Author Archives: Benoit Marcoux

About Benoit Marcoux

In over 35 years working in telecom and energy industries, including 20 in consulting, I have designed systems, financed them, sold them, manage multi-million implementation programs, and ran large service operations. Always a bit of a nerd, I am passionate about how digital technologies transform entire industries and I accompany my clients in this tortuous journey. I graduated as a professional engineer and went on to complete a Master degree in Applied Sciences and an MBA.

Ce que signifie l’électricité à coût marginal zéro

Leave a reply

La majeure partie de l’électricité produite dans le monde provient de la combustion du charbon ou du gaz naturel. Le nucléaire, l’hydroélectricité, l’énergie éolienne et l’énergie solaire à faibles émissions constituent le reste de la production. (J’écris ceci du Québec, où l’électricité provient principalement de l’hydroélectricité.) En d’autres termes, pour la plupart des gens dans le monde, utiliser un kilowattheure d’électricité, c’est un peu comme brûler un peu de charbon ou de gaz naturel. Mais cela change rapidement : en 2025, l’Agence internationale de l’énergie montre que la part des sources à faibles émissions se rapproche des combustibles fossiles dans la production mondiale d’électricité.

Utiliser le charbon ou le gaz naturel pour produire de l’électricité signifie que la production de chaque unité d’énergie électrique (kilowattheures ou kWh) coûte de l’argent : il faut acheter le combustible. En revanche, une caractéristique commune de l’électricité à faibles émissions est que le coût marginal de production et de livraison est pratiquement nul.

  • Les sources solaire, éolienne et hydroélectrique au fil de l’eau peuvent produire de l’électricité tant que le soleil, le vent ou l’écoulement de l’eau est disponible. Réduire la production ne réduit pas les coûts sociétaux.
  • Pour l’hydroélectricité à réservoir («?grande hydro?»), c’est un peu plus compliqué. Il n’y a pas de frais d’exploitation pour ouvrir les vannes et générer plus, et pas d’économies à fermer. Cependant, la production épuise le réservoir en amont, de sorte qu’il peut y avoir un coût d’opportunité si cette énergie pouvait être vendue à des moments différents pour un prix plus élevé. Cependant, ces centrales hydroélectriques doivent aussi maintenir un débit minimal et la gestion de plusieurs centrales le long d’un réseau fluvial nécessite des compromis, de sorte qu’elles ne sont pas entièrement pilotables. Néanmoins, les coûts marginaux d’exploitation sont nuls.
  • Les centrales nucléaires sont souvent conçues pour fonctionner à une puissance constante, avec des montées et baisses de puissance mesurées en jours. Certaines centrales nucléaires plus nouvelles peuvent mieux varier leur production, mais le seul coût supplémentaire est celui de l’uranium, qui est très petit. Réduire la production d’une centrale nucléaire ne réduit pas vraiment les coûts.
  • Enfin, les coûts du réseau de transport et de distribution sont également fixes à court terme.

Ainsi, dans un système alimenté par des sources autres que fossiles, les coûts sont constants à court terme, du moins jusqu’à sa capacité de production ou de transport. Lorsque la demande s’approche de la capacité du système, les coûts marginaux augmentent soudainement. Pour équilibrer l’offre et la demande dans un système contraint, l’opérateur du système prendra des mesures coûteuses telles que :

  • Démarrer des générateurs fossiles, tels que les centrales au gaz naturel, qui sont coûteuses à exploiter.
  • Faire appel aux batteries en réseau, achetant cette énergie à certains taux précédemment convenus.
  • Importer de l’électricité supplémentaire d’autres régions.
  • Piloter des charges contrôlables, comme la climatisation et les chauffe-eau des clients résidentiels.
  • Payer les grands clients industriels, comme les alumineries, pour réduire leur charge.

Ainsi, en fin de compte, un kilowattheure supplémentaire est soit «?gratuit?» (n’ajoute pas aux coûts du système), soit très coûteux (près de la capacité du système).

Cette caractéristique de tout-ou-rien soulève quelques questions pour la conception des tarifs et du marché.

Les tarifs réglementés sont conçus pour recouvrer les coûts du système, mais dans un système à faibles émissions, ils n’augmentent que pendant les périodes de pointe critiques, généralement quelques heures par an. Les tarifs de prix de pointe critiques et de remise de pointe critique peuvent donc être un meilleur signal pour les clients que les tarifs fixes selon l’heure de consommation appliqués 365 jours par an. (Les tarifs de pointe critique et les tarifs horaires peuvent être utilisés en même temps, surtout lorsque de grands générateurs non distribuables sont présents sur le système, comme en Ontario.) D’autre part, les tarifs en temps réel, qui varient constamment avec les coûts du marché, pourraient signifier que les clients sont confrontés à des prix extrêmement élevés pendant les pointes, ce qui peut conduire à l’injustice.

Dans de nombreuses régions, l’électricité est achetée et vendue dans un marché ouvert de l’énergie (mesurée en kWh, une unité d’énergie) entre les producteurs et les détaillants. Le coût marginal des générateurs fossiles fixe le prix de clôture du marché, les producteurs non émetteurs soumissionnant à zéro, sachant que tout montant supérieur à zéro est mieux que rien. Que se passe-t-il lorsqu’un système n’a que (ou presque que) des sources non émettrices?? Le prix de clôture reste à zéro la plupart du temps. Oups, ce n’est pas bon pour les affaires. Dans ces cas, un marché de capacité (mesuré en kW, une unité de puissance) peut être formé. Dans un marché de capacité, les producteurs sont payés pour la capacité potentielle qu’ils peuvent fournir pendant les périodes de pointe, que leurs actifs soient appelés ou non. Par conséquent, un plus grand nombre d’administrations compteront sur les marchés de capacité dans un avenir à faibles émissions. Une autre approche consiste à se passer entièrement des marchés et à opter pour un accord d’achat d’électricité entre une agence d’achat (ou un service public) et des producteurs d’électricité. D’autres approches mixtes peuvent également être trouvées dans le monde entier. Nous sommes encore en train d’apprendre à concevoir au mieux les marchés de l’électricité avec un réseau sans émission, et ce sujet est en évolution.

En fin de compte, attendez-vous à payer différemment pour l’électricité et les producteurs seront indemnisés différemment. Parfois, les prix de l’électricité seront moins élevés, mais parfois plus élevés qu’ils ne le sont actuellement. Cette transformation économique est similaire à certains égards à ce qui s’est passé dans les télécommunications. Il y a trente ans, nous payions pour chaque appel interurbain et chaque appel cellulaire, à des taux mesurés en dollars par minute dans le cas des appels internationaux. De nos jours, nous payons des frais fixes pour une énorme bande passante ou de grands blocs de données, et nous ne réfléchissons pas à deux fois avant de faire une vidéoconférence FaceTime avec des proches à l’étranger. Payons-nous moins pour les télécommunications?? Eh bien, pas vraiment dans l’ensemble, et c’est beaucoup plus compliqué, mais nous en obtenons beaucoup plus pour notre argent. La même chose se produira avec l’électricité.

What Zero Marginal Cost Electricity Means

Leave a reply

Most of electricity generated in the world comes from burning coal or natural gas, with low emission nuclear, hydro, wind and solar making up the rest of the generation. (I’m writing this from Québec, where electricity comes mostly from hydro.) In other words, for most people in the world, using a kilowatt-hour of electricity is a bit like burning a bit of coal or natural gas. But that’s quickly changing: in 2025, the International Energy Agency shows that the share of low-emission sources is approaching fossil fuels in global electricity generation.

Using coal or natural gas to generate electricity means that producing each unit of electric energy (kilowatt-hours or kWh) costs money: one needs to buy the fossil stuff. In contrast, a common characteristic of low-emission electricity is that the marginal cost of generation and delivery is practically zero.

