: Charging of Long-Range Electric Vehicles

When adopting electric vehicles (EV), consumers are now favoring long-range light-duty EVs[1], with nearly all the growth coming from sales of long-range battery electric vehicles rather than short-range EVs or plug-in electric hybrids.[2] Given this development, I focus here on the unique characteristics of long-range light-duty EVs charging. Long-range EVs have three characteristics that differentiate them from other residential electrical loads:

  • EVs are large and mobile loads—they are not always connected to the grid, and not every day.
  • EV charging is highly price elastic—drivers seek the cheapest electrons.
  • Drivers easily control when to charge—charging is flexible with the large batteries and the telematics of modern long-range EVs. 

These characteristics—and especially customer behavior—mean that utilities can’t consider EVs like any other loads. Utilities need a new thinking to plan for EV charging and to assess how to best manage it to benefit ratepayers. These characteristics also have impact on public and workplace charging sites, their operators, and the businesses nearby.

Let’s see how different EV charging really is.

EVs Are Large and Mobile Loads 

Most electrical loads are fixed, like water heaters and clothes driers. Mobile loads, like cell phones, are small. But EVs are unique because they are mobile and large electrical loads. They are indeed large—typically, 4 to 8 kW for a level 2 charger, and often 100 kW or more with a public direct current fast charger (DCFC). And they are mobile: we drive our cars around (obviously) and do not always keep them plugged in when parked. In fact, parked long-range EVs are more often unplugged than plugged.

Compare this to traditional household electrical loads of a comparable magnitude, which are wired in, like water heaters, or permanently plugged, like clothes driers. Industrial loads in the 100-kW range are usually fixed and wired in.

So What?

This means that the EV charging load is less predictable than traditional electrical loads, both in space and time. An EV driver may charge at home with a level 2 charger, on the way to the cottage with a public DCFC, and on a 120-volt wall plug (level 1 charging) once they get there. Over time and with large numbers of EVs on the road, we may learn where and when EVs are being charged, on average, bringing greater predictability to this load. But, until then, we will have to go with some uncertainty. However, understanding what drive EV customer behavior and what drivers can control helps reduce uncertainty.

EV Charging Is Highly Price Elastic

EV charging is highly price elastic—an economic term meaning that consumers are sensitive to charging price and adjust accordingly. If charging prices at a given time or location rises, the demand for charging then and there should fall. Conversely, lower prices spur usage. 

Many studies confirm the high price elasticity of EV charging:

  • Comparing the charging load profile in the Canadian provinces of Ontario (with time-of use electricity pricing) and Québec (without time-of-use) shows that time-of-use pricing is delaying peak charging by almost 2 hours, with a steep increase once off-peak pricing happens.[3]
  • PG&E customers who have enrolled in EV-only rates conduct 93% of EV charging off peak; on Southern California Edison’s EV-only rate, 88% of charging is off-peak.[4]
  • A small rate differential may induce a strong tendency for overnight charging. A study assessed the impact of the peak-to-super-off-peak price ratio going from small (2:1) to large (6:1). However, the share of super off-peak charging varied little, from 78% to 85% of EV charging taking place during super off-peak period (typically after 10 PM or midnight).[5]
  • EV customers exhibit learning behavior, increasing their share of super off-peak charging and decreased their share of on-peak over time.[6]
  • When free workplace charging is offered, it is used 3 times as much as when employees must pay for it.[7]

Drivers of gasoline or diesel cars are highly responsive to local petrol prices, shopping around or timing purchases when they can, as well as seeking coupons for cheaper gas.[8] When it comes to price, EV drivers seem to act like drivers of internal combustion vehicles.

So What?

The high price elasticity of EV charging is a strong indication that pricing and monetary incentives may be used to shape the EV charging load curve—at home, at work or in public. 

This is not ignored by utilities, as “60 percent of utilities consider activities that would enable them to develop effective rate structures—such as studying EV charging ownership, behavior and rate impacts—to be the most important activity in preparing for increased EV adoption”.[9] For residential charging, driver sensibility toward prices opens the door for gamification programs and is also the main value drivers being considered for vehicle-to-grid pilots. Regarding public charging, Tesla is quietly testing out ways to incentivize its customers to charge their cars when electricity demand isn’t so high or when sites are not congested[10]—I would expect that other charging operators and utilities will also assess time-varying or dynamic pricing for public charging. 

Drivers Easily Control When to Charge

Many forms of residential loads, such as air conditioning used when it is hot and ovens at dinner time, are predictable because consumers want or need to turn them on during specific situations or at regular times. EV charging is less predictable because drivers of long-range EVs have much more control on when (and therefore where) to charge. Drivers elect to use various charging patterns, depending on their needs:

  • Residential EV charging load is well suited to respond to price signals. Modern light-duty EVs be easily programmed to begin charging at a preset time using dashboard menus or a cellphone app. If a smart home charger is installed, it too can limit charging to specific times. Drivers can also start and stop charging remotely with a car or a home charger apps.
  • EV drivers pair charging with other activities, such as spending time in stores while waiting for their vehicles to charge.[11]
  • A Reddit user posted a message received from Tesla, encouraging them to stop at select California Superchargers before 9 a.m. and after 9 p.m. over a weekend, for a lower charging price.[12]
  • Drivers using an “empty battery” pattern tend to run the battery down to a very low state of charge (SOC) before recharging, like people fueling gasoline cars stopping at a gas station perhaps once a week.[13] In fact, not charging every day is recommended by automakers.[14]
  • Another common pattern is “scheduled charging”, where drivers charge the battery at periodic intervals, even every day, regardless of the state of charge of the vehicle’s batterie.
  • For many drivers, charging once or twice a week when the battery gets low is convenient. Others charge their EV at every opportunity[15], plugging into a charger if it’s available nearby, taking advantage of the fact that they do not need to remain beside the vehicle while it is charging.

In other words, drivers of long-range EVs are flexible and control when and where to charge so that it is best for them, either because it is convenient or less expensive. 

So What?

Utilities, charging operators and business owners can leverage this flexibility, knowing the mobility and the price sensibility of EV drivers. Through price signals or promotions, they can nudge drivers to charge where and when it best suits them—to minimize stress on the grid, to balance usage of high-traffic charging sites, or to increase in-store retail sales. 

Looking Forward

With steep forecasts of the number of light-duty EVs in some areas, many electric utilities are rightly concerned by the impact EV charging may have on their resource plans, both in terms of energy and capacity. Many see managed—or “smart”—charging as a solution to this disruption. Managed charging aims to shift EV charging to times when capacity is available in generation and in the grid. To effect managed charging, utilities may rely on metered rates, unmetered incentives, load control, or, very often, a combination of those approaches. Rates and incentives are behavioral approaches, attempting to nudge customer conduct, while load control works with the loads themselves. 

However, utilities are not the only ones trying to influence the charging patterns EV drivers. There are indeed many stakeholders in the EV charging ecosystem: utilities, cities, charging operators, local businesses, real-estate developers, state/provincial governments, federal government, regulators, automakers, charger manufacturers, etc. For example, installation of chargers at commercial sites and their charging rates is primarily driven by business considerations, such as attracting customers (a business owner objective), and not to benefit the grid (a utility objective) or to ensure sufficient coverage or capacity for EV drivers (which are government objectives). Another example: utilities and their regulators may set rates for public charging stations, but charging operators control end-user pricing and service conditions. 

Greater collaboration and alignment among these stakeholders, with better understanding of driver behavior, will be essential for the EV charging infrastructure to develop harmoniously. 


[1] Long-range electric vehicles (EV) typically have an EPA-rated range of around 250 miles (400 km) or more, with batteries of at least 60 kWh. Examples in 2021 include the Tesla Model 3 and the Kia Niro EV. Shorter range EVs also exist, like some Nissan Leafs, along with plug-in hybrids vehicles, like the Toyota RAV4 Prime.

[2] Long-Term Electric Vehicle Outlook 2020, BloombergNEF, May 19, 2020, page 65.

[3] Charge the North project, Presentation to the Infrastructure and Grid Readiness Working Group by Matt Stevens, FleetCarma, September 2019, page 14.

[4] Beneficial Electrification of Transportation, The Regulatory Assistance Project (RAP), January 2019, p. 66.

[5] Final Evaluation for San Diego Gas & Electric’s Plug?in Electric Vehicle TOU Pricing and Technology Study, Nexant, Inc., February 20, 2014.

[6] Final Evaluation for San Diego Gas & Electric’s Plug?in Electric Vehicle TOU Pricing and Technology Study, Nexant, 2014, p.44.

[7] Employees with free workplace charging get 22% of their charging energy from work, while employees with paid workplace charging get 7% of their charging energy from work. Charge the North project, Presentation to the Infrastructure and Grid Readiness Working Group by Matt Stevens, FleetCarma, September 2019, page 13.

[8] See https://voxeu.org/article/gasoline-demand-more-price-responsive-you-might-have-thought, accessed 20191107.

[9] Black & Veatch 2018 Strategic Directions: Smart Cities & Utilities Report, Black & Veatch, 2018, pages 10. 

