Category Archives: Canada

A Trojan Horse: Time-Varying Rates

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

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

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

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

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

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

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

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

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

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

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

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

 

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

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

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

A Perspective on Canada’s Electricity Industry in 2030

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

Canada Electricity Industry 2030 20180221

Customers of Electric Utilities Are Redefining Quality

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

The new reality of electric utilities upends this traditional wisdom.

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

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

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

Table: Estimated ENMAX Customer Class Interruption Costs

Duration Residential Commercial Industrial Weighted Average
30 Minutes

 

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

The table is interesting for two reasons:

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

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

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

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

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


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

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

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

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

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

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]

References:

[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.

CEA Tigers’ Den Workshop

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

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

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