Category Archives: Business Models

Comment la chaîne de valeur de l’électricité au Québec se compare au reste du monde

shape, polygon

Dotée d’une hydroélectricité abondante, la chaîne de valeur de l’électricité du Québec s’est développée à sa façon. À titre de comparaison, la figure ci-dessous illustre les rôles communs des différents acteurs qui fournissent de l’électricité dans le monde.

En Europe, au Royaume-Uni, dans la plupart des États-Unis et en Ontario et en Alberta, des acteurs discrets remplissent chacune des cases du diagramme. Plus particulièrement, les producteurs vendent de l’électricité sur les marchés de l’énergie, achetée par des détaillants indépendants pour la revendre aux clients finaux. Les détaillants ne vendent que de l’énergie et ils ne sont pas propriétaires du réseau reliant les producteurs aux clients. Les détaillants peuvent être des entreprises privées concurrentielles ou des organismes publics sans but lucratif, selon les régions. Le flux d’électricité des producteurs aux clients est contrôlé par un opérateur de système indépendant. Les réseaux de transport et de distribution, qui sont des goulots, sont réglementés sur le prix, souvent avec des incitations à la fiabilité et aux coûts. Mais, dans l’ensemble, c’est la même chose que vous (le client) ayant un accès Internet filaire d’une société de téléphone ou de câblodistribution (c.-à-d. le réseau) pour ensuite acheter des services multimédias vendus par Netflix ou Apple (c.-à-d. les producteurs).

Au Québec, Hydro Québec est le producteur, le transporteur et le distributeur dominants. Elle a son propre opérateur de système interne et utilise des appels d’offres et des contrats gré à gré, et non un marché, pour acheter auprès de certains producteurs d’électricité indépendants. La vente au détail d’électricité est fournie avec la distribution d’électricité et il n’y a pas d’agrégateurs pour la gestion des pointes. Il y a très peu de stockage sur le réseau (autre que les vastes réservoirs) et peu de ressources énergétiques distribuées (RÉD). L’organisme de réglementation provincial n’approuve plus les dépenses du service public et les prix de l’électricité, maintenant rattachés à l’indice des prix à la consommation, jusqu’à concurrence de 3 %.

Le dégroupement de la chaîne de valeur de l’électricité du Québec, en partie ou autant qu’en Europe, ne peut se faire sans évaluer les avantages et les inconvénients de cette approche. Cependant, nous devons certainement regarder comment d’autres ont fait face à la rareté d’électricité alors que nous nous prélassions dans l’abondance. Parce que, après tout, il y aura plus de rareté que d’abondance à l’avenir.

How Québec’s Electricity Value Chain Compares to the World

polygon

Endowed with abundant hydropower, Québec’s electricity value chain developed in its own way. For comparison, the figure below illustrates the common roles of the various players delivering electricity to the world.

In Europe, the UK, most of the US and in Ontario and Alberta, discrete actors fill each of the boxes in the diagram. Most notably, producers sell electricity on energy markets, bought by independent retailers for resale to end customers. Retailers only sell energy and they do not own the grid connecting producers to customers. Retailers can either be competitive private ventures or not-for-profit public agencies, depending on regions. The flow of electricity from producers to customers is controlled by an independent system operator. The transmission and distribution grids, which are bottleneck facilities, are regulated on price, often with reliability and cost incentives. But, overall, this is the same as you (the customer) having a wired Internet access from a phone or cable company (aka the grid) and then buying media services sold by Netflix or Apple (aka producers).

In Québec, Hydro Québec is the dominant producer, transmitter, and distributor. It has its own internal system operator and uses tenders and negotiated contracts, not a market, to buy from some independent power producers. Electricity retail is bundled with electricity distribution and there are no aggregators for peak management. There is very little grid storage (other than the vast reservoirs) and few Distributed Energy Resources (DER). The provincial regulator no longer approves spending by the utility and the electricity prices, now pegged to the consumer price index, up to 3%.

Unbundling Québec’s electricity value chain, partly or as much as it is in Europe, cannot be done without assessing the pros and cons of this approach. However, we certainly need to look how others have coped with electricity scarcity while we basked in abundance. Because, after all, there will be more scarcity than abundance in the future.

Community Choice Aggregation: An Alternative for Québec’s Electricity Future?

With Hydro-Québec, Québec is endowed with incomparable natural resources, including unique hydroelectricity potential and electricity system. Its electricity system is also highly integrated, from generation to customers. 

Other regions, facing more difficult energy choices, adopted different industry structures. I want here to explore a strong trend in the US and see how we could be inspired by it: Community Choice Aggregation (CCA). 

