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

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

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

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

Let’s see how different EV charging really is.

EVs Are Large and Mobile Loads 

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

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

So What?

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

EV Charging Is Highly Price Elastic

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

Many studies confirm the high price elasticity of EV charging:

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

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

So What?

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

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

Drivers Easily Control When to Charge

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

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

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

So What?

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

Looking Forward

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Here Are the 145 Canadian Electric Utilities

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

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

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

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

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

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

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

Let me know if you want to know more!

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

Presentation at the EV Charging Infrastructure Summit

Today, I presented at this conference.

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

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

You can download the presentation and the speaker notes here:

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

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

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

EV Charging Puts Downward Pressure on Electricity Rates

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

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

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

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

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

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

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

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

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

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

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

The Electric Cars in the Future of Utilities

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Don’t Fight a Declining Cost Curve

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

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

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

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

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

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

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

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

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

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

Don’t Count on Regulatory Barriers for Protection

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

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

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

Don’t Take Customers Nor Suppliers for Granted

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

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

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

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

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

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

Don’t Follow the Herd

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

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

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

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

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

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

Closing Thoughts

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

Which leads me to offer you this quote:

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

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

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

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

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

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

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

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

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

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

EV Charging: an Enabler for Utility Customer Engagement

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

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

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

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

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

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

Energy Is Cheap; Power Is Valuable

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

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

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

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

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

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

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

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

How will this affect your business?

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[ii]               Chapter 10.

[iii]              Chapter 10.

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

[v]                Chapter 6.

[vi]               Chapter 6.

[vii]              Chapter 6.

[viii]             Chapter 6

[ix]               In the introduction.

[x]                Chapter 1.

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

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


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

Why Should You Interview Customers?

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

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

Decide on What You Want to Assess

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

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

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

Select Interviewees

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

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

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

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

Get the Logistics Out of the Way

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

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

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

Have an Interview Guide

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

Some base rules in preparing an interview guide include:

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

Make the Interview Dynamic

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

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

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

Analyze the Results

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

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

Plan Enough Time

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

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

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

Closing Words

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

How Bill 34 Will Affect Vendors Selling to Hydro-Québec

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

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

Before: Traditional Rate Base Rate-of-Return Regulation

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

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

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

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

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

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

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

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

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

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

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

What Is Bill 34 Changing?

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

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

After: Faster, Risk-Taking and Innovative?

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

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

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

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

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

What May Not Change

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

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

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

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

Closing Words

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

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

Do not hesitate to contact me to discuss further. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Digital Utility of the Future Conference

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

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

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

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

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

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

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

Here is the short deck that I presented.

Mcgill University 20190227

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

Barbarians at the Gate (or: How to Stop Worrying and Love Your Customers)

This mouthful title was the title of my presentation today at the Smart Grid Canada conference in Montréal.

As usual, it is written in my somewhat funky style and provocative, but was well received.

Let me know what you think!

SGC20180912 BMarcoux

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
(% 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.

Lower and Lower Energy Prices from Wind and Solar PV

Reduction in installed costs and operation costs (per kW or MW – see http://benoit.marcoux.ca/blog/the-costs-of-wind-and-solar-pv-systems-are-down-way-down/), coupled with free “fuel” converted into electricity at increasing efficiency, translate directly into lower and lower cost of energy (kWh or MWh). The dropping cost of wind and solar energy can be followed in 2 ways. First, analysts compute the costs over the expected life of a plant, estimate energy production and allocate a fair return for owners to come up with the Levelized Cost Of Energy (LCOE). Second, real-life auctions leading to long-term Power Purchase Agreements (PPA) from utility-scale plants provide actual price data.

At the global level, the International Renewable Energy Agency (IRENA) has built a Renewable Cost Database containing the project level details for almost 15,000 utility-scale renewable power generation projects around the world, from large GW-scale hydropower projects to small solar PV projects, down to 1 MW. IRENA also has an Auctions Database which tracks the results of competitive procurement of renewable power generation capacity that are in the public domain. The Auctions Database currently contains auction results for around 7,000 projects, totaling 293 GW. Figure 1 shows the LCOE and auction data for onshore wind and solar PV, illustrating the sharp decline in the cost of electricity experienced from 2010 to 2017, and signaling prices for 2020 from auction data. Auctions are particularly useful to estimate cost trends in the near future. In essence, just like computer designers are forward-pricing based on Moore’s Law, wind and solar PV developers are forward-pricing installed costs for up to 3 years.

