Category Archives: Policies and Regulatory

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

shape, polygon

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

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

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

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

How Québec’s Electricity Value Chain Compares to the World

polygon

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

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

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

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

Community Choice Aggregation : une alternative pour l’avenir de l’électricité au Québec??

Avec Hydro-Québec, le Québec est doté de ressources naturelles incomparables, dont un potentiel hydroélectrique et un réseau d’électricité uniques. Son système électrique est également hautement intégré, de la production aux clients. 

D’autres régions, confrontées à des choix énergétiques plus difficiles, ont adopté des structures industrielles différentes. Je veux ici explorer une tendance forte aux États-Unis et voir comment nous pourrions nous en inspirer : Community Choice Aggregation. 

Les agrégateurs communautaires (Community Choice Aggregators ou CCA) sont des organismes publics sans but lucratif qui ont une certaine exclusivité de vente au détail de l’électricité dans une région. Les CCA permettent aux administrations locales (villes et comtés) de se procurer de l’énergie au nom de leurs résidents, de leurs entreprises et de leurs municipalités tout en recevant des services de transport et de distribution de leur compagnie d’électricité locale. En agrégeant la demande, les collectivités obtiennent un effet de levier pour négocier de meilleurs tarifs avec des fournisseurs concurrentiels et choisir des sources d’énergie plus vertes. Étant locales, les CCA peuvent également être mieux placées pour offrir des services et des programmes d’efficacité énergétique adaptés à leurs collectivités. 

Il y a plus de 1200 CCA aux États-Unis desservant 10,6 millions de clients dans 8 états. En 2022, environ 100 térawattheures (TWh) d’électricité ont été achetés par les CCA. Les collectivités qui participent aux programmes de CCA négocient leur source de production d’énergie, utilisent le pouvoir d’achat en vrac pour réduire les coûts de l’énergie, stimulent le développement des ressources locales d’énergie renouvelable et des emplois locaux dans l’énergie propre, assurent la stabilité et la transparence des prix de l’énergie, tout en accélérant la transition vers l’énergie renouvelable avec chaque initiative. Les CCA travaillent en partenariat avec le service public existant de la région. Le CCA achète l’électricité, et le service public continue de la livrer, d’entretenir le réseau et de fournir une facturation consolidée.

Est-ce que cela pourrait être adapté au Québec?? Peut-être, pourquoi pas?? Je ne dis pas que c’est la solution, mais c’est peut-être un outil auquel il faut réfléchir.

Je suis cette tendance depuis quelques années maintenant, alors contactez-moi si vous voulez en discuter. 

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

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

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

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

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

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

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

Clear Definitions for Energizing Discussions

In the debate surrounding the upcoming Hydro-Québec bill, many opinions are circulating. Unfortunately, several concepts are mixed up, which confuses the discussion. Here are some definitions to enlighten readers.

  • Monopoly: The transmission and the distribution of electricity are natural monopolies. This means that there is “naturally” a single supplier that emerges in each location (or corridor for transmission). Imagine if several suppliers wanted to have poles along our streets! It doesn’t happen. However, there are already 11 electricity distributors with a monopoly in Québec: Hydro-Québec, 9 cities and a cooperative. Hydro-Québec is not the only distributor. For transmission, some companies have lines, such as Rio Tinto, and some lines have been built in partnership. Once again, Hydro-Québec is not alone.
  • Monopoly (bis): The production of electricity and the retail sale of electricity are not natural monopolies. In several regions, such as the European Union, several producers compete and sell electricity on an open market. Electricity retailers buy and sell this energy to consumers proposing various plans, much like we see in the telecommunications industry. Electricity is delivered from producers to consumers using the natural monopoly of transmission and distribution companies. This 4-stage structure (production-transmission-distribution-retail) is common, and Québec’s vertically integrated structure is more the exception than the rule.
  • Price regulation: Monopoly means price regulation. Transmission and distribution prices are always regulated to ensure a fair return on prudent investments; sometimes performance incentives (reliability, costs) are imposed, as in Great Britain or Alberta. Where production and retail are competitive, regulation can be light, mainly to ensure that prices and conditions of service are fair, and to ensure that competition works for the benefit of consumers. Also, it should be noted that prices must be regulated even for a state monopoly.
  • Nationalization (or privatization): The nationalization of electricity production and delivery in Québec, a legacy of the Quiet Revolution, is not seriously questioned: no one will want to sell Hydro-Québec, as Hydro One was in Ontario a few years ago. The nationalization of private electricity companies has made it possible to accelerate electrification (helping the trade balance), to develop the industrial sector of Québec’s economy (electrical equipment and aluminum), and to develop the service sector (consulting engineering and computer science). However, nationalization does not mean that the private sector has no role to play or that Hydro-Québec should be the sole producer. 