  • Solar, wind, and run-of-river hydro may produce electricity as long as the sun, the wind or the flow of water is available. Turning off generation doesn’t reduce societal costs.
  • For reservoir hydro (“big hydro”), it is a bit more complicated. There’s no out-of-pocket cost to open the valves and to generate more, and no savings to turn off. However, generating depletes the upstream reservoir, so there may be an opportunity cost if this energy could be sold at different times for a higher price. However, these hydro plants must maintain minimum flow and managing multiple plants along a river system requires trade-offs, so they aren’t fully dispatchable. Still, marginal operating costs are zero.
  • Nuclear plants are often designed to run at a constant power, with ramp-up and ramp-down measured in days. Some newer nuclear plants can better vary their generation, but the only additional cost is that of uranium, which is very small. Reducing output of a nuclear generator doesn’t really reduce costs.
  • Finally, the costs of the transmission and distribution grid are also fixed in the short run.

Thus, in a system powered by non-emitting sources, costs are constant in the short run, at least up to its generation or transmission capacity. When demand gets near the system capacity, marginal costs suddenly increase. To balance supply and demand in a constrained system, the system operator will take costly measures such as:

  • Dispatching fossil generators, such as natural gas plants, which are costly to run.
  • Dispatching grid batteries, buying this power at some previously agreed to rates.
  • Importing additional electricity from other jurisdictions.
  • Dispatching controllable loads, like HVAC and water heaters for residential customers.
  • Paying large industrial customers, like aluminum smelters, to reduce their load.

So, in the end, an additional kilowatt-hour is either “free” (does not add to system costs) or very expensive (near system capacity).

This all-or-nothing characteristic raises a few issues for tariff and market design.

Regulated tariffs are designed to recover the system costs, which only increase during critical peaks, typically a few hours per year. Critical Peak Pricing and Critical Peak Rebate tariffs may therefore be a better signal to customers than fixed Time-Of-Use (TOU) tariffs applied 365 days a year. (Both critical peak and TOU tariffs may be used at the same time, especially when large non-dispatchable generators are present on the system, like in Ontario.) On the other hand, Real Time Pricing tariffs, which vary constantly with market costs, could mean that customers face extremely high prices during peaks, and this can lead to unfairness.

In many jurisdictions, electricity is bought and sold in an open energy market (measured in kWh, a unit of energy) between producers and retailers. The marginal cost of fossil generators set the closing energy market price, with non-emitting producers bidding at zero, knowing that any closing amount above zero is better than nothing. What happens when a system has only (or mostly) non-emitting sources? The closing price remains at zero most of the time. Oops, that’s not good for business. In those cases, a capacity market (measured in kW, a unit of power) may be formed. In a capacity market, producers are paid for the potential capacity they can provide during peaks whether or not their assets are called upon. Hence, more jurisdictions will rely on capacity markets in a low-emission future. Another approach is to get away with markets entirely and go with power purchase agreement between a purchasing agency (or utility) and power producers. Other, mixed approaches may also be found around the world. We are still learning how to best design electricity markets with a non-emitting grid, and this topic is ongoing.

In the end, expect to pay differently for electricity and producers will be compensated differently. At times, electricity prices will be less, but sometime higher, than they are now. This economic transformation is similar in some ways to what happened in telecommunications. Thirty years ago, we paid for each long-distance calls and cell calls, at rates measured in dollars per minute in the case of international calls. Nowadays, we pay a flat fee for the huge bandwidth or large data blocks, and we don’t think twice before doing a FaceTime videoconference with loved ones overseas. Do we pay less for telecom? Well, not really overall, and it’s a lot more complicated, but we get much more out of our money. The same thing will happen with electricity.

La transition énergétique : un manège cahoteux en 2024 et au-delà

Leave a reply

Lorsque les analystes vous montrent des prévisions de la transition énergétique, telles que les pourcentages d’énergie renouvelable, les ventes de véhicules électriques ou le pic de production de pétrole, avez-vous remarqué comme les années à venir sont une courbe lisse tandis que les années passées sont un zigzag?? Pensez-vous vraiment que cela se produira??

Une transition industrielle n’est jamais sans heurts. C’est comme rouler sur des montagnes russes branlantes dans l’obscurité avec des chutes qui lèvent le cœur, des virages serrés, des boucles inattendues et des impasses soudaines.

Ce manège cahoteux nous attend en 2024 et au-delà alors que nous continuons la transition vers l’abandon des combustibles fossiles.

Pour comprendre où nous allons, je suis très attentif à l’évolution du marché pétrolier, car il constitue le fondement de notre système énergétique. À l’heure actuelle, la production mondiale de pétrole brut (et d’autres liquides) est d’environ 102 millions de barils par jour (mb/j), après avoir diminué à 91 mb/j pendant la pandémie. Les carburants routiers sont de loin la plus grande utilisation de pétrole raffiné. Les ventes mondiales de véhicules de tourisme et de camions à combustion ont déjà atteint un sommet, mais il y a encore plus de véhicules qui entrent dans le parc que de véhicules mis au rebut. Par conséquent, la demande mondiale de pétrole devrait augmenter encore d’environ 2 mb/j en 2024. Cependant, la Chine a annoncé que 2023 marque le pic de la demande d’essence en Chine, avec une part de nouveaux véhicules branchables en Chine approchant maintenant les 40%. On peut penser que le parc mondial de véhicules à combustion commencera bientôt à diminuer, ce qui explique le scénario «?politiques annoncées?» de l’Agence internationale de l’énergie (AIE) qui suppose un pic de la demande de pétrole avant 2030. Il devient clair qu’au fil du temps, les véhicules électriques étoufferont progressivement la demande de pétrole. Ensuite, le trajet deviendra vraiment cahoteux.

De nombreux producteurs (pays) pétroliers disent qu’ils continueront à produire tout au long de la transition et au-delà. Ils ne peuvent pas tous être corrects. Historiquement, les pays du cartel de l’OPEP (et de l’OPEP+, créée en réponse à la chute des prix du pétrole entraînée par la production de pétrole de schiste aux États-Unis) ont agi comme des producteurs d’équilibre, réduisant leur production pour maintenir les prix. Mais l’OPEP est maintenant confrontée à une crise. L’Angola est le dernier pays à quitter l’OPEP. Le cartel ne représente plus que 27 millions de barils par jour. De plus, certains producteurs non membres de l’OPEP augmentent leur production, comme le Canada, qui s’attend à produire 5,3 millions de barils par jour d’ici la fin de l’année 2024, contre 4,8 mb/j en 2023. Les États-Unis sont en voie d’atteindre un nouveau record de 13,1 millions de barils par jour en 2024 (ou peut-être jusqu’à 13,35), contre 12,9 millions de barils par jour en 2023.

Comment cela sera-t-il résolu?? Personne ne le sait avec certitude. L’Arabie saoudite est actuellement le producteur pétrolier dont les coûts sont les moindres. Ils peuvent choisir de limiter leur production pour maintenir des prix élevés pendant quelques années de plus, en supposant que les autres pays de l’OPEP et de l’OPEP+ emboîtent le pas. Ou ils peuvent choisir de baisser les prix dans l’espoir que les producteurs américains de pétrole de schiste cesseront de forer de nouveaux puits et réduiront la production. Ou les Saoudiens peuvent décider d’abandonner la Russie, la Russie devenant alors encore plus dépendante de la Chine, avec des implications géopolitiques inconnues. Ou de nouvelles guerres dans les Balkans ou à Taïwan perturberont les chaînes d’approvisionnement mondiales. Ou tout cela, et plus encore, au fil du temps.