[10] See https://insideevs.com/features/454482/getting-best-deal-tesla-superchargers, accessed 20210416.

[11] See https://atlaspolicy.com/wp-content/uploads/2020/04/Public-EV-Charging-Business-Models-for-Retail-Site-Hosts.pdf. accessed 20210416.

[12] See https://www.reddit.com/r/teslamotors/comments/jkhdx8/supercharging_discount_this_weekend_in_california/, accessed 20210416.

[13] The Life of the EV: Some Car Stories, Laura McCarty and , Brian Grunkemeyer, FlexCharging, presented at the 33rd Electric Vehicle Symposium (EVS33), Portland , Oregon June 14-17, 2020, page 6.

[14] See, for instance, the recommendations of Hyundai at https://www.greencarreports.com/news/1127732_hyundai-has-5-reminders-for-making-your-ev-battery-last-longer.

[15] Charging frequency of private owned e-cars in Germany 2019, Published by Evgenia Koptyug, Oct 21, 2020, https://www.statista.com/statistics/1180985/electric-cars-charging-frequency-germany/, accessed 20210305.

Here Are the 145 Canadian Electric Utilities

February 2nd update: Thanks to some friends, the list has been updated, reducing the number of Canadian utilities from 151 to 145.

In the United States, the Energy Information Agency maintains a handy database of electric utilities. I couldn’t find anything similar for Canada. In my activities as a business consultant in the electricity sector, it’s something useful and I have had many Canadian utilities as customers. So, I made my own over the years and I’m sharing it here. 

You’ll be pleased to know that 145 electric utilities operate in Canada — I included the entire list at the end of this post. Some definitions here: I’m only counting distribution companies. Companies that are energy retailers, transmitters or generators without a distribution operation are omitted from this list. I found the number of customers for most of them, giving a sense of size, although I couldn’t always find this information — mostly Alberta coops and some utilities in the territories. 

58% of Canadian utilities are municipally owned, and 24% more are coops.

However, by customer count, 57% of Canadian customers are served by a provincial or territorial utility. As I couldn’t find the customer counts of many coops, this chart underestimates this category. 

Ontario has the most utilities, followed by Alberta, British Columbia and Québec. Manitoba and Prince Edward Island are the only two provinces with a single utility. 

Hydro-Québec is the largest Canadian utility, with over 4.3 M customers. BC Hydro and Hydro One follow. Alectra is the largest municipal utility. The Fortis companies, if taken together, would have over 1 M customers in BC, AB, ON, PE and NL, but they’re largely operating independently. The top 20 companies have 90% of the Canadian customers — the 20th one, Kitchener-Wilmot Hydro, has almost 100,000 customers.

Let me know if you want to know more!

RankUtility NameCustomersOwnershipProv./Terr.
1Hydro-Québec Distribution4,316,914Prov./Terr.QC
2BC Hydro2,049,322Prov./Terr.BC
3Hydro One Networks Inc.1,395,575Prov./Terr.ON
4Alectra Utilities Corporation1,054,613MunicipalON
5Toronto Hydro-Electric System Limited777,904MunicipalON
6ENMAX Power Corp.674,800MunicipalAB
7Manitoba Hydro586,795Prov./Terr.MB
8FortisAlberta Inc.563,000Inv. OwnedAB
9SaskPower537,714Prov./Terr.SK
10Nova Scotia Power Incorporated520,000Inv. OwnedNS
11NB Power405,466Prov./Terr.NB
12EPCOR Distribution Inc.369,000MunicipalAB
13Hydro Ottawa Limited339,771MunicipalON
14Newfoundland Power269,000Inv. OwnedNF
15ATCO Electric Ltd.227,000Inv. OwnedAB
16FortisBC175,900Inv. OwnedBC
17Elexicon Energy Inc.167,653MunicipalON
18London Hydro Inc.160,598MunicipalON
19Saskatoon Light & Power117,200MunicipalSK
20Kitchener-Wilmot Hydro Inc.97,695MunicipalON
21ENWIN Utilities Ltd.89,561MunicipalON
22Hydro-Sherbrooke82,697MunicipalQC
23Maritime Power80600Inv. OwnedPE
24Oakville Hydro Electricity Distribution Inc.73,133MunicipalON
25Burlington Hydro Inc.68,205MunicipalON
26Energy+ Inc.66,521MunicipalON
27Entegrus Powerlines Inc.59,810MunicipalON
28Oshawa PUC Networks Inc.59,183MunicipalON
29Waterloo North Hydro Inc.57,855MunicipalON
30Synergy North Corporation56,700MunicipalON
31Niagara Peninsula Energy Inc.56,067MunicipalON
32Greater Sudbury Hydro Inc.47,725MunicipalON
33Newmarket-Tay Power Distribution Ltd.43,931MunicipalON
34Milton Hydro Distribution Inc.40,388MunicipalON
35Brantford Power Inc.40,124MunicipalON
36Newfoundland & Labrador Hydro38,000Prov./Terr.NF
37Bluewater Power Distribution Corporation36,743MunicipalON
38Saint John Energy36,500MunicipalNB
39PUC Distribution Inc.33,647MunicipalON
40City of New Westminster31,000MunicipalBC
41Essex Powerlines Corporation30,393MunicipalON
42City of Medicine Hat Electric30,200MunicipalAB
43Canadian Niagara Power Inc.29,455Inv. OwnedON
44Kingston Hydro Corporation27,778MunicipalON
45North Bay Hydro Distribution Limited24,199MunicipalON
46Westario Power Inc.23,774MunicipalON
47Welland Hydro-Electric System Corp.23,664MunicipalON
48ERTH Power Corporation23,380MunicipalON
49Halton Hills Hydro Inc.22,528MunicipalON
50Festival Hydro Inc.21,382MunicipalON
51Hydro-Jonquière20,289MunicipalQC
52Innpower Corporation18,632MunicipalON
53EPCOR Electricity Distribution Ontario Inc.17,916Inv. OwnedON
54Swift Current Electricity Services16,600MunicipalSK
55Wasaga Distribution Inc.14,003MunicipalON
56Lakeland Power Distribution Ltd.13,762MunicipalON
57Orangeville Hydro Limited12,652MunicipalON
58E.L.K. Energy Inc.12,478Inv. OwnedON
59Algoma Power Inc.11,732Inv. OwnedON
60Grimsby Power Incorporated11,631MunicipalON
61Ottawa River Power Corporation11,320MunicipalON
62Lakefront Utilities Inc.10,546MunicipalON
63Hydro Westmount10,181MunicipalQC
64Hydro-Magog9,957MunicipalQC
65Niagara-on-the-Lake Hydro Inc.9,558MunicipalON
66Hydro-Joliette8,975MunicipalQC
67Centre Wellington Hydro Ltd.7,156MunicipalON
68Tillsonburg Hydro Inc.7,129MunicipalON
69Coopérative SJBR6,400CooperativeQC
70Northern Ontario Wires Inc.5,977MunicipalON
71Rideau St. Lawrence Distribution Inc.5,910MunicipalON
72Edmundston Energy5,800MunicipalNB
73Hydro Hawkesbury Inc.5,549MunicipalON
74Ville d’Alma5,482MunicipalQC
75Ville de Baie-Comeau4,928MunicipalQC
76Nelson Hydro4,434MunicipalBC
77Renfrew Hydro Inc.4,325MunicipalON
78Hydro-Coaticook3,968MunicipalQC
79Wellington North Power Inc.3,830MunicipalON
80Fort Frances Power Corporation3,773MunicipalON
81Antigonish Electric Utility3,500MunicipalNS
82Espanola Regional Hydro Distribution Corporation3,309Inv. OwnedON
83Ville d’Amos2,882MunicipalQC
84Sioux Lookout Hydro Inc.2,848MunicipalON
85Hearst Power Distribution Company Limited2,700MunicipalON
86Cooperative Hydro Embrun Inc.2,366CooperativeON
87Atikokan Hydro Inc.1,629MunicipalON
88Corix Multi Utility Services Inc. 1,365Inv. OwnedBC
89Hydro 2000 Inc.1,244MunicipalON
90Chapleau Public Utilities Corporation1,222MunicipalON
91Perth Andover Light Commission1,000MunicipalNB
92Hemlock Utility Services Ltd.252Inv. OwnedBC
93The Yukon Electrical Company Limited 80Inv. OwnedBC
94Kyuquot Power Ltd.42Inv. OwnedBC
95Silversmith Light & Power Corporation9Inv. OwnedBC
96Armena REA Ltd. CooperativeAB
97Battle River Power Coop CooperativeAB
98Beaver REA Ltd. CooperativeAB
99Blue Mountain Power CooperativeAB
100Borradaile REA Ltd. CooperativeAB
101Braes REA Ltd. CooperativeAB
102City of LethbridgeMunicipalAB
103City of Red Deer Electric Light & PowerMunicipalAB
104Claysmore REA Ltd. CooperativeAB
105Co-op (Rocky REA Ltd) CooperativeAB
106Devonia REA Ltd. CooperativeAB
107Drayton Valley REA Ltd. CooperativeAB
108Duffield REA Ltd CooperativeAB
109EQUS REA Ltd. CooperativeAB
110Ermineskin REA Ltd. CooperativeAB
111Fenn REA Ltd. CooperativeAB
112Heart River REA Ltd. CooperativeAB
113Kneehill REA Ltd. CooperativeAB
114Lakeland REA Ltd. CooperativeAB
115Lindale REA Ltd. CooperativeAB
116MacKenzie REA Ltd. CooperativeAB
117Mayerthorpe & District REA Ltd. CooperativeAB
118Montana REA Ltd. CooperativeAB
119Municipality of Crowsnest PassMunicipalAB
120Myrnam REA Ltd. CooperativeAB
121Niton REA Ltd. CooperativeAB
122North Parkland Power REA Ltd. CooperativeAB
123Peigan Indian REA Ltd. CooperativeAB
124Sterling REA Ltd. CooperativeAB
125Stony Plain REA Ltd. CooperativeAB
126Tomahawk REA Ltd CooperativeAB
127Town of Cardston MunicipalAB
128Town of Fort Macleod MunicipalAB
129Town of Ponoka MunicipalAB
130West Liberty REA Ltd CooperativeAB
131West Wetaskiwin REA Ltd. CooperativeAB
132Wild Rose REA Ltd. CooperativeAB
133Willingdon REA Ltd. CooperativeAB
134Zawale REA Ltd. CooperativeAB
135City of Grand ForksMunicipalBC
136City of PentictonMunicipalBC
137District of SummerlandMunicipalBC
138Berwick Electric Light CommissionMunicipalNS
139Canso Electric Light CommissionMunicipalNS
140Lunenburg Electric UtilityMunicipalNS
141Mahone Bay Electric UtilityMunicipalNS
142Riverport Electric Light CommissionMunicipalNS
143Northland UtilitiesInv. OwnedNT
144Qulliq EnergyProv./Terr.NU
145Yukon Electrical CompanyInv. OwnedYK
146Yukon Energy CorporationProv./Terr.YK