Beyond words, the important thing is to set the right goals and use the levers at our disposal to achieve them, understanding the advantages and disadvantages of each model. 

Des définitions claires pour une discussion énergisante

Dans le débat entourant le projet de loi à venir sur Hydro-Québec, beaucoup d’opinions circulent. Malheureusement, on y mélange plusieurs concepts, ce qui embrouille la discussion. Voici donc quelques définitions pour éclairer les lecteurs.

  • Monopole : Le transport et la distribution d’électricité sont des monopoles naturels. Ça veut dire qu’il y a «?naturellement?» un seul fournisseur qui émerge dans chaque endroit (ou corridor pour le transport). Imaginez si plusieurs fournisseurs voulaient avoir des poteaux le long de nos rues?! Ça ne se fait pas. Cependant, il y a déjà au Québec 11 distributeurs d’électricité avec un monopole : Hydro-Québec, 9 villes et une coopérative. Hydro-Québec n’est donc pas le seul distributeur. Pour le transport, certaines entreprises ont des lignes, comme Rio Tinto, et certaines lignes ont été construites en partenariat, comme avec les Mohawks vers les États-Unis. Encore ici, Hydro-Québec n’est pas seule.
  • Monopole (bis) : La production d’électricité et la vente au détail de l’électricité ne sont pas des monopoles naturels. Dans plusieurs régions, comme dans l’Union européenne, plusieurs producteurs se concurrencent pour faire de l’électricité vendue sur un marché ouvert. Les détaillants d’électricité achètent et revendent cette énergie aux consommateurs, selon divers plans, un peu comme on le voit dans l’industrie des télécommunications. L’électricité est livrée des producteurs aux consommateurs en utilisant le monopole naturel des entreprises de transport et de distribution. Cette structure à 4 étapes (production-transport-distribution-détail) est commune, et la structure largement intégrée verticalement du Québec est plus l’exception que la règle. Cependant, il y a aussi au Québec plusieurs autres producteurs : en éolien (Boralex, Kruger, Innergex, Énergir, etc.), avec de petites centrales hydroélectriques, certaines entreprises (comme Rio Tinto), et même certaines municipalités (comme Sherbrooke).
  • Réglementation des prix : Qui dit monopole dit réglementation des prix. Les prix de transport et de distribution sont toujours réglementés pour assurer un rendement correct sans être indus, forçant des investissements prudents?; parfois, les incitatifs à la performance (fiabilité, coûts) sont imposés, comme en Grande-Bretagne ou en Alberta. Là où la production et le détail sont concurrentiels, la réglementation peut être légère, essentiellement pour s’assurer que les prix et les conditions de services sont équitables, et pour s’assurer que la concurrence fonctionne pour le bien des consommateurs. Aussi, notons que les prix doivent être réglementés même pour un monopole d’État. Au Québec, la Régie de l’énergie est responsable de la réglementation du transport, de la distribution et de la vente au détail de l’électricité.
  • Nationalisation (ou privatisation) : La nationalisation est le transfert à l’état de la propriété d’entreprises privées. La nationalisation de la production et de la livraison de l’électricité au Québec, héritage de la Révolution tranquille, n’est pas sérieusement remise en question : personne ne voudra vendre Hydro-Québec au privé, à l’exemple d’Hydro One en Ontario il y a quelques années. La nationalisation des entreprises privées d’électricité, d’abord en 1944 puis en 1963, a permis, entre autres, d’accélérer l’électrification (aidant à la balance commerciale), de développer le secteur industriel secondaire (équipement électrique et aluminium), et de développer le secteur tertiaire (génie-conseil et informatique). Cependant, la nationalisation ne veut pas dire que le privé n’a aucun rôle à jouer ni qu’Hydro-Québec est le seul producteur, transporteur, ou distributeur. 