Figure 1 Global levelized cost of electricity and auction price show downward trends for utility-scale onshore wind and solar PV.[i]

Based on LCOE, the average cost of electricity from onshore wind fell by 23% from 2010 to 2017. Based on auction price, we can expect the average cost of electricity from onshore wind farms to decline a further 17% by 2020, to US4.7¢ per kWh. Overall, from 2010 to 2020, the cost of electricity from onshore wind has seen an average reduction of almost 6% per year, or 55% per decade.

Based on LCOE, the average cost of electricity from utility-scale solar PV fell by 73% from 2010 to 2017. Looking forward with auction prices, we can expect the average cost of electricity from utility-scale solar PV to decline a further 47% by 2019, to US4.7¢ per kWh. From 2010 to 2019, the cost of electricity from utility-scale solar PV has seen an average reduction of 20% per year, or 87% per decade.

By 2019 or 2020, the best onshore wind and solar PV projects will be delivering electricity for less than 2¢ or 3¢ per kWh, as shown by the record-low auction prices for solar PV in Dubai, Mexico, Peru, Chile and Saudi Arabia.[ii]This is not missed by leading industry executives. During the January 2018 investor call, Jim Robo, Chairman and Chief Executive Officer of NextEra Energy, noted:

  • “[Without] incentives, early in the next decade wind is going to be a 2 to 2.5 cent per [kWh] product.”
  • “By early in the next decade, as further cost declines are realized, and module efficiencies continue to improve, we expect that without incentives solar pricing will be 3 to 4 cents per [kWh], below the variable costs required to operate an existing coal or nuclear generating facility of 3.5 to 5 cents per [kWh].”[iii]

This executive is saying that generating energy from wind and solar PV will cost less than just burning fuel in existing plants.

Even in Canada?

In December 2017, the Government of Alberta announced the results of its Renewable Electricity Program, for nearly 600 MW of wind generation to be operational in 2019, at prices ranging from 3.09¢ to 4.33¢ per kWh, setting a new record in Canada.[iv]Those wind farms will be located in Southern Alberta, where the onshore wind resources are the best in Canada.

Already now, and increasingly in coming years, some wind and solar PV power generation projects can undercut fossil fuel-fired electricity generation, without financial incentives, and this is coming to Canada very quickly.

Global averages do not reflect the broad variation in the quality of solar or wind resources at any given location. For example, Figure 11shows the LCOE in 3 U.S. cities for utility-scale solar PV: Phoenix, AZ (a southern high-insolation area), Kansas City, MO (an average city in the U.S.), and New York, NY (typical of the North-East). A utility-scale solar PV plant in a high-insolation area like Phoenix can produce electricity for approximately 30% less than a plant in New York. However, all geographies have seen a decline in the cost of generation. Given the average decline of 20% per year, costs in New York are about 18 months behind costs in Phoenix.

Figure 2 Cost of electricity generated from utility-scale (one-axis tracking) solar PV increases at higher latitudes[v]

Cities with better isolation can be expected to have better solar PV capacity factor, and this is true when comparing U.S. and Canadian cities, as shown in Table 1.

Table 1 Approximate annual generation of a 100-MW tracking solar PV systems in various North American cities[vi]

City Annual generation in MWh for a 100-MW system % vs. Phoenix
Phoenix, AZ 219,000 100%
Kansas City, MO 173,000 79%
New York, NY 153,000 70%
Lethbridge, AB 189,000 86%
Calgary, AB 182,000 83%
Montréal, QC 146,000 67%
Toronto, ON 144,000 66%
Halifax, NS 145,000 66%
Vancouver, BC 135,000 62%

Based on this table, utility-scale tracking solar PV system in Southern Canada generates approximately 62% to 86% of the electricity generated by a similar system in Phoenix, AZ. Southern Alberta has the best solar resources in Canada, above the U.S. average (represented here by Kansas City, MO).[vii]Given that cost of electricity from utility-scale solar PV sees an average reduction of 20% per year, the large Canadian cities are just 1 to 2 years behind Phoenix.