En plus des cahots causés par les dangers pétroliers et gaziers, nous pouvons également nous attendre à d’autres cahots dans la chaîne d’approvisionnement de l’énergie propre. Les technologies propres évoluent rapidement, et certains des chouchous d’aujourd’hui échoueront, pour être remplacés par quelque chose de mieux que personne ne sait encore. Certaines nouvelles technologies devront passer par un long processus de maturation avant de réussir, comme nous l’avons vu avec les problèmes initiaux des grandes éoliennes maritimes. Certaines technologies propres prometteuses ne parviendront pas à passer du MW au GW, ce qui les limitera à des applications de niche. De nouveaux produits seront tout simplement mauvais, comme certains des premiers modèles de VE des constructeurs automobiles traditionnels. L’activisme «?pas dans ma cour?» peut retarder la mise en œuvre des projets d’énergie propre ou même conduire à leur annulation. Les chaînes d’approvisionnement des technologies propres sont déjà serrées, les délais d’approvisionnement des transformateurs électriques s’étendant, par exemple, sur des années. Le risque d’une perturbation de l’approvisionnement en minéraux, comme celui du cuivre, est bien réel. Les facteurs géopolitiques augmentent encore l’incertitude, avec une grande partie de la fabrication de batteries, de panneaux solaires et d’éoliennes maintenant concentrée en Chine, ainsi que le traitement des minéraux, y compris pour les terres rares.

J’espère que vous que vous avez encore le cœur bien accroché malgré ces bosses de montagnes russes, parce que la transition en apportera plus encore. Une transition réussie de l’abandon des combustibles fossiles signifiera des gagnants, mais il y aura aussi des perdants : les travailleurs du pétrole dans les pays développés pourraient perdre leur emploi, tandis que les pays en développement dépendants du pétrole pourraient faire face à des déficits budgétaires et à d’éventuels troubles civils, avec des conséquences humanitaires et géopolitiques inconnues. Certains pays en développement pourraient ne pas être en mesure d’obtenir de l’électricité fiable à partir de sources renouvelables en raison de problèmes de chaîne d’approvisionnement. Cependant, il y a une lueur d’espoir ici : la nature distribuée et locale de ces technologies offre l’espoir de réduire la pauvreté énergétique vécue par 1 milliard de personnes qui n’ont pas les moyens d’utiliser des combustibles fossiles.

Donc, nous ne savons pas quelles seront les prochaines bosses, mais à quoi pouvons-nous nous préparer??

Dans l’ensemble, la transition énergétique devrait nuire aux résultats des sociétés pétrolières et gazières, que ce soit en raison de la réduction des volumes ou de la baisse des prix. Ces sociétés paient également une prime de risque plus élevée en raison de la volatilité et de l’incertitude. Les activités pétrolières et gazières en amont, y compris l’exploration et l’extraction, sont devenues de plus en plus risquées et moins rentables. En revanche, les activités du secteur intermédiaire comme le transport, l’entreposage et la vente en gros devraient être moins touchées à court terme. De plus, certains pensent qu’il n’y aura pas de pic dans la production mondiale de pétrole avant 2030 : l’OPEP s’attend à ce que la demande de pétrole continue de croître jusqu’en 2050. Il n’y a pas de consensus ou de certitude concernant cette transition. Néanmoins, si vous travaillez dans le secteur pétrolier et gazier en amont, cherchez des occasions d’appliquer vos compétences en matière d’énergie propre — l’énergie géothermique et l’énergie éolienne maritime viennent à l’esprit. Si vous travaillez en aval, les opportunités peuvent inclure la production d’hydrogène vert (pour remplacer le gris) et les réseaux de recharge de VE (mais attendez-vous à ce que ce soit différent des stations-service).

Bien que les faibles prix du pétrole puissent retarder la transition vers l’énergie propre, ils réduiraient les investissements dans le pétrole et le gaz et libéreraient donc des capitaux pour les investissements dans les technologies propres. De plus, les perturbations de l’approvisionnement en pétrole et en gaz peuvent entraîner des hausses de prix. Ces événements ont également tendance à accroître les investissements dans les technologies propres, comme nous l’avons vu en Europe à la suite de l’invasion de l’Ukraine par la Russie. Pour les entreprises et les pays pétroliers et gaziers, c’est un cas de damné si vous le faites, damné si vous ne le faites pas, indépendamment de leurs actions. Les investissements mondiaux dans l’électrification propre, les carburants à faibles émissions et l’efficacité énergétique sont déjà plus élevés que ceux dans le charbon, le pétrole et le gaz naturel, avec des rendements plus constants pour les projets d’énergie propre. Peu de gens doutent que les investissements dans l’énergie propre continueront généralement d’accélérer (avec des bosses en cours de route, c’est certain). 

Alors que nous nous éloignons des combustibles fossiles, quatre grandes catégories de charges électriques stimulent la croissance du système électrique. Il s’agit du chauffage électrique (à usage résidentiel, commercial et institutionnel), de l’électrification des transports (y compris les véhicules électriques, mais aussi le rail et d’autres moyens de transport), de l’électrification des procédés industriels (y compris le chauffage et le séchage, mais aussi l’électrochimie et éventuellement de nouvelles applications telles que la réduction directe du fer) et de la production d’hydrogène (remplaçant l’hydrogène gris en tant que matière première chimique pour l’ammoniac et le méthanol, pas en tant que vecteur d’énergie). Des billions de dollars seront investis dans les systèmes et les appareils électriques des clients. 

Le réseau électrique doit croître de manière significative afin de répondre aux besoins de ces nouvelles charges électriques. Dépendant du niveau actuel d’électrification, les réseaux dans des régions comme le Québec devront croître de 1,5 ou 2 fois d’ici 2050, tandis que ceux du Nord-Est américain devront croître peut-être 4 fois, et même plus encore dans les pays en développement. Cela signifie des billions d’investissements supplémentaires dans la production, le transport et la distribution d’énergie propre dans les années à venir. Cependant, un taux de croissance aussi élevé avec principalement des sources éoliennes et solaires intermittentes exige que les services publics d’électricité conservateurs adoptent de nouvelles façons de penser et de travailler. Les services publics font face à de nombreux défis : attirer la participation aux programmes de gestion de la demande, de réponse à la demande et d’efficacité énergétique?; intégrer de nouvelles technologies de réseau, comme le stockage?; réduire les retards d’interconnexion pour les projets d’énergie renouvelable ; améliorer la fiabilité du service ; construire de nouvelles infrastructures de production et de transport?; gérer le resserrement du marché du travail?; assurer l’abordabilité, l’équité entre les clients et des investissements prudents?; gérer l’évolution des exigences réglementaires et du marché de l’électricité?; et plus encore. Les gouvernements et les organismes de réglementation devront élaborer des politiques et des concepts de marché bien pensés pour soutenir les services publics pendant la transition énergétique. Malheureusement, les politiques stupides sont encore beaucoup trop courantes, comme c’est le cas actuellement au Texas et en Alberta.

La vérité risque aussi de devenir une autre victime de la transition. Les rebondissements des montagnes russes de la transition offriront des opportunités à tout le monde — négationnistes et alarmistes, foreurs et écolos — de croire qu’ils sont sur la bonne voie, juste pour dérailler plus tard. Malheureusement, la transition énergétique est un sujet complexe et le «?gros bon sens?» est souvent erroné. Beaucoup de gens espèrent aussi gagner de l’argent rapidement en sautant dans le train de l’industrie de l’énergie. Ils apportent des idées et des inclinations importées d’autres domaines, mais qui peuvent ne pas être pertinentes ici. Il n’y a pas de solution magique à la transition énergétique.

En guise de dernier mot, ne vous laissez pas influencer par les dernières bosses sur les montagnes russes de la transition énergétique. Gardez l’esprit ouvert et restez calme, en vous appuyant sur des sources impartiales et bien informées. Transformer les systèmes énergétiques du monde en systèmes énergétiques durables prend du temps et des efforts, mais c’est ce qui se passe. Le monde à venir sera différent, mais meilleur à bien des égards.