Community Choice Aggregators (CCA) are not-for-profit public agencies having some electricity retail exclusivity in an area. CCAs allow local governments (cities and counties) to procure energy on behalf of their residents, businesses, and municipalities while still receiving transmission and distribution service from their local utility provider. By aggregating demand, communities gain leverage to negotiate better rates with competitive suppliers and choose greener power sources. Being local, CCAs may also be better positioned to offer services and energy efficiency programs tailored to their communities. 

There are over 1200 CCAs in the US serving 10.6 million customers across 8 states. In 2022, approximately 100 terawatt-hours (TWh) of electricity was procured by CCA communities. Communities that participate in CCA programs negotiate their source of energy generation, use bulk buying power to decrease energy costs, spur the development of local renewable energy resources and local clean energy jobs, ensure energy price stability and transparency, while accelerating the transition to renewable energy with every initiative. CCAs work in partnership with the region’s existing utility. The CCA buys the power, and the utility continues to deliver it, maintain the grid, and provide consolidated billing.

Could this be adapted to Québec? Perhaps, why not? I’m not saying that this is the solution, but it may be a tool to think about.

I have been following this trend for a few years now, so reach out to me if you want to discuss. 

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.

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.

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. 

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. 

“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

A Trojan Horse: Time-Varying Rates

A majority of Canadian households and small businesses are in provinces where time-varying rates or peak pricing or rebates are available or proposed, thanks to smart meters installed over the last few years. Tariffs for large business already include a demand charge that makes up a big chunk of their bills, inciting them to have a constant power draw. Many businesses also have critical peak pricing or rebates. Therefore, most of the electricity in Canada is sold to people having financial incentives to not only be energy efficient (i.e., consume fewer kWh overall), but to manage when electric power is drawn from their utility. However, with the possible exception of large electricity users, most customers simply do not want (or can’t) manage the minutia of consuming electricity on an hourly or daily basis. This is to be expected, as it’s a lot of work and inconvenience for little pay: running the dishwater off-peak rather than on-peak may save a dime, but it means noise when people are trying to sleep and emptying it during the morning rush to school or work. Although all the saved dimes may add up to significant dollars at the end of a year, human nature makes us lazy, and we just go on whining about high hydro cost instead.

In aggregate, everybody’s dimes also add up to a lot of money for the society. For most people and businesses, electricity is not something to get passionate about. It is a significant – but not the largest – component in the budget. We mostly notice electricity when it is not there, as we can’t do much without it. Most people don’t know or care how electricity get to them, as long as they can benefit from it and that its rates appear to be fair. The significant yet stealthy nature of electricity makes it the perfect commodity. Electrons have no brand, no color, no flavor. It becomes easy to rationalize outsourcing the management of electricity to a third party if it reduces cost and make our lifes easier.

Time-varying rates and peak pricing or rebates thus create the financial incentives for new energy services to emerge and help individual customers save money – they are a Trojan horse inside the utility castle. Essentially, energy service companies are introducing themselves in the value chain – it’s a form of value-added intermediation, although energy service companies are not allowed to resell in most provinces. In addition to rate arbitrage, the business model of energy service companies leverages the dropping cost of rooftop solar power and energy storage, supported by mass-market smart home devices (for residences) or off-the-shelf building management systems (for businesses) connected over the Internet. Lower electricity costs with cool gadgets and better comfort. Voilà! A competitor is born.

Energy service companies are offering what amounts to a partial substitute for electric utility services. Rooftop solar panels, batteries, smart home thermostats, water heaters and lighting, building management systems, EV chargers, thermal storage and other technologies marketed by energy services companies, engineering firms and solar developersdo not replace mains electricity. However, energy service companies provide financing and remove the complexity of managing electricity rates and provide other benefits such as comfort or backup during outages. In the process, energy service companies capture a decent chunk of the electricity value stream as they turn electricity service into even more of a commodity service. Less energy (kWh) gets delivered by utilities, pushing rates up for all, although few customers will actually go off the grid.

Storms on the horizon. Ouch. That’s competition, and it is new for many in electricity utilities.

Energy service companies are not directly competing with utilities – not like, say, Bell or Telus competing with Rogers or Vidéotron – but it is competition nevertheless – a bit like Bell being in a strange love-hate relationship with Google. In fact, customers must buy still their electricity from their local utility in most provinces[i]. If energy service companies are not direct competition, it has almost the same effect: skimming profitable segments.

Canadian generation, transmission and distribution utilities are affected at different levels and in varying ways, depending on provincial regulations and on their position along the electricity value chain.

