Category Archives: Business Models

EV Charging: an Enabler for Utility Customer Engagement

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

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

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

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

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

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

Energy Is Cheap; Power Is Valuable

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

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

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

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

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

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

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

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

How will this affect your business?


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

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

How Bill 34 Will Affect Vendors Selling to Hydro-Québec

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

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

Before: Traditional Rate Base Rate-of-Return Regulation

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

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

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

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

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

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

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

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

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

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

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

What Is Bill 34 Changing?

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

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

After: Faster, Risk-Taking and Innovative?

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

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

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

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

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

What May Not Change

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

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

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

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

Closing Words

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

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

Do not hesitate to contact me to discuss further. 

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Here is the short deck that I presented.

Mcgill University 20190227

A Trojan Horse: Time-Varying Rates

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

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

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

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

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

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

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

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

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

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

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

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

 

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

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

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

The Sun for a Penny

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