Bonne chance à vous et aux vôtres pour l’année à venir?!

The Energy Transition: Bumpy Ride in 2024 and Beyond

Leave a reply

When analysts show you charts of the energy transition over time, such as percentages of renewable energy, EV sales, or peak oil production, have you notice how future years are a smooth curve while past years are a zigzag? Do you really think this will happen?

An industry transition is never smooth. It’s like riding a rickety roller coaster in the dark, with heart-stopping drops, sharp turns, unexpected loops, and sudden dead ends.

That bumpy ride awaits us in 2024 and beyond as we transition away from fossil fuels.

To understand where we’re going, I pay close attention to developments in the oil market, since it is the bedrock of the current energy system. Currently, worldwide crude oil (and other liquids) production is around 102 million barrels per day (mbpd), having decreased to 91 mbpd during the pandemic. Road fuels are by far the largest use of refined oil. Worldwide sales of combustion passenger vehicles and trucks have already peaked, but more vehicles are still entering the fleet than being scrapped. Therefore, global oil demand is expected to rise again by about 2 mbpd in 2024. However, China announced that 2023 marks peak gasoline demand in China, with plugin share of newly registered vehicles is now approaching 40%. We can expect that the world’s fleet of combustion vehicles will soon start shrinking, explaining the International Energy Agency’s (IEA) stated policy scenario of a peak in oil demand before 2030. Clearly, EVs will gradually choke off demand for oil over time. Then the ride will get really bumpy.

Many oil producers (countries) say that they will continue to produce throughout the transition and beyond. They can’t all be right. Historically, countries in the OPEC cartel (and OPEC+, created in response to falling oil prices driven by US shale oil output) have acted as balancing producers, reducing their output to maintain prices. But OPEC is now facing a crisis. Angola is the latest country to leave OPEC. The cartel now accounts for just 27 million barrels per day. Additionally, some non-OPEC producers are increasing their output, such as Canada, which expects to produce 5.3 million barrels per day by year-end 2024, from 4.8 mbpd in 2023. The United States is on track to reach a new record high of 13.1 million barrels per day in 2024 (or perhaps as much as 13.35), up from 12.9 million barrels per day in 2023.

How will this get resolved? Nobody knows for sure. Saudi Arabia is currently the lowest cost oil producer. They may choose to limit their output to maintain high prices for a few more years, assuming that the other OPEC and OPEC+ countries follow suit. Or they may choose to lower prices in the hope that US shale oil producers will stop drilling new wells and reduce output. Or the Saudis may decide to abandon Russia, with Russia then becoming even more dependent on China, with unknown geopolitical implications. Or new wars in the Balkans or Taiwan will disrupt global supply chains. Or all this, and more, may happen over time.

In addition to bumps caused by oil and gas hazards, we can also expect further bumps in the clean energy supply chain itself. Clean technology is evolving rapidly, and some of today’s darlings will fail, to be replaced by something better that nobody knows yet. Some new technologies will have to go through a long maturation process before they succeed, as we have seen with the initial problems in large offshore wind turbines. Some promising clean technologies will fail to scale from MW to GW, limiting them to niche applications. Some new products will just be bad, such as some early EV models from traditional automakers. Not-in-my-backyard (NIMBY) activism can delay the implementation of clean energy projects or even lead to their cancellation. The clean tech supply chains are already tight, with, for example, lead times on electrical transformers stretching into years. The risk of a mineral supply disruption, such as that of copper, is very real. Geopolitical factors further increase uncertainty, with much battery, solar panel and wind turbine manufacturing now concentrated in China, as well as mineral processing, including for rare earths.

I hope that you are not already getting sick from all these roller coaster bumps, because the transition will bring more of them. A successful transition away from fossil fuels will mean winners, but there will also be losers: oil workers in developed countries could lose their jobs, while developing countries dependent on oil could face budget shortfalls and possible civil unrest, with unknown humanitarian and geopolitical consequences. Some developing countries may not be able to obtain reliable electricity from renewable sources due to supply chain issues. However, there is a glimmer of hope here: the distributed and local nature of these technologies offers hope of alleviating the energy poverty experienced by 1 billion people who cannot afford the use of fossil fuels.

So, we do not know what the next bumps will be, but what can we prepare for?

Overall, the energy transition is expected to hurt the bottom line of oil and gas companies, whether due to reduced volumes or lower prices. These companies also pay a higher risk premium due to volatility and uncertainty. The upstream oil and gas business, including exploration and extraction, has become increasingly risky and less profitable. In contrast, midstream activities such as transportation, storage and wholesale should be less affected in the short term. Also, some believe that there will be no peak in global oil production before 2030: OPEC expects demand for oil to continue growing through 2050. There is no consensus or certainty regarding this transition. Still, if you work in upstream oil and gas, look for opportunities to apply your skills in clean energy — geothermal and offshore wind comes to mind. If you work downstream, opportunities may include green hydrogen production (to replace grey) and EV charging networks (but expect this to be different than gas stations).

While low oil prices may delay the clean energy transition, they would reduce investment in oil and gas and therefore free up capital for investments in clean technologies. Furthermore, disruptions in oil and gas supplies can lead to price rises. These events also tend to increase investment in clean technologies, as we have seen in Europe following Russia’s invasion of Ukraine. For fossil fuel companies and countries, it is a case of damned if you do, damned if you don’t, regardless of their actions. Global investments in clean electrification, low-emission fuels and energy efficiency are already higher than those in coal, oil and natural gas, with more consistent returns for clean energy projects. Few would doubt that clean energy investments will generally continue to accelerate (with bumps along the way, for sure). 

As we transition away from fossil fuels, four major categories of electrical loads are driving the growth of the power system. These are electric heating (for residential, commercial and institutional use), transportation electrification (including EVs, but also rail and other means of transport), electrification of industrial processes (including heating and drying, but also electrochemistry and possibly new applications such as direct iron reduction) and hydrogen production (replacing grey hydrogen as a chemical feedstock for ammonia and methanol, not as an energy carrier). Trillions of dollars will be invested in customer electrical systems and devices. 

The electricity grid must grow significantly to meet the needs of these new electrical loads. Depending on the current level of electrification, grids in regions such as Québec will have to grow by 1.5 or 2 times by 2050, while those in the US Northeast will have to grow perhaps 4 times, and even more in developing countries. This means trillions of additional investments in clean energy generation, transmission and distribution in the coming years. However, such a high rate of growth with mainly intermittent wind and solar sources requires that conservative electric utilities adopt new ways of thinking and working. Utilities face many challenges: attracting participation in demand management, demand response and energy efficiency programs; integrating new grid technologies, like storage; reducing interconnection delays for renewable projects; improving service reliability; building a new generation and transmission infrastructures; managing tight labour market; ensuring affordability, fairness among customers and prudent investments; managing evolving regulatory and power market requirements; and more. Governments and regulators will need to develop well-thought-out policies and market designs to support utilities during the energy transition. Unfortunately, dumb policies are still far too common, as is currently happening in Texas and Alberta.

Truth also risks becoming another victim of the transition. The twists and turns of the transition roller coaster will provide opportunities for everyone—deniers and alarmists, roughnecks and tree huggers—to believe that they are on the right track, only to derail later. Unfortunately, energy transition is a complex subject and “common sense” is often wrong. Many people also hope to make a quick buck by jumping on the energy industry bandwagon. They bring ideas and inclinations imported from other fields, but which may not be relevant here. There is no magic solution to the energy transition.

As a final word, don’t let yourself be swayed by the latest bumps on the energy transition roller coaster. Keep an open mind and stay calm, relying on unbiased and well-informed sources. Transforming the world’s energy systems into sustainable ones takes time and efforts, but it is happening. The world to come will be different, but better in many ways.