Presentation at the EV Charging Infrastructure Summit

Today, I presented at this conference.

This presentation provided real-life insights into developing a sound EV strategy for utilities and cities. Using from data ChargeHub, I shared best practices to keep in mind as public charging infrastructure is developed. These suggestions are inspired by the actions of forward-thinking utilities and governments, which ChargeHub has had the privilege of assisting with data and strategic advice over the last few years.

Done right, EVs prove to be good for utilities, their ratepayers, and all citizens.

You can download the presentation and the speaker notes here:

IEEE Webinar: “The Business Case for Utilities Supporting Public EV Charging”

Today, I gave a webinar for the Institute of Electrical and Electronics Engineers (IEEE) entitled “The Business Case for Utilities Supporting Public EV Charging”. I got quite a few good questions. For everyone to see, I am posting the slides here

Do not hesitate to reach out to me if you have any question. 

EV Charging Puts Downward Pressure on Electricity Rates

Real-world experience from utilities with a relatively high penetration of light-duty EVs shows that EV charging brings additional utility revenues that vastly exceed the costs to generate and deliver the additional energy. This may be surprising given the concerns expressed in some industry opinion pieces on the ability of the grid to support EVs. However, in California, with high EV penetration and otherwise relatively low average residential load, only 0.15% of EVs required a service line or distribution system upgrade.[1] At a system level, a Hydro-Quebec study shows that average home charging of an EV draws only 600 watts on peak – a small amount.[2] It is worth noting that these two examples do not even rely on EV load management, which would further lower contribution to peak load. 

In practice, many factors contribute to mitigating the impact of unmanaged EV charging on the grid. For instance, many owners of long-range EVs only charge at home once or twice a week, and not necessarily at peak system time. Also, many EV drivers are simply charging off a standard 120 V wall plug – slow but enough in most circumstances. More and more drivers charge at their workplace or at public stations, with diversified load curves. At the local level, distribution transformers used for residential customers are typically loaded at 25% to 30% of their rating; a few hours a year may be above the kVA rating of the transformer, but with little consequence.[3]

If anything, the advent of EVs may get electric utilities growing again: current year-over-year electricity consumption growth (kWh) averages below 1% in North America but was about 2.5% as recently in the 1990s.[4] Perhaps incredibly, yearly growth was about 8% to 10% in the 1950s and 1960s, as a wave of electrification propelled the economy. The ADN of electric utilities includes building the electricity grid and adding capacity.

Looking forward, various forecasts of the electricity use from EV adoption range from a fraction of a percent to perhaps 2% per year[5] – not negligible, but clearly manageable in view of past growth rates. 

Overall, grid impacts of light-duty EV load profile over at least the next decade should be relatively modest and net economic benefits from additional utility revenue vastly exceed costs. Those benefits will exert a downward pressure on rates for all utility customers – not just to those driving EVs. For example, Avista estimates that the net present value to ratepayers of a single EV on its system is $1,206 without managed charging.[6] Furthermore, shifting charging to off-peak or high renewable generation periods further improves benefits – up to $1,603 per EV for Avista. Furthermore, EV drivers also gain from lower maintenance and operating costs. And besides, the switch to EVs significantly reduce greenhouse gas and other harmful air pollutant emissions.
This post was initially published at https://chargehub.com/en/blog/index.php/2020/03/25/ev-charging-puts-downward-pressure-on-rates/.


[1] Joint IOU Electric Vehicle Load Research – 7th Report, June 19, 2019.

[2] Public Fast Charging Service for Electric Vehicles, Hydro-Québec, R-4060-2018, HQD-1, document 1.

[3] Electric Power Distribution Handbook, T.A. Short, chapter 5. Some winter-peaking utilities are even planning the overloading of distribution transformer, counting on the low ambient temperature to cool it down.

[4] https://data.nrel.gov/files/90/EFS_71500_figure_data%20(1).xlsx, figure 2.1, for US data. 

[5] For examples of forecast electricity use from EV adoption, see: 
– Mai et al., Electrification Futures Study, page 82. https://www.nrel.gov/docs/fy18osti/71500.pdf.
– Canadian electric vehicle transition – the difference between evolution and revolution, EY Strategy, October 2019, page 9. https://assets.ey.com/content/dam/ey-sites/ey-com/en_ca/topics/oil-and-gas/canadian-electric-vehicle-transition-the-difference-between-revolution-or-evolution.pdf.

[6] Electric Vehicle Supply Equipment Pilot Final Report, Avista Corp., October 18, 2019.

The Electric Cars in the Future of Utilities

Yogi Berra famously said that “it’s tough to make predictions, especially about the future.” Electric vehicles do not escape this wisdom. Still, recent trends and forecasts suggest a sustained growth in adoption of light-duty electric vehicles in North America. 

There are many reasons to believe that there will be many electric cars in our future. 

First, most electric vehicle drivers think that their cars are the best cars they ever had – according to a AAA survey[1], 96% of electric vehicle owners say they would buy or lease one again the next time they are in the market for a new car. Anecdotally, we can confirm this: through the ChargeHub platforms, electric vehicle drivers express their enthusiasm daily toward their cars (but also, unfortunately, their frustrations toward public charging).

Second, more and more car manufacturers are committing to an electric future: global automakers are expected to invest $225 billion on the development of battery-electric vehicles from 2019 to 2023, according to an AlixPartners study[2] — roughly equal to the massive amount that all automakers globally combined spend on capital expenditures and research and development in a year. New electric car plants are being built and internal combustion ones are being converted. There’s no turning back.

Thirdly, many states, provincial and federal governments have policies to reduce greenhouse gas emissions in order to stave off climate change. The transportation sector is the largest contributors to U.S. greenhouse gas emissions, and light-duty vehicles contribute to 59% of transportation emissions[3]. Necessarily, reducing greenhouse gas emission will require us to drive electric light-duty vehicles. 

Yet, only about 2% of 2019 new passenger car sales in North America are plug-in electric vehicles.[4]

There are a number of factors to explain the dichotomy between actual and forecast sales of electric vehicles. The first is simply availability: buying a new electric vehicle usually implies waiting months and there are few model options. If you do not happen to live in the few states or provinces that have a zero-emission mandate[5] requiring a minimum percentage of electric light-duty vehicles, you may actually be out of luck: car manufacturers may simply not offer them to you. For example, Subaru stocks the Crosstrek plug-in hybrids in California, nine other states[6] and the Canadian province of Québec[7] that have adopted zero-emission vehicle regulations. 

Even in jurisdictions with zero-emission mandates, availability is often limited to regulatory obligations: internal combustion vehicles are currently far more profitable than electric ones, and automakers don’t have enough incentive to move away from internal combustion engine vehicles, especially at current low-volume. However, analysts, like the McKinsey strategic consultancy, expect that EVs have the potential to reach initial cost parity with and become equally—or even more—profitable as internal combustion vehicles around 2025[8]. Combined with already lower operating costs for drivers, this will make building electric vehicles a compelling proposition for automakers and drivers alike. 