The annual generation stated in Table 1does not reflect diurnal and seasonal variations in output. After all, the sun does not always shine, nor does the wind always blow. A combination of dispatchable generation, transmission networks, demand management programs and energy storage is required to balance the grid, including the variability of wind and solar generation. However, it is interesting to note that the wind and solar resources in Canada are quite complimentary:

  • Geographically, the onshore wind resources are better at higher latitudes, while the solar resources are better in Southern Canada.[viii]
  • In Southern Canada, Alberta and Saskatchewan offer the best onshore wind and solar resources.
  • Offshore wind is available on the Pacific Coast (British Columbia), on the Atlantic Coast (Maritimes provinces and NF&L), on the Great Lakes (Ontario) and Lake Winnipeg (Manitoba).
  • Hydroelectric potential is greatest in Québec and Manitoba.
  • Across Canada, wind resources are, on average, better in the winter, while the solar resources are better in the summer. There is also some hourly complementarity between wind and solar potential.[ix]


[i]       Renewable Power Generation Costs in 2017, International Renewable Energy Agency, 2018, Figure 2.12, p. 50.

[ii]      Renewable Power Generation Costs in 2017, International Renewable Energy Agency, 2018, p. 19-20.

[iii]     http://www.investor.nexteraenergypartners.com/phoenix.zhtml?c=253465&p=earningsRelease, accessed 20180130.

[iv]      https://www.aeso.ca/market/renewable-electricity-program/rep-round-1-results, accessed 20180128.

[v]       U.S. Solar Photovoltaic System Cost Benchmark: Q1 2017, National Renewable energy laboratory, Figure ES-3.

[vi]      http://pvwatts.nrel.gov/index.php, accessed 20180129, and author’s calculations.

[vii]     Calgary is the sunniest of Canada’s largest cities and Edmonton is the third-sunniest. Perhaps surprisingly, Alberta enjoys a much better solar resource than Germany, an early leader in solar PV.

[viii]    See the The Atlas of Canada – Clean Energy Resources and Projects (CERP), http://atlas.gc.ca/cerp-rpep/en/, accessed 20180129, for the wind and solar energy resource potential in Canada.

[ix]      Energy Watch Group, Global Energy System Based on 100% Renewable Energy – Power Sector: Canada, Lappeenranta University of Technology, 2017, p. 5.

The Costs of Wind and Solar PV Systems Are Down – Way Down


Insight  1
Utility-scale solar PV costs are dropping ~20% a year (including solar panels, inverters, balance-of-system, installation, and operations) while panel efficiency is improving. Solar is the renewable sector with the most patents, promising further improvements.

Insight  2
Onshore wind costs are dropping ~6% a year, and onshore wind is currently the least expensive new generation source. Wind turbine technology continues to improve through a combination of taller towers and wider rotor diameters.

Insight  3
Prices are below 2¢/kWh (unsubsidized) for projects auctioned to be delivered in 2019 and 2020. Continuing cost drivers include:  larger-scale manufacturing in low-cost locations, tighter integration, higher performance, larger farms with better economy of scale, repowering of old sites with good wind or solar resources, and automation of operations.

Insight  4
The cost reduction curve of commercial solar PV over time is about two years behind the cost curve of utility-scale solar farms. Residential is two years behind commercial. Southern Alberta and Saskatchewan have the best solar resource in Canada, one year behind Southern United States. The rest of Southern Canada is just another year behind.

The rate of cost reduction in wind and solar PV systems has been wholly impressive. Solar PV modules are 20% of the cost they were in 2010. Wind turbine prices have fallen by around half over a similar period, depending on the market. Costs are dropping so quickly that some governments feel compelled to protect fossil generators. For example, in 2017, there was a bill in front of the Wyoming State Legislature to tax renewables in order to favor local coal producers. The bill went nowhere, but you know that you are onto something when it is being taxed.[i] Similarly, the U.S. Department of Energy attempted to protect coal and nuclear producers in the name of keeping power grids dependable, but this was eventually rejected by the Federal Energy Regulatory Commission in early 2018.[ii]

Spurred by a global competitive race sponsored by states and large corporations, a confluence of performance improvements, supply chain efficiencies and business innovations is driving cost reduction trends for renewables, with effects that will only grow in magnitude in 2018 and beyond.