All the best to you and yours for the coming year!

The Maslow Pyramid of EV Charging

Leave a reply

Remember the Maslow pyramid? It is often used to illustrate human needs, with the largest, most fundamental needs at the bottom, and the self-fulfillment needs at the top. This idea also applies to light-duty EV charging infrastructure.

The EV charging pyramid represents what I expect the market shares of the basic charging use cases to be once the EV charging infrastructure is more widely deployed, in a decade or so. The market share is expressed as the overall percentage of the delivered energy for each case. Obviously, these market shares are only indicative and will vary between regions, depending on various factors such as the rate of home ownership and urbanization. Also, individual EV drivers will have different charging patterns, with some drivers using some use cases much more than others.

These four segments are the fundamental use cases for light-duty EV charging. Each has its own characteristics (see table below). Overall, home charging is the largest segment because it is the most convenient and the least expensive mean to charge an EV. On-the-go fast charging (like going to a gas station) is the least convenient and the most expensive. Charging at various destinations is in between these extremes. 

All EV drivers may use all of these options, and each one is good in its own way. However, some drivers will use some of them more than others. For example, a salesperson often driving to see clients in distant cities may use a lot of on-the-go charging, whereas a retired couple may only use home charging, except for occasional trips to see family in other cities. A city dweller parking on the street may primarily use destination charging at work or while shopping, but use home charging at their cottage. The pyramid only illustrates the overall market share; it does not represent individual patterns.

The key then is to match the speed of charging to the expected duration of stay. For on-the-go charging, a driver is stopping to charge the vehicle. Charging needs to be as fast as possible. For destination and home charging, charging occurs while the EV is parked and the driver doing something, like shopping, visiting or sleeping — it’s charging while parked. Charging time needs to match park duration. Some destinations have longer park duration than others, as one may spend a day at a national park (good for Level 2 charging) but less than an hour at a shopping mall (good for a moderate fast charger). The basic rule is that the charging speed needs to match the expected dwell time at a site. Too fast or too slow charging both result in suboptimal customer experience.

Stopping to Charge vs. Charging While Parked

The other characteristics stem from this observation. 

Convenience. On-the-go charging at a service station is the least convenient: drivers only go there for the chore of charging and, perhaps also for a restroom break and to get coffee. Other cases are more convenient, as charging occurs naturally while the drivers do what they need to do — no time wasted waiting. 

Criticality. On-the-go charging is the most critical situation, since drivers usually stop with a nearly depleted battery. If there is a line-up or if a charger is broken, they are stuck unless there are other fast chargers in the vicinity. In contrast, destination charging does not require waiting for a fully depleted battery. Drivers will instead charge their vehicles whenever they have the opportunity. And there are far more Level 2 chargers than fast chargers — there’s always another one nearby.

Costs. On-the-go charging is also the most expensive to use, as these fast chargers have the most expensive hardware and the highest power costs. Destination chargers are less expensive than on-the-go chargers, cost less in electricity and may be subsidized to attract shoppers. Home charging is the least expensive, sometime as little as a dollar for a full charge, especially when charging at off-peak electricity rates. Level 1 (120 volts) chargers may be used at home, avoiding the purchase of a more expensive Level 2 charger. 

Public site owners and charging operators need to understand the pyramid to optimize customer experience and the economics of charging sites. Too many sites have been built with a poor match between charging speed and stay duration: 

  • Moderate (50 kW) fast chargers along highways (too slow) backed up by a Level 2 charger (way too slow).
  • Moderate fast chargers at a hotel (too fast, as drivers need to come back to move the vehicle after charging). 
  • Very fast chargers at a shopping mall (too fast, as the drivers needs to wait for charging to complete before shopping).
  • Level 2 charger at a fast food restaurant (too slow, as a few minutes of charging doesn’t provide a meaningful charge).

Hopefully, as more charging site owners and operators become EV drivers themselves, we will see emerging a public charging infrastructure that is convenient and resilient, supporting the transition away from fossil-fuel vehicle.

Analyse historique du plan d’action « Vers un Québec décarboné et prospère » d’Hydro-Québec

Leave a reply

J’ai lu avec attention ce plan d’action et, surtout, écouté la commission parlementaire du 30 novembre dernier lors de laquelle des membres de la haute direction d’Hydro-Québec ont témoigné. Je présente ici mon analyse personnelle de tout ceci, dans une perspective historique partant des années 60.

Michael Sabia présente ce plan comme un «?projet de société?» et il a répété cette expression plusieurs fois, au point d’en faire le thème central de la commission parlementaire. La vision est ainsi beaucoup plus sociale et économique que le commercialisme de l’ancien président Éric Martel et que la perspective surtout organisationnelle de l’ancienne présidente Sophie Brochu. 

Le plan d’action semble cohérent avec un projet de société. Les autres dirigeants de l’entreprise ont ainsi fait de nombreuses références à l’ouverture de l’entreprise pour travailler avec les peuples autochtones, les communautés, les clients, l’écosystème de l’électricité, les promoteurs, etc. On a même mentionné l’ouverture sur le monde en voulant s’inspirer de ce qui se fait de mieux ailleurs. Le plan d’action est d’ailleurs présenté comme étant une première ébauche, sujette justement à des ajustements à la suite de discussions à venir. Je reçois ceci comme un vent de fraîcheur, Hydro-Québec s’étant repliée sur elle-même au cours des dernières années. Le cadre de ces discussions n’est cependant pas précisé.

Le plan d’action «?Vers un Québec décarboné et prospère?» rappelle la période qui a suivi la Révolution tranquille, dans les années 60 et 70. Les gouvernements successifs, unionistes, libéraux ou péquistes, ont alors enclenché le développement des grands ouvrages de Manic-Outardes, qui ont doublé la capacité de production du Québec, de Churchill Falls (au Labrador) et de la Baie-James, qui l’ont encore doublé. Aujourd’hui, on parle à nouveau de doubler à l’horizon 2050. Mais augmenter la capacité de production ne fut pas le seul objectif des gouvernements. 

Dans les années 60 et 70, les gouvernements ont aussi utilisé la construction des grands ouvrages pour permettre aux Québécois francophones de prendre en main le développement économique de la province. Ce développement économique fut à la fois dans le secteur secondaire (fabrication d’équipement électrique et alumineries) et dans le secteur tertiaire (grandes firmes de génie-conseil et, un peu plus tard, en technologies de l’information). On entend encore les échos de cette décision d’avenir, car le Québec est aujourd’hui le pôle canadien de fabrication de matériel électrique : nous avons proportionnellement 2 fois plus d’emplois en fabrication de matériel électrique que le reste du Canada, tout au long de la chaîne de valeur, et des PME aux multinationales. Cette période voit aussi l’émergence de firmes québécoises de génie-conseil de calibre international, dont certaines sont parvenues au top-10 mondial, comme SNC-Lavalin. 

On peut s’inspirer de ce parallèle historique, tout en constatant que la situation actuelle présente ses caractéristiques propres. 

On parle encore d’hydroélectricité appuyée par le savoir-faire d’Hydro-Québec, bien évidemment, mais beaucoup d’éolien et de solaire, filières moins coûteuses, plus décentralisées, plus rapides à implanter, et utilisables directement par les clients. Au fil des grands projets hydroélectriques, dès les années 50, Hydro-Québec est devenue experte dans la gestion de ces projets, largement livrés à temps et dans les budgets. C’est exceptionnel dans le domaine — on n’a qu’à penser aux dépassements des projets Site C en Colombie-Britannique et Muskrat Falls au Labrador. Or, Hydro-Québec n’a pas le même savoir-faire pour l’éolien et le solaire que pour l’hydroélectricité, alors que plusieurs développeurs ont déjà acquis une expérience considérable en éolien et en solaire en Europe, aux États-Unis ou en Asie. Certains de ces développeurs sont même basés ici, comme Boralex et Brookfield. Dans le plan d’action, Hydro-Québec semble ouverte à continuer à travailler avec des développeurs, et je crois que c’est bien ainsi, pour éviter à notre tour des erreurs coûteuses. 