Au-delà des mots, l’important est de fixer les bons objectifs et d’utiliser les leviers à notre disposition pour les atteindre, en comprenant bien les avantages et les inconvénients de chaque modèle. 

Ce que signifie l’électricité à coût marginal zéro

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

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.

Residential Light-Duty EV V2G

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

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

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

The Case for Residential Light-Duty EV V2G

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

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

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

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

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

V2G vs. V2H vs. V2L

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

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

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

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

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

On-Board V2G (AC)

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

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

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

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

Off-Board V2G (DC)

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

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

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Don’t Fight a Declining Cost Curve

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

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

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

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

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

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

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

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

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

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

Don’t Count on Regulatory Barriers for Protection

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

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

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

Don’t Take Customers Nor Suppliers for Granted

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

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

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

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

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

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

Don’t Follow the Herd

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

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

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

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

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

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

Closing Thoughts

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

Which leads me to offer you this quote:

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

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


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

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

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

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

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

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

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

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

Energy Is Cheap; Power Is Valuable

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

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

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

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

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

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

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

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

How will this affect your business?


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

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

How Bill 34 Will Affect Vendors Selling to Hydro-Québec

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

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

Before: Traditional Rate Base Rate-of-Return Regulation

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

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

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

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

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

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

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

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

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

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

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

What Is Bill 34 Changing?

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

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

After: Faster, Risk-Taking and Innovative?

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

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

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

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

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

What May Not Change

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

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

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

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

Closing Words

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

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

Do not hesitate to contact me to discuss further. 

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

A Trojan Horse: Time-Varying Rates

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

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

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

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

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

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

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

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

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

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

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

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

 

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

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

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

A Perspective on Canada’s Electricity Industry in 2030

I wrote this piece with my friend Denis Chartrand as a companion document for my CEA presentation back in February 2018 (See http://benoit.marcoux.ca/blog/cea-tigers-den-workshop/) but I now realize that I never published it. So, here it is!

Canada Electricity Industry 2030 20180221

Customers of Electric Utilities Are Redefining Quality

Traditional utility wisdom in Canada is that customers are satisfied with the current level of reliability and that improving reliability would only increase costs and push rates up.

The new reality of electric utilities upends this traditional wisdom.

Customers are redefining what is meant by quality. Traditionally, Canadian Utilities used duration of interruptions per year, or SAIDI[i], as their main measure of reliability. Some utilities report the frequency of interruptions per year, SAIFI, as well. A limitation of SAIDI and SAIFI is that interruptions of less than a minute are not included, presumably under the assumption that customers do not care that much about short interruptions. This might have been true in the analog world of years past, but it is not anymore, with even a short interruption resetting our electronic devices. Furthermore, with the fuse saving protection strategy that most Canadian Utilities have adopted on their distribution feeders, short interruptions happen more frequently than longer ones, and are therefore noticed more.

Even a short interruption resets common electronics, like my microwave oven above. This gave birth to the “blinking clock” syndrome, a stark reminder to residential customers that an outage occurred and that their utility has failed them – again. (Photo by the author)

ENMAX, when justifying its distribution automation projects within the performance-based regulation scheme of Alberta, based its analysis on the cost of sustained and momentary service interruptions, with the values for its various customer classes as shown in the table below.[ii]

Table: Estimated ENMAX Customer Class Interruption Costs

Duration Residential Commercial Industrial Weighted Average
30 Minutes

 

$3.02 $992 $3,641 $92.77
Momentary
(% vs. 30-Min.)
$2.71 (90%) $757 (76%) $2,354(65%) $69.12(75%)
Customer mix 92.2% 7.3% 0.5% 100%

The table is interesting for two reasons:

  • On average, the costs to customers of a momentary interruption is 75% that of the cost of a 30-minute interruption, but up to 90% for residential customers. The very small difference in cost between a momentary outage and a 30-minute outage explains why outage frequency is a higher concern than length of outages for residential customers.[iii]Due to the prevalence of the fuse saving protection strategy on electrical distribution feeders in Canada,[iv]there are far more momentary service interruptions than sustained ones – momentary interruptions therefore become the primary concern of customers.
  • The bulk of the economic cost of service interruptions is borne by commercial and industrial customers. While residential customers are far more numerous, the cost per interruption is low. However, residential customers can be more vocal in their complaints in social and traditional media.