Figure 1 A confluence of performance improvements, supply chain efficiencies and business innovations is driving cost reduction trends for renewables

Performance improvements

The last decade has seen a string of innovations and inventions for renewable energy technology. The large number of patents issued is a measure of the level of innovation, and, perhaps surprisingly, China has become the leading innovator by this measure. From 2000 to 2016, over 575,000 patents were filed for renewable energy:[iii]

  • Half of them since 2010.
  • 55% were for solar energy and 20% for wind energy. Hydropower, a mainstay of Canadian Utilities, accounted for just 6% of patents.
  • Greater China (including Hong Kong and Taipei) accounted for almost a third of patents, well ahead of second-place United States at 18%. Canada has less than 1.5% of those patents.

Technology improvements primarily aim at raising the capacity factor, generating more energy from available resources, and reducing installations, operating and maintenance costs.

For example, in the last decade, the efficiency of solar PV panel went from about 12% to a range of 18.8-23.5%. By 2424, industry expectations place the range at 19.8-25%.[iv] Increased use of sun tracking for utility-scale plants and improvements in inverter losses are also contributing to the improvement of the capacity factor of solar PV systems, with utility-scale PV systems increasing from an average of 13.7% to 17.6% (see Figure 2).[v]

For wind power, higher hub heights allow turbines to access higher wind speeds[vi], with each additional meter of hub height added to a wind turbine increasing the annual energy yield by 0.5 to 1 percent[vii]. Average rotor diameter and nameplate capacity (in MW) have also significantly increased since 2010[viii]. Offshore installations allow even larger turbines, with the 9.5 MW Vestas V164 currently holding the world record[ix] and General Electric developing an even larger Haliade-X 12 MW model[x].  As the market for wind turbines expands, manufacturers are also offering a broader range of models to allow developers to choose the best models for the site constraints they are facing (e.g., strong winds, light winds, wind variability, setting issues, etc.).[xi] All this contributes to better wind capacity factor: average capacity factor for onshore wind plants increased from around 20% in 1983 to around 29% in 2017, with average capacity factor for newly commissioned offshore plants routinely reaching 40% (see Figure 2)[xii], with a new offshore floating wind farm, Hywind Scotland, achieving a 65% capacity factor from November 2017 through January 2018.[xiii]

Figure 2 Capacity factors of newly commissioned systems have increased since 2010.[xiv]

Supply chain efficiency gains

As the market for renewable power generation systems expands, the industry sees increasing economies of scale in manufacturing, better vertical integration of manufacturers and consolidation among manufacturers, all fueled by a more competitive global supply chain. Again, China stands as a model, for example creating the largest power company by combining Shenhua Group and China Guodian. Groups such as this are active as foreign investment agents of China, using Chinese wind turbines and solar panels, along with Chinese engineering expertise, to develop renewable wind and solar plants across the world.

With larger scale operations, manufacturers are introducing process improvements that reduce material and labor needs, while reducing overhead. The supply chain gets more and more optimized with product better adapted to local markets and resource conditions.

As a result of these efficiencies and a robust international competitive environment for developers, the installed costs of utility-scale solar PV projects fell by 68% between 2010 and 2017. Installed costs for onshore wind projects fell by 20%. For offshore wind, the total installed costs fell by 2%.

Figure 3 Installed costs have come down since 2010, on average 20%/year for solar PV.[xv]

It is striking that wind and solar PV costs went down so much while efficiency went up at the same time.

For wind electricity generation, installed cost reductions have been driven by declines in turbine prices which, which fell from a range U.S.$1,600-2,000/kW in 2008 to U.S.$800-1,100/kW for recent turbine orders.[xvi] In 2017, one developer saw a 30% reduction in turbine costs and foresees another 10% decline per year through 2020.[xvii] Even as price went down, the profitability of turbine manufacturers has generally rebounded since 2012,[xviii] with the price declines explained by turbine scale, offshoring of key components by European manufacturers and the rise of Chinese manufacturers[xix]. As a result of cost decline and the greater efficiency of new turbines, repowering old wind farms with new turbines is gaining traction.[xx]