If investments being made in manufacturing will cure current availability and cost issues, there are still a few more obstacles that need to be removed to hasten the advent of electrical cars. A survey by KSV lists top worries about batteries running out, convenient home charging and how to charge, operate, and maintain electric vehicles. These other concerns primarily point to insufficient consumer knowledge and incomplete public charging infrastructure. While home charging remains the principal means to recharge electric vehicles, charging at workplaces and public stations plays an important role for drivers who cannot charge at home or when traveling away from home. Utilities have a central role in enabling public and workplace charging, through policy-induced subsidies and tariffs. Utilities are also the second-most trusted source of information on EVs, after Consumer Reports – car dealers are last[9]. To succeed, electric utilities need to work with site owners (for public charging) and automakers (for education) – two types of stakeholders with which utilities do not have relevant business relationships. 

This was initially published at https://chargehub.com/en/blog/index.php/2020/03/05/the-electric-cars-in-the-future-of-utilities/.


[1]       https://www.oregon.aaa.com/content/uploads/2020/01/True-Cost-of-EV-Ownership-Fact-Sheet-FINAL-1-9-20.pdf, accessed 2020-03-05.

[2]       https://www.alixpartners.com/media-center/press-releases/alixpartners-global-automotive-industry-outlook-2019/, accessed 2020-03-05.

[3]       https://www.epa.gov/greenvehicles/fast-facts-transportation-greenhouse-gas-emissions, accessed 2020-03-05.

[4]       https://en.wikipedia.org/wiki/Electric_car_use_by_country, accessed 2020-03-05.

[5]       https://electricautonomy.ca/2020/02/04/industry-divided-on-the-merits-of-a-national-zev-mandate-as-federal-budget-nears/, accessed 2020-03-05.

[6]       https://www.autonews.com/article/20181124/RETAIL01/181129954/subaru-goes-greener-plugs-in-the-crosstrek, accessed 2020-03-05. 

[7]       https://plus.lapresse.ca/screens/1ee08d4e-e711-4ece-ba8d-8599239ff27a__7C___0.html.

[8]       https://www.mckinsey.com/industries/automotive-and-assembly/our-insights/making-electric-vehicles-profitable, accessed 2020-03-05. 

[9]       https://www.eei.org/issuesandpolicy/electrictransportation/FleetVehicles/Documents/EEI_UtilityFleetsLeadingTheCharge.pdf, accessed 2020-03-05. 

How Not-to-Succeed in the Next Decade of Energy Transition

The 2020s promise to be a momentous time for the electricity industry, and I wanted to take some time to reflect on what businesses might need to succeed through the energy industry transition. I might have a privileged perspective on this, having worked with utilities, vendors and investors, first in the IT and telecom industries as they went through their transitions, and then mostly in the electricity industry for the last 20 years. This does not mean that I can’t be wrong (I know – I’ve been wrong many times), but perhaps my views will help others be right. 

I’ve structured this post as a series of “don’ts”, based in part on actual IT and telecom examples that I’ve lived through – I’ve put these examples in italic, but I left the names out to protect the innocents. I found that many businesses have short-term views that lead them down dead-end paths, and I might be more useful in showing known pitfalls than trying to predict the future. 

Don’t Fight a Declining Cost Curve

The IT, telecom and, now, electricity industries are all seeing declining cost curves. The best known one is Moore’s Law, the observation that the density of integrated circuits (and hence the cost of computing) halves every 2 years. Moore’s Law is nearly 60 years old and still strong. It gave us iPhones more powerful now than supercomputers of a generation ago, even though my iPhone ends up in my pocket most of the time, doing nothing. These days, the electricity industry sees the cost of wind and solar energy as well as that of electricity storage dropping at a rate of 10% to 20% per year, with no end in sight.[i]

In IT, telecom and, now, electricity, this also leads toward zero marginal cost, the situation where producing an additional unit (a Google search, a FaceTime call or a kWh) costs nothing (or almost nothing). 

During the IT and telecom transitions, many startups proposed solutions to optimize the use of (still) expensive information processing assets. Some sought to extend the life of previous generations of equipment (like a PBX) by adding some intelligence to it (a virtual attendant), while others were dependent on a price point (like dollars per minutes for overseas calls) that simply collapsed (calls are essentially free now). 

If your business case depends on the cost of energy or the cost of storage remaining where they are, ask yourself, what if the cost goes down 50%? That’s only 3 years of decline at 20%/year. After 10 years, costs will be only 10% of what they are now. Can you survive with near-zero marginal costs? If your solution aims to optimize capital costs, will it matter in a few years? Or, will people just do as they do now, with a do-nothing iPhone supercomputer in their pocket?

Don’t Think That Transition Will Go 2% a Year Over 50 Years

Phone companies were depreciating their copper wires and switches over decades. Phone utilities were highly regarded companies, imbued with a duty for public service and providing lifelong employment to their loyal employees. Service was considered inflexible, but everyone could afford a local line, which was cross subsidized by expensive long-distance calls and business lines. Things were simple and predictable.

In 1980, McKinsey & Company was commissioned by AT&T (whose Bell Labs had invented cellular telephony) to forecast cell phone penetration in the U.S. by 2000. The consultant predicted 900,000 cell phone subscribers in 2000 – the actual figure is 109,000,000. Based on this legendary mistake, AT&T decided there was not much future to these toys. A decade later, AT&T had to acquire McCaw Cellular for $12.6 Billion.[ii]

In 1998, I was operating the largest international IP telephony network in the world, although it was bleeding edge and tiny in comparison to AT&T and other large traditional carriers. Traditional carriers were waiting for IP telephony to fail, as the sound quality was poor, it was not efficiently using the available bandwidth, it was illegal in many countries, etc. The history did not play out as expected. In 2003, Skype was launched, the iPhone, in 2006. Today, you can’t make a phone call anymore that is not IP somewhere along its path. 

I’m seeing the same lack of vision in energy industry. For example, the International Energy Agency (IEA) is famous for being wrong, year after year, in lowballing the rise of solar and wind energy in its scenarios.[iii]

Another example is the rise of electric vehicles. There are about 77 million light-duty vehicles sold in the world, and this number is flat or slightly declining.[iv] Of these, about 2 million electric vehicles were sold in 2019, but the number of EVs sold in increasing 50% every year.[v] In other words, the number of internal combustion vehicles is clearly decreasing and the growth is only coming from EVs. Looking at their dashboards, car manufacturers are quickly reducing their investment in developing internal combustion vehicles, especially engines.[vi] Disinvestment in upstream activity means that internal combustion vehicles will fall behind newer EVs and become less and less appealing. It won’t take 50 years for most light-duty vehicles to be electric – a decade, perhaps.

Don’t Count on Regulatory Barriers for Protection

Telecom carriers fought deregulation and competition, teeth and nails. Back in the 1950s, AT&T went to the US supreme court to prevent customer from using a plastic attachment on the mouthpiece of telephones to increase call privacy – it was called Hush-A-Phone. AT&T owned the telephones and forbid customers from using Hush-A-Phone. However, AT&T lost the court battle, and Hush-A-Phone was sold legally from then on. This landmark decision is seen as the start of telecom deregulation in North America.

The IP telephony network that I mentioned earlier was indeed illegal in some of the countries we operated in. It didn’t matter. We had plenty of partners willing to bypass local monopolies, even if illegal in their countries, and customers willing to make cheaper international calls, even if the quality was not always so great. 

Regulatory barriers are only as strong as policy-makers make them. When constituents see an opportunity to save money or simply have choice, they pressure the policy-makers to change the rules – or elect new ones more attuned to moods of consumers. It’s just a matter of time. 

Don’t Take Customers Nor Suppliers for Granted

In 1997, at a time when cellular phones were still a luxury and the Internet was still a novelty, an Angus-Reid survey of the Canadian public put Bell Canada #2 among most admired corporations in Canada[vii], and it had been among the most trusted companies in Canada for decades. Yet, in 2017, Bell Canada ranked #291 in a University of Victoria brand trust survey[viii]. People love their Apple or Samsung phones, are addicted to Facebook to stay in touch with friends, naturally turn to Google for any question, and use Microsoft Skype to see remote family members, but they now mostly hate their phone company. 

Obviously, Bell is still around and making money, but one can only wonder how things could have been if Bell had played its hand differently. (In 1997, none of iPhones, Facebook, Google and Skype existed).

Suppliers to electric utilities should also listen to this lesson. Northern Telecom (Nortel), AT&T Bell Labs and Alcatel were among the large traditional equipment vendors to telephone utilities. However, a startup was founded in 1984, designing routing equipment for IT networks used in university networks. Over the years, it expanded into all sorts of datacom and telecom equipment – all telecom companies eventually standardized on this new vendor. Northern Telecom and the others went bankrupt or were merged and acquired to the point they could not be recognized. In the process, some telephone companies were left with unserviceable hardware. 

This startup company is called Cisco Systems and is now the largest telecom vendor in the world. 

The same pattern is playing out in electricity. On one hand, you have many utilities that do not understand that many customers want choice. On the other hand, you have vendors, like GE and ABB, that are in turmoil. 

Will you be the future Google or Cisco of electricity? Or the next Nortel?

Don’t Follow the Herd

Full disclosure: I’m a career business consultant. Caveat Emptor. 