This situation is likely to get worse with widespread customer-owned distributed energy resources: owners of distributed energy resources actually lose money during power disturbance. Distributed generators or resources may be thrown offline often for minutes, for safety reasons and to protect the equipment. This results in loss revenue for owners of distributed generators selling back to the grid, or additional costs for those who were offsetting power otherwise purchased from the grid. Overall, the percentage of time when distributed generators are offline because of service interruptions is relatively small, and so is the unsold energy or the energy additionally bought by the customers while waiting for generation to come back online. However, those interruptions may also cause power generation or grid support contracts to be broken, which may carry penalties. Customers may also have to pay additional demand charges, often a large share of the utility costs of business customers.

Service interruptions also cost money, to utilities which is ultimately paid for by customers through higher rates – another key determinant of customer un-satisfaction. First, service interruptions cause power flow and voltage fluctuations as distributed generators trip and come back, and loss of generation and dynamic resources for the grid operator. In an electric network relying partly on distributed energy resources, service interruptions mean additional complexity to maintain stability of the grid and higher costs for network operators who then have to rely on backup resources. Service interruptions even increase operating costs. Fuse saving does not always work: on average, about half of fuse replacements have unknown causes or causes that should normally have been eliminated by fuse saving, such as animal contact.

By the way, the telecom industry also went through a redefinition of what customers mean by quality. It used to be that the main quality measure was voice sound quality during a call[v]. However, voice sound quality has actually gone down in the last decades – the rotary black phone in your grandmother’s old house sounded better than your new iPhone. Nowadays, customer satisfaction is driven more by the convenience of mobility and the possibility of easily doing videoconferencing or multiple parties calls.

In summary, with increasing dependence on reliable power for modern way of life, plus distributed generation earning revenue for customers, outage frequency will become a more and more important factor for customer satisfaction. All this being said, there is hope – new smart grid approaches and protection strategies can result in fewer service interruptions, leading to higher customer satisfaction and lower cost for utilities.


[i]       SAIDI means System Average Interruption Duration Index. SAIDI is the average duration of all the outages seen by customers over the course of a year. In Canada, only interruption durations of more than 1 minutes accrue to SAIDI. Interruptions of less than a minute are considered momentary and do not count toward SAIDI.

[ii]       Evaluation of PowerMax Distribution Automation Strategy, ENMAX Power Corporation, prepared by Quanta Technology, November 29, 2011, page 23.

[iii]     Assessing Residential Customer Satisfaction for Large Electric Utilities, Lea Kosnik et al., Department of Economics, University of Missouri—St. Louis, May 2014.

[iv]      Fuse saving is an electrical protection strategy used on many distribution feeders in Canada. The objective is to avoid that fuses installed on lateral taps blow for a non-persistent fault, such as an animal contact or a lightning strike. With fuse saving, a mainline or station a circuit breaker or recloser is used to operate faster than the lateral tap fuses. A few seconds after an initial fault, the breaker reclose, re-establishing power. If the fault is non-persistent, power will be restored. If not, it may retry later. If the fault is persistent, the breaker will eventually reclose and let the lateral fuse blow, isolating the fault. Because most faults are non-persistent, fuse saving prevents needless fuse blow, avoiding sustained service interruption for customers on the affected lateral. The main disadvantage of fuse saving is that all customers on the circuit see a momentary interruption for lateral faults.

[v]       The quality of a call is given by its Mean Opinion Score (MOS), a subjective measurement where listeners sit in a quiet room and rate a telephone call on a scale of 1 to 5. It has been in use in the telephony industry for decades and was standardized in an International Telecommunication Union (ITU) recommendation.

Wind and Solar PV Are Becoming a Chinese Story

In 2015, China became world’s largest producer of photovoltaic power, and this is clearly a policy enshrined in the 13th five-year plan (2016-2020).[i] This plan calls to increase installed wind power capacity to 210 GW and solar PV capacity to 105 GW by 2020 – about a third more than in 2016, although developers’ enthusiasm means that the solar PV 2020 objective will be achieved in 2018, given 34 GW added in 2016 and 54 GW in 2017 – more than the rest of the world combined. To put this 54 GW in context, it is a third more that the nameplate capacity of the electricity producers in the province of Québec.[ii] However, contrary to what happened in Europe, China’s policy followed the initial price reduction in wind and solar power. If Europe lit the renewable fire some time ago, China now fuels it.