On parle aussi de plus de lignes et de postes de transport vers nos voisins, et pas seulement pour l’exportation, mais aussi pour utiliser nos ouvrages afin d’équilibrer la production renouvelable intermittente ici et ailleurs — une très grande valeur économique. Pour ce qui est des lignes de distribution dans les villes et les campagnes, elles ont été mises à niveau lors des vagues d’électrification des années 60 à 80, mais plusieurs équipements arrivent en fin de vie. C’est en partie ce qui explique la dégradation de la fiabilité du service depuis une dizaine d’années. Or, la fiabilité sera d’autant plus nécessaire que la société sera plus dépendante de l’électricité. Le plan fait mention de réduire les pannes de 35 % d’ici 7 à 10 ans, ce qui semble peu ambitieux puisque les pannes ont doublé depuis 10 ans. Tout de même, plusieurs technologies et façons de faire sont considérées pour redresser la situation, avec des infrastructures physiques plus résistantes ou résilientes (conducteurs recouverts, entrecroises flexibles, poteaux en composite), des systèmes de protection (plus de réenclencheurs, réenclenchement monophasé, réseau plus maillé, automatismes, etc.), ou encore avec une meilleure maîtrise de la végétation.  

Depuis les années 70, Hydro-Québec a périodiquement mis l’accent sur l’efficacité énergétique, surtout dans les années immédiatement avant la mise en marche d’une nouvelle centrale, abandonnant cependant ces programmes dans les années suivantes, lors de surplus. Ces programmes furent surtout administrés par des firmes privées mieux capables de rejoindre efficacement les nombreux clients, comme la firme de génie-conseil Dessau pour le programme Énergain au début des années 80. Aujourd’hui, la participation active des clients, passifs consommateurs en 1960, est nécessaire pour atténuer les pointes de demandes et consommer efficacement l’électricité. On parlera donc aussi de programmes de gestion de la demande, en plus d’efficacité énergétique. Les programmes comme la «?GDP affaires?» (gestion de pointe pour les clients commerciaux, institutionnels ou industriels) avec des agrégateurs privés et l’entente récente avec Sinopé pour automatiser la tarification dynamique sont probablement appelés à se multiplier. Certains clients seront aussi autoproducteurs, avec des systèmes solaires (et éoliens pour certains industriels) installés par des tiers. La collaboration avec les clients et l’écosystème de l’électricité sera nécessaire, même si elle prendra différentes formes qu’il y a 40 ou 50 ans.

En industrialisation, on ne parle plus d’alumineries mais de secteurs nécessaires à la transition, comme la fabrication de batteries. En 1970, on promettait des emplois pour se faire élire, mais nos entrepreneurs et industriels sont maintenant en pénurie de main-d’œuvre et doivent automatiser leurs usines. 

Dans les discussions à venir sur ce projet de société, il y aurait lieu, je crois, d’avoir aussi des discussions sur des points qui pourraient faire polémiques. Mieux vaut aborder ces points maintenant si on veut arriver à un consensus durable envers ce projet de société. 

Par exemple, l’écosystème de l’électricité ne réalise pas son plein potentiel d’innovation. Il n’en a pas toujours été ainsi, car la Révolution tranquille a vu l’innovation québécoise se démarquer. Ainsi, les lignes de transport d’électricité à 735?000 volts, inventées ici et inaugurées en 1965, sont demeurées les lignes à la plus haute tension dans le monde jusqu’en 1982, seulement alors surclassées par une installation d’Union soviétique. Depuis, Hydro-Québec a fait plusieurs tentatives de commercialisation d’innovations du centre de recherche d’Hydro-Québec, avec des filiales comme Nouveler, Capitech et Industech. Les résultats n’ont pas été à la hauteur des attentes. Ailleurs au Québec, même si l’innovation est au cœur des préoccupations des entrepreneurs et des industriels engagés dans la transition énergétique, on se doit de constater que l’écosystème ne réalise plus son plein potentiel, avec des barrières importantes, en particulier à ce qui a trait à la commercialisation. L’ouverture énoncée dans le plan pourrait donc devenir un accélérateur d’innovation par les entrepreneurs et industriels d’ici. Pour appuyer l’écosystème, on devrait peut-être repenser le rôle du centre de recherche d’Hydro-Québec pour en faire un moteur d’innovation, en s’inspirant de modèles existants ailleurs. Par exemple, en Colombie-Britannique, Powertech Labs est une filiale de BC Hydro très active dans la certification de produits électriques et plusieurs de nos entrepreneurs y font tester leurs nouveaux designs. En Ontario, Kinectrics, issue de la privatisation d’Hydro Ontario Research Division il y a une vingtaine d’années, est maintenant présente dans 7 pays et œuvre aussi dans le domaine des tests d’appareillages électriques. Un troisième modèle pourrait être le Lawrence Berkeley National Laboratory aux États-Unis, avec une mission de recherche appliquée peut-être plus conforme au nom officiel du centre de recherche, l’Institut de recherche en électricité du Québec (IREQ). Ces exemples et d’autres devront être discutés avec toutes les parties prenantes, y compris les entrepreneurs et industriels du secteur ainsi que le personnel de l’IREQ.

Tant qu’à avoir des discussions difficiles, il faudra aussi étudier les réformes de l’industrie qui ont eu lieu en Europe au cours des dernières décennies. Ce fut en particulier le cas en Norvège et en Suède, qui, comme le Québec, sont des régions largement alimentées à l’hydroélectricité dans un climat nordique. En général, les points forts de ses réformes ont été le dégroupage du secteur et l’introduction d’un marché de l’électricité. On a donc divisé les opérations du système électrique en transport et distribution d’électricité, qui sont des monopoles naturels, et la production et la vente d’électricité, qui ont été soumises à la concurrence. En outre, un marché de gros de l’électricité avec des prix fluctuants a été introduit en plus d’un marché de détail où les consommateurs pouvaient choisir leur fournisseur d’électricité. 

D’emblée, je dois dire que je ne vois aucun appétit de privatisation d’Hydro-Québec (à l’image d’Hydro One en Ontario) ni pour revoir le mandat d’exploitation des forces hydrauliques comme stipulé dans la Loi sur Hydro-Québec. De plus, les lignes de transport et de distribution utilisées pour fournir le service au public sont un monopole naturel local qui n’est pas remis en question, mais Hydro-Québec n’est pas le seul exploitant au Québec, puisqu’il y a 10 autres distributeurs d’électricité (9 municipalités et une coop) et quelques lignes de transport privées entre des installations industrielles. Cependant, on pourrait comparer les avantages et les inconvénients de réformer le secteur à l’image des Européens. Ceci amènerait aussi la discussion vers le besoin d’avoir un exploitant indépendant («?Independent System Operator?») comme ailleurs en Amérique du Nord. Ce seraient certainement des discussions animées, opposant des vues très différentes, mais nécessaires pour avoir les conditions gagnantes pour effectuer une transition énergétique porteuse de prospérité. Un défi constant lors de ces discussions sera d’aller au-delà des phrases clichés et de partager une compréhension commune des enjeux et des possibilités — l’industrie de l’électricité est complexe et le «?gros bon sens?» nous amène rarement aux bonnes conclusions.