Figure 4 compares the reduction in solar PV installed costs for utility scale (100 MW), commercial (200 kW) and residential solar PV (5.7 kW) in the U.S. market, from 2010 to 2017. Overall, the costs of utility scale have declined 20% per year on average since 2010, while the costs of residential and commercial U.S. systems have declined about 14% per year on average. As of 2017, residential installed costs are 2.5 times higher than utility-scale solar PV; commercial installed costs are in the middle, at 1.8 times. However, in order to appreciate the scale of the reduction, note that the installed costs of residential systems in 2017 are at about the same level as utility scale in 2012 or 2013 – a 4-year lag. Commercial costs are less than 2 years behind utility-scale costs. It only took a couple of years for the cost structure of residential and commercial systems to catch up with utility-scale systems that are orders of magnitude larger! With the efficiency due to the economy of scale up the supply chain, the economy of scale of the PV systems themselves is quickly collapsing. This opens the door for smaller, distributed solar PV systems to have a positive business case.

Installed cost reductions happened in all components of systems, including solar panels, inverters, structural and electrical components, install labor, and even customer acquisition or marketing. However, the cost reductions of solar panels were the largest ones. This was driven by Chinese solar manufacturers, who accounted for about 60% of global solar cell production in 2016.[xxi] China’s dominance in solar manufacturing does not come at the expense of quality, with seven of the top ten largest high-quality manufacturers supplying the U.S. residential market being Chinese.[xxii] Manufacturing capacity expansion increased in 2017, with China accounting for 70% of the expansion.[xxiii]

Figure 4 Installed costs of solar PV came down across all market segments in the U.S., with commercial and residential costs only 2 to 4 years behind utility scale.[xxiv]

The installed cost reduction of solar PV systems in the U.S. was partly driven by the reduction in solar PV module prices since 2010. Balance of system costs have also fallen, but not to the same extent (see Figure 5). Commercial systems are still relatively custom designs, with relatively high engineering, construction and developer overhead. Residential systems are a retail market, with higher supply chain, marketing, overhead and profit margins than the business-to-business markets. Furthermore, the cost of residential and commercial solar PV system in the U.S. is higher than many other countries. As an example, the installed costs of residential solar PV in Germany were around 37% of those in California in 2016[xxv] and the analysis suggests that there are significant opportunities to reduce the gap, if the right policies are put in place. Another study blames very high overhead in the U.S. for the high cost of residential systems.[xxvi] As the electrical code is adapted and permitting streamlined, this study suggests that residential costs will come down in the U.S.

Figure 5 Installed costs of solar PV came down across all market segments in the U.S., but soft costs remain high in the residential and commercial markets.[xxvii]

Business innovations

On the backdrop of improving performance and supply chain efficiencies, business models, commercial and operating innovation are perhaps the most significant cost reduction factors for developers and operators.

First, experienced international project developers, especially from Europe and China, have developed standardized approaches to project evaluation and construction, minimizing project development risks. These firms are now looking for international opportunities as that some of their home markets are slowing. These firms are generally subsidiaries of large groups, like EDF and Shenhua (the world’s largest wind power developer), with access to low cost of capital. Chinese solar module manufacturers continue to feature strongly in overseas solar generation projects. In 2017, Chinese companies took part in projects across Asia, Latin America, Australia, and Africa. No doubt that operating in cost-sensitive and low-skill developing countries in forcing Chinese developers to innovate even more, probably with the idea to bring those innovations in developed countries later.

Second, competitive procurement get a large number of experienced medium- and large-scale developers competing to develop projects, worldwide. The relatively low barriers to entry also put smaller local players into play. The resulting purchase agreements set the price of energy for typically 20 years, adding predictability to developers’ business case, and driving costs further down than the favorable feed-in tariffs initially used in many jurisdictions (like Ontario).

Thirdly, optimized operational practices and the use of real-time and big data analytics at an increasingly granular level enable predictive maintenance to reduce ongoing costs and generation loss from downtime.[xxviii] For example, new PV panels have built-in diagnostic tools accessible remotely via monitoring software. New wind and solar farms are being designed with serviceability in mind to minimize ongoing operation and maintenance costs. Benchmarking performance and digital twins with advance analytics allow operators to identify areas of improvement. Drones do aerial thermography to identify hotspots while robots clean panels and mow grass. All these tools clearly reflect the increasing maturity of renewable power generation technologies.