Figure 1 The growth of wind and solar PV capacity saw Europe leading in early years, but China is now the main source of growth.[iii]

China now dominates new installed capacity for wind and solar PV, and this keen interest is enshrined in its 5-year plans – China will continue to have the largest share for years to come.

You may have noticed how small wind and solar PV capacities are in Canada in comparison to the rest of the world – just 12 GW for wind and 3 GW for solar PV, and barely visible in Figure 3. Canada is a small player for wind and solar PV. The rest of the world adds as much wind and solar PV capacity per year as the entire electricity generation capacity currently installed in Canada, all sources combined.

While new generation capacity from wind and solar is being installed at an increasing rate, investments have been essentially flat since 2011, compressed by dropping unit costs:[iv]

Figure 2 While new generation capacity from wind and solar is being installed at an increasing rate, investments have been essentially flat since 2011.

With lower unit costs per MW, developers can install more capacity for a given investment. This phenomenon can be expected if wind and solar technologies follow a pattern like Moore’s Law – we are not paying more for a computer than we did years ago, we are just getting more for the same price (or even lower price).

This flat 2011-2017 trend also masks major difference across the world: China’s new wind and solar investments went from $42B in 2011 to $123B in 2017 – almost half of global investments. Conversely, European investments went down in the same period, while North America was relatively flat. Canada’s investments in 2017 were a modest $3B.

The domination of Chinese investments is even greater when one considers China foreign investments in clean energy. China being already the largest market for renewable energy, it is developing the renewable sector internationally, aiming to be a leader along the entire value chain. China’s Belt and Road Initiative (BRI) is driving Chinese energy investments overseas. The initiative already has driven solar equipment exports of U.S.$8 billion.[v] China is not content to be a manufacturer and it is also looking for opportunities to develop Engineering, Procurement and Construction (EPC) standards that it can apply internationally, plus operating credentials. China is building corporate giants to fulfill those ambitions, such as Shenhua Group, now the largest wind developer in the world, with 33 GW of capacity.[vi] In 2016, Xinjiang Goldwind ranked 3rd for onshore and also 3rd for offshore wind turbine manufacturing[vii]. China has become the number one exporter of environmental goods and services, overtaking the U.S. and Germany.

————————–

[i]        See https://www.iea.org/policiesandmeasures/pams/china/name-161254-en.php and https://translate.google.com/translate?hl=en&sl=auto&tl=en&u=http%3A%2F%2Fwww.nea.gov.cn%2F2016-12%2F19%2Fc_135916140.htm, accessed on 20180116.

[ii]       Statistics Canada. Table 127-0009 – Installed generating capacity, by class of electricity producer, annual (kilowatts), http://www5.statcan.gc.ca/cansim/a47, accessed 20180131. In 2015, public electricity producers in Québec had an installed generating capacity of 37 GW, while privates ones has 3 GW.

[iii]      IRENA (2017), Renewable Energy Statistics 2017, The International Renewable Energy Agency, Abu Dhabi, with estimates based on Bloomberg New Energy Finance for 2017.

[iv]       Clean Energy Investment Trends, Abraham Louw, Bloomberg New energy Finance, January 16, 2018.

[v]        China 2017 Review, Institute for Energy Economics and Financial Analysis (IFEEA), p. 2.

[vi]       https://www.reuters.com/article/us-china-power-shenhua-guodian-factbox/factbox-shenhua-and-guodian-chinas-latest-state-marriage-idUSKCN1B918I, accessed 20180118.

[vii]      https://about.bnef.com/blog/vestas-reclaims-top-spot-annual-ranking-wind-turbine-makers/, accessed 20180118.

CEA Tigers’ Den Workshop

On February 21, 2018, I presented at the annual T&D Corporate Sponsors meeting of the Canadian Electricity Association. This year, the formula what similar to the “dragons” TV program, with presenters facing “tigers” from utilities. They asked me to go first, so I didn’t know what to expect, but it went well. Or, at least, the tigers didn’t eat me alive.

The theme was a continuation of my 2017 presentation, this time focusing on what changes utilities need to effect at a time of low-cost renewable energy.

I’ve attached the presentation, which was again largely hand-drawn: CEA 20180221 BMarcoux.