The reason for this disclosure is that consultants are great at announcing bold trends that often do not pan out. There is a great herd mentality among consultants, and it carries over to their customers. 

Twenty years ago, one of my clients was one of the early Application Service Providers, a business concept where small businesses could access shared personal computer applications over the Internet. The idea was to reduce the cost of maintaining software installed in PCs and to reduce the hardware requirements of PCs. This client was unknowingly fighting the declining cost curve of computers. It went bankrupt (and my last invoices were not paid). 

The concept of application service providers was heavily promoted by consultancies like Gartner, who presented it as the future of business computing. I guess that Microsoft disagreed. 

I see similar fast-fashion concepts going through the electricity industry. Walking the floor at the Distributech Conference in 2018, it was all about microgrids. In 2019, it was distributed energy resources. We will see what will be fashionable in January 2020. 

My recommendation when you hear the same concept over and over again is asking yourself: is this a real trend or am I in an echo chamber? With many new consultants flocking to the electric utility industry – I call them tourists – , you can hear many concepts that are taken for truth but really too complex to be implemented or unlikely in the fragmented regulatory environment that we have. 

Closing Thoughts

In the end, keep cool: sound engineering, good economics and great customer service will always win.

Which leads me to offer you this quote:

If I’ve heard correctly, all of you can see ahead to what the future holds but your knowledge of the present is not clear.
—DANTE, Inferno, Canto X

All this being said, have a great Holiday season and see you soon in 2020!


[i]                 See this previous blog posts, http://benoit.marcoux.ca/blog/lower-and-lower-energy-prices-from-wind-and-solar-pv/, for an in-depth discussion of cost decline in wind and solar energy, accessed 20191220. 

[ii]                See https://skeptics.stackexchange.com/questions/38716/did-mckinsey-co-tell-att-there-was-no-market-for-mobile-phones, accessed 20191220. 

[iii]               See this previous blog post, http://benoit.marcoux.ca/blog/wind-and-solar-pv-defied-expectations/, for a chart of how wrong the IEA has been, accessed 20191220. 

[iv]                See https://www.statista.com/statistics/200002/international-car-sales-since-1990/, accessed 20191220. 

[v]                 See https://www.iea.org/reports/global-ev-outlook-2019 and http://www.ev-volumes.com/country/total-world-plug-in-vehicle-volumes/, accessed 20191220. 

[vi]                See https://www.linkedin.com/posts/bmarcoux_daimler-stops-developing-internal-combustion-activity-6580481304071065600-vRK8, accessed 20191220. 

[vii]               The Fourth Annual “Canada’s Most Respected Corporations” Survey, Angus Reid Group, Inc., 1998, page 5.

[viii]              The Gustavson Brand Trust Index, Peter B. Gustavson School of Business, University of Victoria, 2017. 

EV Charging: an Enabler for Utility Customer Engagement

EV charging is a new type of load for electric utilities – probably the first new type of large electrical load since air conditioning over 50 years ago. A lot is being written about the perils that charging a large number of EV batteries could bring to the grid, but also how shifting EV charging off peak could offset decline in utility revenues. 

However, filling up a car with energy is not new for utility customers. In fact, they are already quite passionate about it. They’ll drive out of their ways to pay less, fueling up on days when price is lower, or driving some distance to get to a cheaper gas station. Multiple apps allow motorists to share tips. Gas station chains offer loyalty program and grocery coupons. Gas stations have become minimarts. Clearly, motorists are deeply engaged with those providers. 

Electric utilities are trying really hard to get their customers to be more engaged. They rightfully see customer engagement as the key to entice customers to participate in energy efficiency and demand management (or response) programs. The problem is that customers generally have no idea how much electricity they use for lighting, entertaining, cooling, heating, cooking, showering, cleaning dishes… This makes customers little responsive and unengaged, especially since these activities have very low emotional appeal for electricity (unless there is an outage during a hockey game). To tell you how bad the situation is, utilities regularly go to conferences presenting EE or DM/DR programs considered to be highly successful with only single-digit percentage of the customer base participating… 

With EV charging, utilities have the opportunity to reset customer engagement – especially as owning and driving a car has much more emotional appeal than, say, cleaning dishes. This is especially true since drivers are used to see how much fuel they use at the pump – there is a direct feedback every few days. We also know that drivers are responding strongly to fuel price signals. 

While much of the discussion on EV charging has revolved around grid-centric issues like peak management and electricity sales, EV charging is also a time-limited opportunity to get their customer more engaged. If electricity distributors are not seizing the opportunity, other players will, and they will fall back to being what they have traditionally been – utility service providers serving passive subscribers. 

I think that electricity distributors can be much, much more, especially in the context of the energy industry transition that we are going through.

Energy Is Cheap; Power Is Valuable

For a while now, I have been saying that we are entering a world where energy (kWh) is cheap, thanks to dropping solar and wind costs, but power (kW) is expensive, needed as it is to balance renewables and peaking new uses, such as electric vehicle charging.[i]

There are not a lot of empirical evidence of this phenomenon, but Ontario offers one. 

In 2005, Ontario decided to move to a “hybrid” deregulated generation market, with a “Global Adjustment” (GA) charge on customer electricity bill that is used to cover the difference between the energy market price (¢/kWh) and rates paid to regulated and contracted generators for providing capacity (kW). The energy market price was intended to reflect the marginal cost of production, with contracts meant to compensate fixed capacity costs. Over time, as contract volumes increased, more and more of the costs of generation became charged through capacity contracting rather than through energy market revenues. In addition, a significant number of zero marginal cost bidders (essentially renewables) were built, further depressing market revenues. As the chart below indicates, a growing portion of generator payments shifted from the energy market onto capacity contracts, which were then charged to customers through the Global Adjustment.[ii]

This is for Ontario, with its peculiar market structure. However, with the advent of renewables and increasing electrification of the economy, we will see the same trend across the world: the capacity-driven cost of the grid will be exposed. The underlying trend is:

Energy, in kWh or MWh, will get very cheap.

Power, in kW or MW, will be very valuable.

For stakeholders in the industry, it means that economic value will be created with services and tools that help manage power, such as shifting peaks. If you own a generation source with non-zero marginal costs and cannot play on a capacity market, you’re in trouble. 

If you think that this is sort of crazy, think about what happened in the telecom market over the last couple of decades. It used to be that local phone connections were relatively cheap, but long-distance phone calls were extremely expensive (dollars per minute for some international calls). Nowadays, long-distance calls are effectively free, thanks to Skype and FaceTime, with video as a bonus. However, Internet access is expensive. 

How will this affect your business?


[i]  See my 2018 posts, http://benoit.marcoux.ca/blog/cea-tigers-den-workshop/and http://benoit.marcoux.ca/blog/a-perspective-on-canadas-electricity-industry-in-2030/.

[ii]  Data for this chart was extracted from http://www.ieso.ca/en/Corporate-IESO/Media/Year-End-Data. Contact me is you want the underlying numbers. 

Book Review: “Branchée: Hydro-Québec et le futur de l’électricité” (French version; in English : “Charging Ahead: Hydro-Québec and the Future of Electricity”)

Jean-Benoit Nadeau and Julie Barlow have published this worthwhile book on Hydro-Québec. I have recently read the French version, and the English translationwill be available on October 15, 2019. I would highly recommend this book to people who need to understand what is driving Hydro-Québec. Electrical system vendors and other industry stakeholders will certainly appreciate the perspective that Branchée/Charging Aheadbrings. However, the authors largely (but not exclusively) rely on internal Hydro-Québec sources and sometimes come across as overly praising the company. Other, more critical, sources might be needed to grasp the complexities of the energy sector in Québec. 

Overall, Branchée/Charging Ahead is a very well-documented book on Hydro-Québec and current strategic directions. Fifty-three people were interviewed, including a large number of Hydro-Québec personnel, up to the CEO, Éric Martel. The book also draws on multiple third-party references and previous article published by the authors. 

Branchée/Charging Aheadstarts with a history of Hydro-Québec. The history of Hydro-Québec innovations is highlighted, with the 735 kV transmission lines being described as “Hydro-Québec’s great technical prowess”[i]. However, this technology dates back to the 1960s’. While there has been nothing remotely comparable since then, the book lists other examples of Hydro-Québec innovations, such as the LineRanger robot, Li-Ion batteries and TM4 electric motors. The book rightfully says that the “commercialization of inventions is an old fantasy of Hydro-Québec. For 30 years, all CEOs have talked about their amazing potential. But their promises have always disappointed.”[ii]TM4 is a good example given in the book: TM4 used up $500 million over 20 years, but Hydro-Québec sold 55% of it to Dana for only $260 million.[iii]

The book contains many noteworthy and hard-to-find current facts and numbers that industry professional might find valuable, such as:

  • As of early 2019, there are 716 prosumers (distributed generators) on Hydro-Québec’s network.[iv]
  • By controlling just 4 baseboard smart thermostats, Hydro-Québec can reduce the peak load of a typical household by 1 kW; Ten smart thermostats lead to a 2 kW saving.[v]
  • Hydro-Québec is running a smart home pilot project with 400 households, intending to launch a new smart home product through an unnamed subsidiary; Sowee, from Électricité de France, is given as a comparable.[vi]

The authors do not attempt to explain their paradox of innovation promises to have always failed Hydro-Québec and Hydro-Québec continuing to heavily invest in innovation. 