[i]        http://www.forbes.com/sites/williampentland/2017/01/18/wyoming-considers-de-facto-prohibition-on-solar-and-wind-energy/, accessed 20180118.

[ii]       https://www.bloomberg.com/news/articles/2018-01-08/perry-plan-to-help-coal-nuclear-plants-rejected-by-regulators, accessed 20180118.

[iii]      International Renewable Energy Agency (IRENA), INSPIRE database, http://inspire.irena.org/Pages/patents/Patents-Search.aspx, accessed 20180121.

[iv]       Renewable Power Generation Costs in 2017, International Renewable Energy Agency, 2018, pp. 59-61.

[v]        Renewable Power Generation Costs in 2017, International Renewable Energy Agency, 2018, p. 66.

[vi]       Wind power in an open-air stream is proportional to the third power of the wind speed. Thus, a wind speed 10% higher means 33% more available power, all other things being equal.

[vii]      http://www.mbrenewables.com/en/world-record-for-energy-transition/, accessed 20180121.

[viii]     Renewable Power Generation Costs in 2017, International Renewable Energy Agency, 2018, p. 91.

[ix]       http://www.mhivestasoffshore.com/worlds-most-powerful-available-wind-turbine-gets-major-power-boost/, accessed 20180121.

[x]        https://www.reuters.com/article/us-ge-windpower-france/ge-to-develop-worlds-largest-wind-turbine-in-france-idUSKCN1GD5GW, accessed 20180310.

[xi]       General Electric, Siemens and Vestas have all roughly doubled the number of offerings in their portfolio since 2010, with each now offering over 20 models. See Renewable Power Generation Costs in 2017, International Renewable Energy Agency, 2018, p. 90.

[xii]      Renewable Power Generation Costs in 2017, International Renewable Energy Agency, 2018, pp. 102-103.

[xiii]     https://www.statoil.com/en/news/15feb2018-world-class-performance.html, accessed 20180310.

[xiv]     Renewable Power Generation Costs in 2017, International Renewable Energy Agency, 2018, pp. 42-47.

[xv]      Renewable Power Generation Costs in 2017, International Renewable Energy Agency, 2018, pp. 42-47.

[xvi]     2016 Wind Technologies Market Report: Summary, Lawrence Berkley National Laboratory, U.S. Department of Energy, p. 43.

[xvii]    http://www.investor.nexteraenergypartners.com/phoenix.zhtml?c=253465&p=earningsRelease, accessed 20180130.

[xviii]   2016 Wind Technologies Market Report: Summary, Lawrence Berkley National Laboratory, U.S. Department of Energy, p. 18.

[xix]     Globally, Vestas, GE, and Goldwind were the top suppliers in 2016, with Chinese suppliers however occupying 4 of the top 10 spots in the global ranking, based almost entirely on sales within their domestic market.

[xx]      https://www.eia.gov/todayinenergy/detail.php?id=33632, accessed 20180202.

[xxi]     IEA Renewables 2017: Analysis and Forecasts to 2022.

[xxii]    http://news.energysage.com/best-solar-panel-manufacturers-usa/, accessed ???.

[xxiii]   China 2017 Review, Institute for Energy Economics and Financial Analysis (IFEEA), p. 3.

[xxiv]    U.S. Solar Photovoltaic System Cost Benchmark: Q1 2017, National Renewable Energy Laboratory, Figures ES-1.

[xxv]     The Power to Change: Solar and Wind Cost Reduction Potential to 2025, International Renewable Energy Agency, 2016, p. 11.

[xxvi]    https://www.greentechmedia.com/articles/read/how-to-halve-the-cost-of-residential-solar-in-the-us?utm_source=Solar&utm_medium=email&utm_campaign=GTMSolar#gs.UscExbA, accessed 20180131. This study shows that the cost per watt in US$3.25 in the US and US$1.34 in Australia.

[xxvii]   U.S. Solar Photovoltaic System Cost Benchmark: Q1 2017, National Renewable Energy Laboratory, Figures ES-1.

[xxviii] https://www.bloomberg.com/news/articles/2018-01-12/buffett-s-squeezing-more-power-out-of-wind-with-this-software, accessed 20180120.