Utilities Should Lead the Change

I have worked in the telecom industry as head of marketing, in customer care and as a business consultant — I saw what happened there. More recently, I have also seen some of the best and the worst of stakeholder communications at electric utilities — including while I directed a large smart meter deployment, a very challenging activity for customer relationships. Beyond the obvious like using social media, online self-support, and efficient call center operations, There is one thing that electric utilities should do to improve their chances to maintain healthy customer relationships as the industry is transforming: lead the change.

“Someone’s going to cannibalize our business — it may as well be us. Someone’s going to eat our lunch. They’re lining up to do it.”

That was Alectra Utilities CEO, Brian Bentz, speaking at the Energy Storage North America in 2017.[i]

Utilities have a choice: lead change or have change done to them. The latter might hurt customer satisfaction more than the former.

Like telephone companies of the past, electric utilities could try to forestall the coming change, or even to reverse it, hoping to get back to the good old days. In fact, this is rather easy, as there is a lot of inertia built in a utility, often for good reasons: public and worker safety, lifelong employment culture, good-paying unionized jobs, prudency of the regulated investment process, long-lasting assets, highly customized equipment and systems, public procurement process, dividends to maintain for shareholders, etc. For utility executives, effecting change is never easy.

In the end, however, resisting change is futile. Customers are able to start bypassing utilities by installing solar panels and storage behind meters, keeping the utility connection as a last resort. It is just a matter of time before the economics become good enough for many industrial, commercial and residential customers, with or without net metering. Customers will do it, grudgingly, but they’ll do it. This will also leave fewer customers to pay for the grid, sending costs up and stranding assets, therefore increasing rates for customer unable to soften the blow by having their own generation, further antagonizing the public… A death spiral of customer satisfaction.

So, what should utilities do? Here are three examples of utilities that have embraced change and made it easy for their customers to adopt change:

  • Green Mountain Power (GMP) in Vermont helps customers go off the grid. Combining solar and battery storage, the Off-Grid package provides GMP customers with the option to generate and store clean power for their home that would otherwise come from the grid.  The Off-Grid package is customized for each customer and includes: an energy efficiency audit, solar array, battery storage, home automation controls, and a generator for backup. Customers pay a flat monthly fee for their energy.[ii]
  • GMP is also deploying up to 2,000 Tesla Powerwall batteries to homeowners. Homeowners who receive a Powerwall receive backup power to their home for US$15 a month or a US$1,500 one-time fee, which is significantly less expensive the US$7,000 cost of the device with the installation. In return, GMP uses the energy in the pack to support its grid, dispatching energy when it is needed most.[iii] Not surprisingly, results of a recent GMP customer satisfaction survey showed that customer satisfaction continues to rise.[iv]
  • ENMAX proposed to use performance-based regulation to the Alberta Utility Commission (AUC). The AUC set the regime in 2009. performance-based regulation has since then been expanded to other Alberta utilities. ENMAX stated that a number of efficiency improvements and cost-minimizing measures were realized as a result of its transition to a regulatory regime with stronger efficiency incentives. ENMAX indicated that it would not have undertaken these productivity initiatives under a traditional cost of service regulation.[v]
  • PG&E selected EDF Renewable Energy for behind-the-meter energy storage. The contract allows EDF RE to assist selected PG&E customers to lower their utility bills by reducing demand charges, maximizing consumption during off-peak hours, and collecting revenue from wholesale market participation. [vi]

References:

[i]         As reported by UtilityDIVE, https://www.utilitydive.com/news/alectra-utilities-ceo-someones-going-to-cannibalize-our-business-it-ma/504934/, accessed 20180102.

[ii]        See https://www.greenmountainpower.com/press/green-mountain-power-first-utility-help-customers-go-off-grid-new-product-offering/, retrieved 20171229.

[iii]        See https://www.tesla.com/blog/next-step-in-energy-storage-aggregation, retrieved 20171230.

[iv]       see https://www.greenmountainpower.com/press/green-mountain-power-survey-shows-customer-satisfaction-continues-rise/, retrieved 20171230

[v]        Performance Based Regulation, A Review of Design Options as Background for the Review of PBR for Hydro-Québec Distribution and Transmission Divisions, Elenchus Research Associates, Inc., January 2015, page A-25.

[vi]       See http://www.energystoragenetworks.com/pge-selects-edf-behind-meter-energy-storage-contract/, retrieved 20171230.