Toward the end, Branchée/Charging Ahead provides many insights into the thinking of Hydro-Québec senior managers, including where they see the industry going, how it is going to affect Hydro-Québec, what strategic imperatives ensue, and what Hydro-Québec needs to do. Undoubtedly, vendors could find in here material to enrich proposals and presentations. 

I found very few instances of questionable facts in the book. The Philadelphia Navy Yard microgrid is given as an example[vii], but this project has now been abandoned and is being reborn on a much smaller scale. Economically, I also disagree with the statement that Hydro-Québec is well positioned to develop hydrogen production[viii]– there is far more value in using dispatchable hydro to balance renewable resources than to produce hydrogen from electricity (which is a highly inefficient process). 

Furthermore, I believe that many customers, outside industry expert, vendors or other utilities might object to some praising characterization of Hydro-Québec, such as when the authors state that Hydro-Québec “is one of the best managed electricity grids on the continent and is admired by the largest companies in the industry”[ix]or that it has one of the most reliable grids on the continent[x]. The book would have been more balanced by giving a greater voice to those external stakeholders. Also, given the generally positive perspective that the authors are offering, Branchée/Charging Aheadwill certainly support Hydro-Québec when it tries to gather support for Bill 34[xi].  

All this being said, I greatly enjoyed reading the book and I highly recommend it to anyone wanting to better understand this fascinating company. However, I would caution against drawing conclusions or designing policies based solely on Branchée/Charging Aheadwithout balancing some of the ideas with more independent sources.   


[i]                Chapter 2. Quotes from the book are translated from the French edition. 

[ii]               Chapter 10.

[iii]              Chapter 10.

[iv]               In the introduction and later in chapters 4, 5 and 6.

[v]                Chapter 6.

[vi]               Chapter 6.

[vii]              Chapter 6.

[viii]             Chapter 6

[ix]               In the introduction.

[x]                Chapter 1.

[xi]               See http://benoit.marcoux.ca/blog/bill-34-selling-to-hydro-quebec/for my take on Bill 34. 

Customer Interviews: An Essential Step in Assessing Technology-Driven Companies

Insight

Over time, I had to interview the customers of many energy, telecom and IT companies in the context of due diligence reviews. I got to appreciate the usefulness of this process to really understand the prospects of a company, especially in emerging business-to-business markets. The managers of these companies were often engineers or scientists that did not always listen well to their customers. Often, interviewing just a few customers pointed to a hidden gem or uncovered a fundamental weakness.

Why Should You Interview Customers?

As a venture capital partner, a senior manager of an acquiring company, or an M&A specialist, assessing a target company in the context of an industry transition is daunting. This is especially true right now in the electricity industry, with its complex regulatory frameworks, its worldwide supply chain, dropping energy generation costs, and changing customer expectations. In many ways, customers are the key to understand the transition: they buy electricity, are looking at distributed generation systems, and elect politicians who legislate new regulations. Then, what better way to assess a company than speaking to the company’s customers? These interviews also shed new light on the company’s sales forecast and help identify key areas of improvement.

In this article, I would like to share my experience and to offer some suggestions to help you get the most of customer interviews. I do not simply want to provide you with a checklist of questions. There is a certain art in contacting people, putting them at ease, getting them to speak, using active listening techniques, and having a structured analysis of the results.

Decide on What You Want to Assess

The first step of a successful customer interview program is to decide on what needs to be accomplished. Customer interviews may cover many topics:

  • Relationships between the customer and the company.
  • How the customer identified and selected the company and the product.
  • Who are the main competitors.
  • Responsiveness of the company’s staff facing the customer. 
  • Strengths and weaknesses of the product or the service.
  • Potential enhancements.
  • Reliability and availability of the offering.
  • Current and forecast sales volume with the company.
  • Pricing level and structure of the price list.

Depending on the needs of the company or the investor’s concerns, the interviews may focus on a few specific points. For example, it may be required to assess whether the features of a new energy product meets the needs and buying habits of customers, which also requires that the interviewer have some technical and market knowledge.

Select Interviewees

The company normally provides a list of customer contacts. This list must include the name of the company, the name and title of the contact person, a telephone number and an email address. Obviously, the company will tend to give the names of “friendly” customers. A good question to ask is how many customers have been excluded from the list and why. It could be necessary to examine service or returned merchandise records and to ask to contact some problem customers or even former customers. In order to avoid excessive screening by the company and accounting for unavailability of some customers, it is required to ask for a contact list twice as long as the expected number interviews. It may also be that the number of possible interviews is limited merely by the number of customers. This is especially common for companies using an indirect distribution channel or for early-stage companies. Even interviewing just a handful of customers can bring interesting information, but a greater number is required for a large product portfolio or if the distribution channel is complex or reaches many countries.

Another essential step is to get information on the customers being contacted. This information is obtained from internal sources and external sources. In a due diligence, it is common to verify material transaction records or contracts. If the interview program aims at validating these documents, it is necessary to have them in hand during the interviews. External sources, such as the company’s Internet site and the associated LinkedIn, Facebook and Twitter profiles should also be read prior to an interview. 

Many startup technology companies accelerate market entry through an indirect sale channel of distributors and OEM agreements. For example, in a recent case, the channel is comprised of national distributors, local dealers, customer companies and end users. Interviewing representatives at each layer of the distribution channel leads to better data than only interviewing one set of intermediaries. Similarly, it is ideal to contact people from various business functions (operations, marketing, upper management, etc.).

When approached professionally, people are usually genuinely interested in helping a supplier. However, many interviews may fail because of customer time constraints and last-minute emergencies. Also, pay attention to the order of the interviews. Some customers will be recognized as more important and should be interviewed at the end of the process in order to first practice with other customers. Similarly, in the case of a distribution channel, it is preferable to start with the end users in order to validate the selection of the distributors.

Get the Logistics Out of the Way

High-tech companies are often exporting a large share of their products. Interviews must then be done by telephone to minimize costs. Although convenient and inexpensive, telephones raise communication barriers that must be minimized. For international interviews, language can also become an issue.

The telephone is a somewhat impersonal communication system, and the use of videoconferencing is too complex. Even for a phone interview, it is preferable to make an appointment. Appointments are especially important if interviews have to be at unusual hours because the customer is overseas. To make the communication more personal, I take advantage of the email confirming the call to send a picture of myself. It is a simple gesture, but a good way to begin breaking the ice. 

It is important not to be disturbed during the interview. Also, keep a pencil in hand to scribble notes to remember to raise some points later during the interview. Finally, a headset frees the hands and permits more natural and relaxed posture and voice.

Have an Interview Guide

We are talking here about general guidelines, and not a rigid script. To get the most from an interview and to keep its natural character, it is necessary to deviate from the expected course and to take advantage of twists and turns of the discussion. The interviewee must not feel interrogated, but in confidence to talk about points that could be sensitive. 

Some base rules in preparing an interview guide include:

  • Agreeing with the interviewee on objectives and duration at the start of the interview.
  • Establishing an atmosphere of trust by offering anonymity.
  • Starting with mundane topics (ex.: confirming the contact’s title) and progressing toward more sensitive issues (ex.: prices).
  • Going from general to specific topics.
  • At the end, asking for global assessments of the company and its products.

Make the Interview Dynamic

Active listening is a good way to get someone to speak more and to ensure that what has been said is well understood. Using open questions (ex.: “How would you qualify the technical knowledge of the customer support staff?”) is preferable to closed questions that are answered by yes or no (ex.: “Is the customer support staff qualified?”).

Lighten the atmosphere by offering tidbits of information, for example by sharing experiences or by giving information previously obtained (“While speaking to other customers, I heard that… Would you agree?”). This transforms the call from a one-way questioning session into a two-way discussion. Obviously, an interviewer with some knowledge of the industry can better get into bilateral exchanges, especially for technology products.

It is important to keep a polite and respectful tone. Appreciate the fact that interviewees are without pay and may be very busy. Thanking people with a small gift after the interview is a mark of appreciation and can help strengthen the future relations with a customer, but first make sure not to breach company policies. 

Analyze the Results

The interview logbook that I use regroups in a table the highlights of the interviews. The table, which spreads over several pages, presents the salient pieces of information gleaned of the interviews organized in columns according to the structure of the original interview guide. At a glance, it is then possible to do cross references on the main topics. The interview logbook is a convenient analysis tool that supports results presentation while permitting to drill down quickly to specific points and to compare what customers have said. For example, it becomes easy to see if end-user perceptions are the same as those of distributors. It is just as revealing to make comparisons between what people from different functional groups have said. 

The analysis can point at possible corrective actions and opportunities. It may also support revised sales forecast. A customer’s marketing staff does not see the same benefits as the end users? There could be an opportunity to better communicate features and functions, or perhaps to review product packaging. Are the dealers waiting for the next version of the product before promoting of it? It could be worth to pay close attention to the product development schedule. Do distributors, fearing technical problems, only want to introduce a new product gradually? Maybe the sales forecast should be pushed back one quarter. Obviously, an investor may judge the situation too uncertain and decide against proceeding.