En conclusion, je crois qu’il y a assez peu à critiquer sur ce plan d’action initial proposé par Hydro-Québec, aligné avec les volontés gouvernementales et somme toute bien réfléchi. Les quelques critiques que j’ai entendues sont surtout en amont ou en aval. En amont, Hydro-Québec est un instrument du gouvernement du Québec, et on ne peut lui reprocher d’agir en conséquence. Par exemple, certains critiquent l’allocation de 25 % de l’électricité supplémentaire pour la croissance économique, préférant mettre l’accent sur la réduction de la consommation. Cependant, c’est une décision gouvernementale à laquelle Hydro-Québec ne fait que répondre, et on ne peut lui reprocher ceci. En aval, d’autres soulignent les risques à exécuter ce plan, comme pour ce qui est de la pénurie de main-d’œuvre, de l’incertitude sur les besoins futurs ou des imprévus associés au développement des centrales de production. Tout vrai, mais j’ai déjà fait plusieurs plans stratégiques dans des contextes de transition, et les meilleurs sont à la fois ambitieux et itératifs?; les détails deviendront plus clairs au fur et à mesure. 

En fait, c’est là la clé : il faut discuter de ce projet de société entre nous, s’inspirant de ce qui se fait ailleurs, dans des forums qui laissent place à toutes les perspectives.

BP’s Energy Outlook Describes a Low-Carbon Future

Leave a reply

As always, this year’s BP Energy Outlook is a well-written perspective on how our energy system might evolve. Written by an oil major, it can’t be accused of being overly pushing an environmental agenda: it can be seen as best-case scenarios (from a fossil point of view) or worst-case ones (from an environmental point of view). Yet, the future of global energy that it shows is dominated by four trends: declining role for hydrocarbons, rapid expansion in renewables, increasing electrification, and growing use of low-carbon hydrogen.

First, the Outlook sees oil demand declining, driven by falling use in road transport as the efficiency of the vehicle fleet improves and the electrification of road vehicles accelerates. In all scenarios, peak oil demand happens before 2030. The prospects for natural gas depend on the speed of the energy transition. I found the Outlook geopolitical forecast particularly interesting. The Outlook states that OPEC lowers its output over next decade in response to the growth in US and other non-OPEC supplies, accepting a lower market share to mitigate the downward pressure on prices. As the decline in oil demand gathers pace and the competitiveness of US output wanes, OPEC competes more actively, raising its market share. OPEC’s share of global oil production increases to between 45-65% by 2050 in all scenarios.

Renewables (largely wind and solar power) expand rapidly over the outlook, offsetting the declining role of fossil fuels. The share of renewables in global primary energy increases from around 10% in 2019 to between 35-65% by 2050, driven by the improved cost competitiveness of renewables, together with the increasing prevalence of policies encouraging a shift to low-carbon energy.

The growing importance of renewable energy is underpinned by the continuing electrification of the energy system. The share of electricity in total final energy consumption increases from around a fifth in 2019 to between a third and a half by 2050. 

According to the Outlook, the decarbonization of the energy system is supported by the growing use of low-carbon hydrogen in hard-to-abate processes which are difficult or costly to electrify. The share of primary energy used in the production of low-carbon hydrogen increases to between 5-21% by 2050. Tellingly, the more fossil-friendly scenario has the least hydrogen, while the scenarios with faster transition have the most hydrogen. I’m not sure if this reflects BP’s belief that hydrogen helps drive the transition or BP’s hopes that it can be a meaningful player in hydrogen once its fossil business dries up. Either way, making hydrogen will require a lot of electricity, as BP expects that around 60% of low-carbon supply will be from electrolysis (“green”) in 2030, and growing further in later years.

In transportation, the Outlook predicts a switch away from the reliance on diesel in medium- and heavy-duty trucks and buses, with the share of diesel-based trucks declining from around 90% in 2021 to 5-20% in 2050. The main switch is to electrification, but hydrogen-fueled trucks also play a role (15%), especially for heavy-duty, long-distance use cases. BP’s states that the choice between electrification and hydrogen varies across different countries and regions depending on policies affecting the relative price of electricity and low-carbon hydrogen, as well as on regulatory policies and the development of charging and refueling infrastructures.

BP’s Outlook may be found at https://www.bp.com/en/global/corporate/energy-economics/energy-outlook.html.

Preconceptions on EVs Lead to Wrong Infrastructure Decisions

Leave a reply

Drivers of internal combustion vehicles far outnumber drivers of electrical vehicles (EV). Meaning: they are often the ones deciding on EV matters.

Based on a few formal surveys and many ad hoc conversations with drivers and deciders, I unfortunately see that preconceptions on EVs too often drive decision-making on EV matters. I compiled the differences in thinking for combustion and electrical vehicle drivers in the table below. Warning: reality might shock combustion drivers.

What Combustion Drivers Think What EV Drivers Know
Full charge: “You need to charge to 100% before driving.”Charge enough: “I just need to have enough battery to get to where I need to go.”
Long charge time: “It takes much longer to charge your EV than to fuel an ordinary car.”Quick charge (1): “It takes seconds to plug my EV and then I usually go do whatever I need to do.”
Quick charge (2): “If I’m on a road trip, I try to charge at my destination (hotel, cottage…) so I don’t have to wait.”
Quick charge (3): “If I can’t charge home, I get my car to charge overnight at a curbside station, at my workplace, or while shopping.”
Don’t stand there! “Don’t you hate standing beside your car, sweeting, freezing or being rained on, while holding a filthy gas nozzle?”
Slower, but who cares? “Yah, it takes a bit longer to charge at a fast-charging station, but I only charge there as a last resort and very rarely, so it doesn’t matter much since I saved so much time rarely going to gas stations.”
Range anxiety: “Will you have enough charge in the battery to get where you want to go?”Mostly charge at home: “I mostly charge at home and most of my driving is within the 400 km (250 mi.) range of my vehicle.”
Charging anxiety: “Will I be able to charge when I get to the charging station? Will there be a problem such as a broken charger, blocked access, a long waiting line or a combustion vehicle in the stall? How long will it take to charge with this fast charger?”
No charging station: “I don’t see charging stations around where I live.”Easy to find: “Charging sites are easy to find using apps like ChargeHub or PlugShare.”
Good geographic coverage: “Fast charging geographic coverage outside cities is quite good, but there may not be enough charging stalls at peak times.”
Slow is best: “I rather charge at one of the many slow (level 2) destination chargers, often for free, instead of waiting at a fast charger.”
Poor layout: “Why are fast chargers in the remotest corner of the parking lot, or in the middle of nowhere, without a canopy, and requiring backing up? 
No amenities: Is there a restroom and a place to get coffee at this charging station?”
It’s complicated: “Why so many different price scheme? How do I pay? Why do I need to have so many apps on my phone? Don’t you want my business?”
Unreliable public chargers: “Public chargers, especially fast ones, are often broken.”

Messaging and actions to accelerate EV adoption by combustion drivers need to dispel these preconceptions. However, these are different than the messaging and the actions necessary to meet the needs of EV drivers. For example, increasing visibility of charging stations will help combustion drivers realize that there are, indeed, many charging stations around, but it won’t help EV drivers who know how to find them anyway. However, having drive-through layouts and canopies would be greatly appreciated by EV drivers. 

The dichotomy between combustion and EV drivers makes it difficult for government to promote EV adoption while ensuring that the right infrastructure is deployed. This contradiction also led to many charging operators and site owners to install chargers which ended up being lightly used, either because they are not well matched to the site, not well situated, poorly laid out or simply unattended and broken.

Better understanding what combustion drivers and EV drivers think will help us make informed investment decisions. 

Why Are We Trying to Replicate the Gas Station Experience for EVs?

Leave a reply

Your grandma’s rotary phone had advantages over a cell phone: it didn’t need to be recharged and the voice quality was superior. Yet, rotary phones can now only be found in museums. And it didn’t stop at cell phones: Apple came along and showed us how a smartphone has potential to be so much more. Our smartphones are now considered essential for running our day-to-day lives beyond communication — we shop, we look for directions, we take pictures; it’s now more of a personal assistant then a phone. But we need to charge them.