A Critique of the National Energy Board Assessment on Canada’s Energy Future

The NEB published its 2017 assessment on Canada’s energy future a few weeks ago. The NEB, purposely an independent national energy regulator, published this report, part of the Energy Futures series, to be used, among other things, as an input for sound policy making. However, I find it lacking coherent vision.

Curiously, the assessment starts with an admission of failure, with its first “key finding” that the 2017 Energy Futures report is the first where fossil fuel consumption peaks within the projection period. Indeed, each subsequent update since the first Energy Futures in 2007 shows lower and lower fuel use projections:

The chart can be interpreted in two ways: the NEB had it wrong in the past, and now they have it right, or, the NEB must again be getting it wrong. Looking at the assumptions shows that it is the later. While the NEB projects a peak in consumption, it also projects higher oil prices (from $50 to $65–80 per barrel of Brent, depending on scenarios), which is rather surprising, especially since it also projects a constant increase in supply for oil sands, up 59% by 2040 in comparison to 2016.

While the report includes projected price for fuel and gas, it, strangely, does not include projection for the price of electricity. There are, however, a number of projections on the change in generation mix and underlying cost and demand trends.

All scenarios show a (modest) increase in the share of electricity in the national energy mix. The “Technology Case” scenario, the most optimistic one toward clean energy, shows a shift toward more electricity and reduced overall demand in the end-use sector, and more renewable generation in the electricity sector—but the changes are rather small. This modesty is justified by a number of assumptions.

The report projects an increase in new electric passenger vehicles—but growth flattening after 2025, justified by the phase out of incentive programs. Essentially, the NEB assumes that EVs will never be truly competitive with internal combustion cars.

On renewables, the NEB an increase in generation and a decrease in costs under all scenarios. However, the projections are nevertheless surprising. The report acknowledges that solar costs have been coming down 20% a year since 2010:

Then, the report projects that future costs will continue to drop at … 3% to 5% per year:

There is no explanation on what might have happened in 2016 or 2017 to explain this surprising shift.

As a consequence, the projection for non-hydro renewable is rather modest, with much slower growth in the future:

I cannot condone these NEB projections, as they run contrary to what I see in the market.

I just hope that no one uses them to justify how to spend my tax dollars.

Impact of Regulatory Regimes on Executive Behavior

Few outside the executive suite of utilities really appreciate how the regulatory regime affects executive behavior. As understanding behavior is key to selling, I am sharing my thoughts below, applicable mainly to North American utilities.

Problem Statement for Executives of Investor-Owned Utilities 

Given their monopoly over a defined territory, North American Investor-Owned Utilities (IOU) are subjected to price regulation by the state or the province, meaning that a regulator (such as a public service commission, a public utility commission or an energy board) sets the price they charge for the use of their infrastructure (poles, conductors, cables, transformers, switches, etc.).

Most North American IOUs are under rate-of-return regulation, or a variation of it. With rate-of-return regulation, regulator set the price so that utilities are compensated for their costs (operating costs, depreciation on assets, and taxes) and allowed a fair return on their investment. This is done by filing tariffs that are approved by the regulator following a rate hearing.

Utility executives are paid to maximize shareholder returns. Since utility shareholders are rewarded by a fair rate of return on a base of assets, executives create shareholder value by justifying more assets to the regulator while lowering the risk profile that shareholders perceive in future earnings. However, the regulator only allows new asset expenditures if they are prudent and if the society benefits. A capital expenditure is prudent if the costs are reasonable at the time they are incurred, and given the circumstances and what is known or knowable at this time. The society benefits if the expenditures minimize the required revenue paid by ratepayers, have a positive impact on the economy (such as improved reliability), improve customer service (such as fewer complaints), reduce societal risks (such as those caused by major weather events or those linked to information security), or achieve government policies and meet regulations (such as renewable generation targets). By constantly meeting regulatory concerns, utility executives ensure that the utility will be compensated through rates, with predictable earnings and minimizing the risk profiles that investors perceive. Conversely, when a utility fails to show that it is making prudent decisions or that the society benefits, then the regulator may disallow investments from the rate base. In such a case, shareholders bear the shortfall through reduced earnings and share value.