One issue is that the tariffs structure for electricity generators and for T&D networks poorly reflects the underlying system cost structure. If rates along the electricity value chain were perfectly set, then utilities should not care if customers shift their energy consumption – after all, that’s the objective of time-varying rates and demand charges. In practice, rates are far from perfectly matching costs. For example, demand charges for small business accounts are typically set for a year or two based on the peak power demand (in kVA) in a past month. This rate structure is essentially a leftover from electromechanical meters where a meter reader would come to a business every month to read energy (kWh) and power (kVA), and then reset the power register on the meter with an actual physical key – the power register would ratchet up until the next read, when they would be reset again. That’s as good as it could be with electromechanical meters, but the maximum demand that was registered didn’t likely coincide with the peak demand on the system. The resultant tariffs structure incites business customers to minimize monthly maximum demand (and, hence, demand charges), but still allow them to draw a lot of power during a system peak, although energy management systems could have reduced demand during the peak and shift it to a different time. Working on behalf of their customers, energy service companies may end up optimizing customer demand around prevailing tariffs to minimize customer charges but may increase overall system costs in the process.

Upstream in the value chain, traditional generators and independent power producers are affected by energy efficiency and demand management initiatives that can potentially reduce energy and power demand of customers. The effects vary depending on the market structure in each province. Contracted generators are less exposed; in Ontario, the “global adjustment” mechanism compensates large generators, while Alberta has a capacity market. However, spot generators may face large variations in prices. Overall, generators are at risk of having stranded assets as energy efficiency improves in the economy and as customers contract with energy service providers to better manage power demand.

Many distribution-only utilities in Canada are partially shielded[ii]. They charge their customers a energy and power rates set by the province and a separate distribution charge that is intended to pay for the costs of their stations and network. The energy and power generation charges are pass-through, and transmitters and generators bear any issues. The distribution charge is often allocated on a per-kWh basis, plus a fixed monthly charge. Because of the per-kWh allocation of their costs, local distributors are somewhat exposed to the vagaries of energy service companies. However, the distributors have more operating costs and lower capital costs than transmitters and generators, meaning that a per-kWh distribution charge is not as far off the mark.

Mid-size municipal utilities also face a different reality than large integrated provincial utilities. Owned by the city, they are accountable local actors, close to their customers (or constituents), using their agility to respond to issues in a way that is just not happening with large integrated utilities. Municipal utilities become instruments of the local mayor and city council, like water, sewers, snow removal and other municipal services. Mayors’ challenges are about their constituents getting sick, having clean water, being warm or cool, holding productive jobs, commuting efficiently, surviving disasters. They see that the local utility supports the needs of a smart city, to be both resilient to face increasing disasters and be sustainable to reduce its environmental impact and to improve quality of life – while being financially affordable. In this context, working with third parties, like energy service companies, just becomes another means to satisfy the needs of citizens and local businesses[iii].

Large vertically integrated provincial utilities face more complex challenges than municipal utilities: the impact of energy service companies on generation can be significant, the feedback loop from constituents to the government and the utility is more tenuous, the customer base has more varied needs, and the integrated utility has a large impact on the finances of the province. Not surprisingly, they tend to prefer to maintain a greater control over the relationship with customers. Whether they can maintain control and reduce choice without antagonizing customers is uncertain, especially when consumers get used to energy service alternatives ranging from large telecom companies to Google and Amazon.

 

[i]       The exceptions are Alberta, the most deregulated market in Canada, and Ontario, although wholesale and retail rates in Ontario are such that about95% of Ontarians choose to buy electricity from their local utility. See https://business.directenergy.com/what-is-deregulation#deregmarketand https://www.oeb.ca/about-us/mission-and-mandate/ontarios-energy-sector, retrieved 20181023.

[ii]      However, municipal utilities in Québec pay large business rates, with demand charges.

[iii]     And, perhaps, in the process, help the mayor get re-elected.

The Sun for a Penny

I recently presented at the Canadian Electricity Association (CEA) on the future of the industry. What would happen to the power industry if the cost to generate solar electricity reached 1¢/kWh? What could be the impact of a carbon tax? What are the business opportunities arising from the need for reliable power? While electric utilities have seen tremendous transitions during the 125-year history of the CEA, the current rate of development is unprecedented. To paraphrase a famous quote by Wayne Gretzky, utilities need to “skate to where the puck is going to be, not where it has been.” This presentation tried to provide power utilities with some insights into the future direction of the puck! See the presentation here: The Sun for a Penny 20170225a