The same transformation is happening with EVs. EVs can do more than a combustion vehicle, being batteries on wheels designed around a core computing architecture. We’re only beginning to scratch the surface of how EVs can change our lives, with greater resiliency at home and helping integrate renewable energy sources without contributing as much to climate change.

Yet, non-EV drivers seem to assume that adoption of EVs will be limited until they can be recharged in a time comparable to fueling a combustion vehicle at a gas station. It’s like saying that cell phones and smartphones can’t reach mass adoption until they don’t need to be charged. 

Combustion vehicle drivers might be shocked (warning!) to learn that EV driver behavior is closer to charging a smartphone than fueling a car. EV drivers tend to charge overnight at home or opportunistically during the day, but not necessarily expecting a full charge every time. They prefer to charge at their destination using less expensive, more convenient and more reliable (but slower) level 2 chargers or slow DCFC rather than faster chargers at a “gas station” where they would have to wait and pay more for charging. Do you often “fast charge” your smartphone? I don’t.

“Gas station” charging is the most expensive way to charge in an ecosystem that is very price sensitive (like gasoline). It’s also the most time-consuming way to charge while we all need more time to do our things. Nevertheless, “gas station” charging is crucial in some situations, like along corridors during a road trip. But it’s also a last resort, used as infrequently as possible. Like a payphone in remote locations without cell coverage. But this doesn’t stop us from loving our smartphones.

Fast chargers: over-rated?

Leave a reply

Many assume that adoption of light-duty electrical vehicles (EV) will be limited until EVs recharge as fast as combustion vehicles refuel at a gas station. That’s not quite true. The truth will not surprise many EV drivers, but (warning!) some combustion vehicle drivers might be shocked.

For EV drivers to experience a gas station-like experience, charging needs to be complete within minutes, i.e. fast charging, the faster the better, it seems. The need largely arises from the possibility of cross-country road trips, leading to an accent on fast charging along highway corridors. Who doesn’t dream of cruising top-down in a roadster on highway 66 or the Trans-Canada highway?

What’s the real need? The share of energy provided by public fast charging is around 10% to 15%, depending on where you are, and most of this is in cities, not along highway corridors. This breakdown is not surprising, as most EV drivers charge at home, which is also the least expensive place to charge. After home, workplace is the second least expensive place to charge, with some employers providing free charging. For public charging, level 2 chargers are much more economical than fast chargers to install and operate, cost less than half as expensive for drivers to use, are easier to handle (having lighter cables) and may often be more convenient (no need to wait, just park, plug and come back some hours later or the next morning). Given this, plus the fact that the range of modern EVs is more than most people usually need in a day, level 2 chargers at destinations (as well as “slow” fast chargers, like 25 kW or 50 kW) are likely to retain a higher share of charging energy than public super fast charging. Note that 25 kW or 50 kW chargers at commercial destinations like grocery stores are very convenient: you may get a week worth of veggies, milk, meat and driving in one visit, all without waiting.

Corridor fast charging is a last resort, used if other alternatives (home, workplace, and destination charging) are not suitable. This means that fast corridor chargers have relatively low time utilization, but the pattern is peaky, resulting in congestion at certain times, such as Friday afternoon as people leave town for the weekend. The low market share of fast chargers will clearly be a challenge for operators of gas stations, as 100% of fuel is now sold at gas stations. And, with high peaks, congestion will occur even with low average utilization. Operators of fast corridor chargers will have no choice but to increase prices further for captive drivers who have no other alternatives.

However, a good fast charging infrastructure along highway corridors is nevertheless essential, as EV drivers sometimes need it, when they go on road trips. Furthermore, the fast charging infrastructure is also a major showcase for people considering buying an EV. Without it, as infrequently it might be used, few combustion drivers would consider an EV.

Hydrogen Point of View

Leave a reply

Over the last couple of years, I have been approached to describe the hydrogen fueling infrastructure or for opportunities related to hydrogen production or distribution. So, here is my point of view for all to know.

  • Production of low-carbon (“green”) hydrogen will be essential to replace the ?60 millions of tons of fossil (“gray”) hydrogen used as feedstock for various chemical processes, such as making fertilizer. This is a large decarbonization challenge, and it will be decades before the production of low-carbon hydrogen can catch up. Note that another ?60 millions of tons of fossil hydrogen are used to upgrade crude oil and remove sulfur during refining, but this use of hydrogen will diminish as we transition away from fossil fuel. 
  • Molecular hydrogen could be used as an energy carrier, but it is a lousy one, regardless of its color. In fact, the ?120 millions of tons of fossil hydrogen produced now are not used as an energy carrier, except for some small niches, like lunar rockets. Made from low-carbon electricity using electrolyzers, hydrogen is a highly inefficient energy carrier, with only 1/4 to 1/3 of the energy used in the process recovered when the hydrogen is fed to a fuel cell or simply burned for heat. Hydrogen as an energy carrier is also inefficient, as it is difficult to transport and store it, exemplified by the difficulty Nasa had when launching its latest lunar mission. 

As an energy carrier, poor efficiency and effectiveness of hydrogen results in poor economics versus direct electrification of transportation and heat, for most applications. The niche applications where hydrogen could be used will also suffer from low volume in comparison to direct electrification solutions, resulting in worsening economics. Unless you are Nasa, you should probably stay away from hydrogen as an energy carrier. 

Note that hydrogen is not an energy source, but it could be a carrier. While hydrogen is a very common element, it is not an energy source, as it cannot be mined or found in a form that is usable to generate energy. It is an energy carrier when electricity is used to produce molecular hydrogen, which can be converted back to electricity or heat, albeit not efficiently. 

A final note on my personal history: I built an electrolyzer when I was 13 years old. I lit up the resulting hydrogen to make a bang — a rather big bang, it turned out. My mother was not impressed and told me, “never again”. I have a lot of respect for my mother, and perhaps you should too. 

AIEQ Panel on Electricity Supply Chain

Leave a reply

On November 8, 2022, I chaired a discussion panel on supply chains at the Québec Electricity Industry Association (AIEQ) conference. 

The supply chain of the electricity industry is undergoing a profound transformation, fueled by the electrification of the economy (presented by Mathieu Lévesque, ing., MBA, from Dunsky Energy + Climate Advisors). While growth may be good news, it is also straining the supply chain, including raw materials (like metals and graphite), goods and services. 

For entrepreneurs in Québec, the US market is of great importance. Jean-François Hould (Québec Government Office in Washington) presented the recent legislative and policy changes in the US, including “America’s Strategy to Secure the Supply Chain for a Robust Clean Energy Transition”. Clearly, our neighbors to the South also see the supply chain as the key to their competitiveness and economic growth. US firms can be both our customers and our suppliers, but also our competitors in a strained supply chain. 

Mihaela Stefanov, MBA presented the perspective of Boralex Inc., hinged on the issues of price inflation, geographic concentration of manufacturing and ESG (Environmental, Social, and Governance). 

Similarly, Martina Lyons (International Renewable Energy Agency (IRENA)) showed that high price volatility, security of supply (including “friendshoring”) and ESG are the key issues with the supply of raw materials. 

Overall, these issues — price inflation and volatility, security of supply and ESG — are the defining characteristics of the emerging supply chains. For Québec companies selling abroad, these can be a source of competitive advantage, with its clean electricity grid, trustworthiness, and strong ESG record. On the other hand, sourcing raw materials and goods in a strained supply chain expose the same companies to these defining characteristics. Balancing these opposite forces will require careful leadership and collaboration among all stakeholders in Québec’s electricity ecosystem. 

Finally, I would like to thanks all the panelists for this engaging discussion. 

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

Leave a reply

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

Leave a reply

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

Leave a reply

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

Leave a reply

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

Leave a reply

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

Leave a reply

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

Leave a reply

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

Leave a reply

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