For utility executives, the fundamental objective is to select investment projects that minimize required revenue (a regulatory term defined as operating expenses + depreciation + taxes + return on assets) while being prudent and maximizing societal benefits (to ensure approval). These projects increase the regulated base of assets while minimizing the shareholder risk profiles. This is why utility executives are generally willing to trade lower operating expenses (which is the only other controllable element in the definition of required revenue) for higher capital expenditures. It is also why they are seeking ways to lower operating expenses through subcontracting or outsourcing, as it frees revenue to justify additional capital expenditures. This is often expressed as a rule of thumb, such as “we are OK with $10 of capital to save $1 of operating expenses”, although regulatory approval is always required.

Expressions such as “equipment failures hurt the bottom line” make little sense for a utility executive: if an old equipment that failed is replaced by a new one, that’s actually good, as the old one is written off (the loss being recovered from the ratepayers) and a new asset is added to the base (for which shareholders will get a return). Similarly, the expression “reducing operating expenses improves your bottom line” is not absolutely true – such reduction eventually accrues to ratepayers, not shareholders, but often just to offset other increases. However, it can be true in a sense if the reduced operating expenses are the result of capital expenditures that increase the asset base and, hence, the return paid to shareholders. Hypothetically, utility executives should want to replace all (non-executive) workers (i.e., operating expenses) by robots (i.e., capital assets).

This leads to a number of factors that utility executives ponder when deciding on new investment projects. They will be inclined to support an investment project before their regulator if it results in a combination of the following factors, arguably ordered from the strongest down:

  • Meeting governmental obligations:
    • Meeting statutory obligations, such as workers’ health and safety regulations and CIP V5 cybersecurity standards.
    • Meeting policy obligations, such as integrating renewable sources in the distribution network, energy conservation programs, removal of PCB or oil filled equipment, and reduction of greenhouse gas emissions.
    • Prudency, which determines if the costs are reasonable with what is known at the time of filing.
  • Lower rate impact:
    • Lower operating expenses, such as avoiding overtime truck rolls.
    • Lower energy costs for rate payers, such as if technical losses are diminished.
    • Stretched service life or reduced maintenance costs of existing assets, such as by limiting stress on station transformers installed 50 years ago and approaching end-of-life.
    • Lowering carbon taxes.
  • Reduced societal risks:
    • Greater resiliency during major events, such as looping distribution feeders and underground construction.
    • Better public safety, such as avoiding forest fire.
  • Positive impact on the economy:
    • Reducing sustained or momentary outage costs.
    • Three-phasing of rural lines to better serve C&I customers.
  • Improved quality of service:
    • Improved customer service metrics, such as fewer customer complaints from flickers.
    • Fairness among customers, such as improving reliability experienced by customers in rural areas to approach that of urban areas.

Each utility operates in its own regulatory and societal environment. Therefore, the relative importance of these factors varies between utilities. In particular, some price-cap regulation is starting to appear in North America. With price-cap regulation, prices are set from a starting point and then adjusted according to an economic price index (such as CPI) minus some expected productivity improvement and plus or minus incentives. However, few states and provinces have moved to price-cap regulation for electric utilities. Also, given that the starting point of price-cap is rate-of-return, and given that unforeseen events may cause utilities to petition regulators for additional capital spending, the difference in executive behavior between the 2 regimes may not be as large as one might think. Still, with utilities under price-cap regulation, it is better to talk about total cost of ownership than about capital spending. Some utilities also have quality of service incentives that increase the importance of reliability indices.

Problem Statement for Executives of Customer-Owned Utilities 

Customer-Owned Utilities (COU), essentially cooperatives and municipal utilities, are often regulated by their local government (such as a city council), just like other city services like water and waste disposal. They typically have a shorter feedback loop with customers than IOUs. Contrary to executives of investor-owned utilities, executives of customer-owned utilities do not have an incentive to maximize their base of assets, so tradeoffs may favor more operating expenses, especially so since they are seen as good employers in their communities. Investment decisions will weigh more on societal benefits and risks, with emphasis on customer service and quality of service. Therefore, it is important to adjust the language, as insisting on capital investments only does not make sense for customer-owned utilities.

Large Canadian provincial utilities and municipal utilities across North America are publicly owned, like traditional COUs, but often pay dividends to their owners. Their behavior is normally somewhere between those the IOU and COU extremes, especially if most of the rate increases can be shifted to generators.