Plan Enough Time

For a typical half-hour phone interview, an experienced person will have to prepare by making an appointment and reading information. One or two hours are required to write down notes and fill in the interview logbook for each interview. You should plan for at least 3 hours of sustained work for each interview. 

To this, add the preliminary work for selecting interviewees and adapting the interview guide. This can evidently take longer if the interviewer cannot rely on prior work. Analysis and presentation of the results can be formatted in a slide show or a formal report. Analysis and presentation can also be integrated to a global due diligence report. Regardless of the format, count on a minimum of one day of preparation and 2 or 3 days of analysis and writing for a 10-interview program. For a complete and professional result by an experienced interviewer, budget about 8 days of sustained work for a 10-interview program. The work will have to take place over 2 or 3 weeks assuming normal delays for reaching interviewees. 

To this point, one can appreciate why interviews are often outsourced to a third party. Some customers could be unwilling to speak directly to a supplier’s investor. Besides, experience shows that close to half of people interviewed ask for some anonymity – they are more willing to speak to a seemingly neutral party. Furthermore, a report prepared by an external firm will have greater weight when presented to other investors involved in a transaction. 

Closing Words

Making good interviews is an art that takes some practice. To take advantage of the experience, stop a moment, think about what could have been done better, and update the interview guides. The interview skills will also improve over time.

How Bill 34 Will Affect Vendors Selling to Hydro-Québec

The Government of Québec has tabled Bill 34[1]that simplify the rate-setting process for Hydro-Québec Distribution.[2]Essentially, most distribution rates are frozen for 2020, and then adjusted for inflation until 2025, when a rate review would occur. Additionally, the bill requires Hydro-Québec to reimburse to customers of some $500 million before 1 April 2020.[3]It should be noted that Hydro-Québec currently has the lowest residential rates in North America.[4]

This Bill is a significant change from the traditional rate base rate-of-return regulation that previously subjected Hydro-Québec to yearly rate filing. Based on my personal marketing experience in the electricity industry, this post outlines my views of how Bill 34 may change some of Hydro-Québec business drivers when dealing with its vendors, presumably leading Hydro-Québec to faster decision-making in purchasing, smarter assessment of costs, and a greater appetite for innovative solutions.

Before: Traditional Rate Base Rate-of-Return Regulation

The electricity distribution business is a natural monopoly. This means that it is in the interest of society to have just one distribution utility in a given territory. It is easy to understand the rationale: you would not want to have multiple sets of poles along roads; one set is more than enough. However, left to itself, a distribution utility with a monopoly could charge unreasonable rates for use of its bottleneck facility.[5]

In most of Canada and the United States, electric utilities are regulated using a traditional rate base rate-of-return regulation regime. Under this regime, the sum of all regulated costs – essentially operating expenses, depreciation on assets (resulting from past capital expenditures), interests on debt, taxes, as well as an allowed shareholder returns on investments (i.e. a reasonable profit) – are recovered from customers. This is called revenue requirement or required revenues. Required revenues are allocated across the customer base in a variety of ways, primarily on the basis of the energy distributed (cents per kilowatt-hour, ¢/kWh), as well as peak load (dollars per kilowatt, $/kW) for some commercial and industrial customers. In practice, different classes of customers get different rates, but revenues projected during a regulatory rate case have to be equal to revenue requirements. If there is a significant variance between the projected revenues and the actual revenues in a year, adjustments are normally made in subsequent years.[6]

Obviously, regulated utilities are not allowed to spend anyway they want: they have to prove to their provincial regulator – the Régie de l’énergie in Québec, the Alberta Energy Board, the Ontario Energy Board, etc. – that their costs (both operating expenses and capital expenditures) are necessary and prudent. These arguments are aired during public rate cases – yearly in the case of Hydro-Québec, up to now – during which various interveners, typically representing customer groups, submits reports and ask questions. The process can be slow, adversarial and excruciating as all details of operations are looked at and need to be justified – the regulator often does not trust the utility and even activities and investments that a utility may present as essential may not be approved. 

Rate-of-return regulation of utility monopolies has served relatively well as a market substitute for a century, but it has its drawbacks. I’ll retain three issues for discussion here: slow innovation, poor service quality, and uneconomic decisions.

Innovation tends to be among the casualties of rate-of-return regulations: the slow regulatory cycle, the public scrutiny and the second-guessing by interveners makes utilities extremely risk-averse and slow to integrate new technologies. For example, as part of rate cases, utilities sometimes specify models of power equipment, which become the standard products used in the network. Because another complex homologation process would get in the way, product selection may not be revised for many years, even decades, often until the vendor cease production. However, over time, utilities often end up customizing those products, based on experience or new needs, rather than seeking newer products. 

Rate-of-return regulation is an economic form of regulation that does not properly account for service quality. It is difficult to integrate service quality metrics in this regulatory framework and offering varying levels of service quality depending on willingness to pay is not practical. Not surprisingly, electric utilities tend to have negative Net Promoter Scores (NPS), a loyalty measure, with generally far more detractors than promoters among customers.[7]

Since their revenues are practically known in advance following rate setting, regulated utilities look at their business upside-down in comparison to companies operating in a competitive, free market:

  • Shareholders earn a return on all utility assets – the more, the better. New investments mean a larger asset base, on which the shareholders are allowed to claim a return, meaning that net income will also be higher. There is a strong incentive for utilities to buy more equipment or to gold-plate it, although interveners may oppose, and regulators may not agree. 
  • Regulated utilities effectively pass operating expenses to their customers. Indeed, lowering (or increasing) operating expenses simply lowers (or increases) required revenues, but net income remains unaffected. Yet, the regulatory process tends to compress controllable operating expenses (like customer service or maintenance) in expectation of raising efficiency by the utility. Utilities may actually go along, shareholders preferring to compress operating expenses than investments in assets. 

For vendors, traditional rate base rate-of-return regulations mean that making normal sales arguments often does not make sense in a utility world: 

What vendors may sayWhat utility people may think
“You would be the first in the industry to implement this new technology.”“…And go through hell trying to get it approved.”
“You’ll save on capital expenditures with this new equipment.”“Why would we do this? Shareholders want to justify more capital expenditures, not less.”
“You’ll be making more profit by adopting my cost-saving solution.”“No, we’ll have to pass on the savings to customers at the next rate case and not make more profit.”

Surprisingly, it seems that few vendors understand this traditional utility buying logic, although it is very much the normal case across Canada and the United States. However, Bill 34 is changing all this in Québec.

What Is Bill 34 Changing?

Bill 34 freezes most distribution rates for 2020, followed by yearly adjustments for inflation until 2025, when a rate review would occur. Therefore, Hydro-Québec would no longer have to file rate applications, with detailed costs justifications, every year. Under the Bill, Hydro-Québec is not required to obtain authorization for its infrastructure investment projects and changes to the electricity distribution network. Similarly, commercial programs do not need approval. In contrast to traditional regulation, Bill 34 effectively disconnects costs and revenues for 5 years and should introduce more common business decision-making. 

Bill 34 also stops the Régie efforts to move to a Performance-Based Regulation (PBR). PBR is increasingly popular to regulate utilities[8]. In Canada, Alberta has adopted PBR.[9]Another good example is Great Britain, with its RIIO (Revenue = Incentives + Innovation + Outputs) framework.[10]PBR generally aims to balance multiple variables, such as quality of service and costs, while freeing utilities to innovate. Without presuming of the rationale behind Bill 34, it may be that the very low costs of electricity in Québec in comparison to the jurisdictions where PBR was implemented, as well as Hydro-Québec’s renewable generation fleet, present a simpler approach toward the same objectives. 

After: Faster, Risk-Taking and Innovative?

Hydro-Québec remains a natural monopoly, without direct competitive pressure. However, with Bill 34, decision-making should become much closer to that of “ordinary” commercial business, with a new-found flexibility and a greater drive toward efficiency and business innovations. Hydro-Québec will be incentivized to reduce costs to increase net income, as revenues will be stable (after inflation). In particular, the new framework removes the bias toward capital expenditures and rewards a smarter control of operating expenses. For instance, with greater flexibility, Hydro-Québec might increase maintenance and extend life of some power equipment at the same time that it might replace other assets with advanced systems – all in the name of efficiency.

All this may change how Hydro-Québec will interact with equipment and service vendors, although any change to purchasing decision-making will undoubtedly depend on management decisions and may be slowed by the natural inertia of the company. 

Nevertheless, Hydro-Québec may become more open to acquire new products and services from new vendors, with a corresponding risk for established vendors. High-end or customized (and therefore more expensive) products from established vendors may be especially at risk of substitution by less expensive or industry-standard ones. In some cases, the number of vendors supplying a type of product dwindled to just one over the years; it now may be that Hydro-Québec will seek to split contracts with a competitor to try to bring down costs on commodity products. On the other end, like common in other industries, Hydro-Québec may also seek broad strategic partnerships for more complex products, with favorable contract terms for Hydro-Québec in exchange for a vendor exclusivity in some product categories. 

With the greater flexibility brought by Bill 34, Hydro-Québec may also become more inclined to try out innovative products or systems in its distribution network, and we could see faster decisions to deploy those innovations. This might come at an opportune time, as other utilities introduced new grid technologies in order to support distributed generation (especially solar) at a very large scale[11]; Hydro-Québec could learn from the vendors involved in these deployments.

Similarly, Bill 34 might enable Hydro-Québec to accelerate the launch of new products or services to its customers, possibly in collaboration with external vendors. Hydro-Québec has been innovative in researching new uses for electricity and energy efficiency system, going as far as building houses to test smart home technologies.[12]Hydro-Québec publicly expressed interest in how smart home, solar generation, energy storage and microgrids could impact its network.[13]Other utilities have already introduced services and products to their customers around these concepts, like BC Hydro (CaSA smart thermostats)[14], Green Mountain Power (Tesla batteries and FLO smart electric vehicle chargers)[15], Hydro Ottawa (Google smart assistant),[16]and many more; it would not be surprising to see Hydro-Québec following suit. 

What May Not Change

While Bill 34 will change many things, some important practices should remain. For example, Hydro-Québec is extremely serious about cybersecurity[17]; vendors should still expect to have to meet stringent cybersecurity requirements, for good reasons. As a Québec crown corporation, Hydro-Québec also remains subjected to normal government buying policies, like requiring bids beyond certain amounts and strict rules when dealing with vendors[18]– this too will remain. 

Contrary to performance-based regulatory regimes like RIIO in Great Britain (see above), Bill 34 does not provide explicit incentives to improve the reliability of the electricity service. While this is not a change from the current regulatory regime, it should be noted that the reliability of Hydro-Québec electricity services has been degrading over the last years.[19]However, repairing the network after an outage does cost money, and some vendors could highlight how their solution prevent outages or reduce the cost of repairs. Furthermore, Hydro-Québec management could conclude that maintaining sufficient reliability is essential to avoid a decision to return to traditional regulation in 2025. 

Also, Bill 34 specifically maintains Hydro-Québec’s obligation to file an annual report. Those reports include a wealth of information on the organization, the performance and the financial situation of Hydro-Québec.[20]

Finally, utilities, including Hydro-Québec, publish public performance indicators.[21]Usually, those indicators are also used in management incentive plans. Showing the impact of a solution on performance indicators will remain a sound sales tactics when selling to utilities. 

Closing Words

Once Québec’s national assembly adopts Bill 34, probably in the Fall, it will certainly become an experiment that will be carefully watched by Canadian regulators. Leveraging the low costs of renewable electricity in Québec, it may encourage greater efficiency and business performance by Hydro-Québec, without the complexity of a performance-based regulatory regimes. 

For vendors, the Bill may also fundamentally change how Hydro-Québec should be approached, with potentially a much greater attention to total costs and partnerships than before. 

Do not hesitate to contact me to discuss further. 

Benoit Marcoux, benoit@marcoux.ca, +1 514-953-7469.


[1]               See “An Act to simplify the process for establishing electricity distribution rates”,  http://www.assnat.qc.ca/en/travaux-parlementaires/assemblee-nationale/42-1/journal-debats/20190612so/projet-loi-presentes.html, accessed 20190614.

[2]               Bill 34 only affects the distribution division of Hydro-Québec. The transmission (TransÉnergie) and generation (Production) divisions are not affected. 

[3]               See http://news.hydroquebec.com/en/press-releases/1510/electricity-rates-adoption-of-a-simplified-approach-that-will-guarantee-low-rates/, accessed 20190620. 

[4]               See http://www.hydroquebec.com/residential/customer-space/rates/comparison-electricity-prices.html, accessed 20190615.

[5]               Note that the natural monopoly does not extend to energy retail and generation. In many jurisdictions, notably in most of Alberta, Texas and Europe, there are many energy retailers buying electricity from generators and offering various plans to customers. However, this energy is supplied through electricity distributors that have the poles and conductors up to customers’ homes. In Canada, provinces other than Alberta and Ontario have only vertically integrated distributors and retailers, i.e., the distributor is also the only retailer of electricity. 

[6]               To some extent, Bill 34 is the result of lack of adjustments from over-earning in previous years, as the provincial government, owners of Hydro-Québec, kept these surpluses. This resulted in a delicate political situation, as many people saw this as a disguised tax.

[7]               See CEA Opinion Research, 2014 National Public Attitudes for NPS of Canadian utilities, and https://en.m.wikipedia.org/wiki/Net_Promoter, accessed 20190615, for an overview of the concept. 

[8]               See http://go.woodmac.com/webmail/131501/471713673/8ec22b38df7f81ef4f8278af14095e1bb711214dffd0ee90dc9a250ab8bb5970, accessed 20290619, for an overview of PBR adoption in the United States.

[9]               See http://www.auc.ab.ca/pages/distribution-rates.aspx, accessed 20190615.

[10]             See https://www.ofgem.gov.uk/network-regulation-riio-model, accessed 20190615.

[11]             For example, there are 840,878 residential solar projects in California (https://www.californiadgstats.ca.gov/charts/, accessed 20190617) but only about 700 in Québec (see https://www.lapresse.ca/affaires/economie/energie-et-ressources/201903/22/01-5219334-mini-boom-de-production-denergie-solaire-au-quebec.php, in French, accessed 20190617). Integrating a large number of distributed generators in a distribution network is challenging, and utilities in some other jurisdictions had to innovate to make it work.

[12]             See https://ici.radio-canada.ca/nouvelle/1016006/hydro-quebec-maisons-futur-shawinigan-energie-solaire-thermostats(in French), accessed 20190617.

[13]             See http://plus.lapresse.ca/screens/f2ad982b-9fda-469f-a3f2-86116ab0a46a__7C___0.html(in French), accessed 20190617.

[14]             See https://www.bchydro.com/powersmart/energy-management-trials/casa-thermostat-trial.html, accessed 20190617. 

[15]             See https://greenmountainpower.com/products-all/, accessed 20190617.

[16]             See https://hydroottawa.com/save-energy/innovation/smart-audio, accessed 20190617. 

[17]             For example, Hydro-Québec is funding an industrial research chair in smart grid security at Concordia University – see  http://www.nserc-crsng.gc.ca/Chairholders-TitulairesDeChaire/Chairholder-Titulaire_eng.asp?pid=981, accessed 20190617.

[18]             See https://www.hydroquebec.com/suppliers/becoming-supplier/safe-ethical-and-responsible-procurement.html, accessed 20190618.

[19]             The average number of minutes of outages per Hydro-Québec customer, excluding major events like storms, has been steadily increasing, from 126 minutes in 2013 to 181 in 2018. See http://www.regie-energie.qc.ca/audiences/RappHQD2013/HQD-09-02-Indicateursdeperformance.pdfand http://publicsde.regie-energie.qc.ca/projets/501/DocPrj/R-9001-2018-B-0060-RapAnnuel-Piece-2019_04_18.pdf, respectively for 2013 and 2018, in French, accessed 20190617. 

[20]             See http://www.regie-energie.qc.ca/audiences/RapportsAnnuels_DistribTransp.html, accessed 20190615, for past annual reports in French.  

[21]             See http://publicsde.regie-energie.qc.ca/projets/501/DocPrj/R-9001-2018-B-0060-RapAnnuel-Piece-2019_04_18.pdffor Hydro-Québec’s 2018 performance indicators, in French, accessed 20190618. 

Digital Utility of the Future Conference

Last month, I chaired the Digital Utility of the Future Conference in Toronto (http://ikonnect.world/DigitalUtilitiesoftheFuture2/). Based on feedback from many participants, the event was a clear success and I am looking forward to the 2020 edition. Having mostly been out of the country on business since then, I would now like to share some reflections on the event.

First, the multiple presentations highlighted the extent to which digital technologies now permeate the utility world. The energy transition adds tremendous sophistication to the electricity distribution network, relies on renewed engagement by customers, and brings many new regulatory and environmental constraints. As the transformation of other industries have shown, such complexity can only be dealt with through better management of corporate resources, especially information.

Second, adapting to the energy transition and leveraging information a big task. The rule book is still being written. Many innovations were presented. In a few years, we will look back at some of these ideas and admire the foresight of their promoters; other ideas will be dead ends. However, it is clear now that the future of the utility industry will depend on innovations to a much greater extent than was the case a few years ago.  

Third, participants were a mix of utility and vendor representatives, with many presentations being made by representative from both. I think that the best combination. Utilities know their business but may be insulated behind a regulatory wall. Vendors see multiple clients, inside and outside the energy industry, but may not understand all the subtilities of a regulated business. Having both can get sparks flying (in a good way). 

Finally, I would like to thank all participants, sponsors and presenters. I think that we all had a great time debating what the digital future of utilities may look like.

“The Shocking Business of Electricity”: A Short Lecture to McGill Business Students

Today, I am grateful to have been able to present some aspects of the electricity business to business students at McGill University, where I did my MBA many years ago. It was great fun.

Here is the short deck that I presented.

Mcgill University 20190227