Author Archives: Benoit Marcoux

About Benoit Marcoux

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

Utilities Should Lead the Change

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

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

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

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

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

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

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

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

References:

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

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

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

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

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

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

Power to (from) the People

With low-cost renewables, many customers become power producers, and it will transform the relationship of utilities with them.

You saw that in media and telecom. My grandchildren loves to watch amateur baby video on YouTube. This one has been viewed 178 million times.

Every time, there is an ad and the daddy or mommy who produced the video gets a bit of money. Overall, videos that people put on YouTube generate $15 billion a year in advertising revenue.

In the electric utility industry, low cost solar means that many customers will generate power, with or without incentives or net metering. It will just make sense. They may just take the free electrons when they can, and wasting them if they can’t neither use nor sell them.

And by the way, we have cut down on our cable TV subscription. Customer-owned generation will have a similar effect on utilities. Many will have solar panels and they will buy less from utilities.

In essence, for the first time, utilities will see competition from their own customers.

An “iPhone Moment” for Electric Utilities in 2018?

In 1977, I worked as an electric meter reader, before going to university to earn my Electrical Engineering degrees at Polytechnique Montréal. In 2012, I was directing the largest smart meter deployment in Canada, replacing some of the same meters that I had read three and a half decades earlier. In between, I worked for 20 years in telecoms, living the Internet and wireless revolutions, and then mostly with electric utilities for the last 15 years.

As this year gets to a close, I would like to reflect on the changes that technology has brought – or could bring – to utilities and what it may mean for the future.

In 1987, telephone and electric utilities were both in the wire business – perhaps 20 AWG for telephone and 4/0 for electric, but mostly copper hanging on wood poles and serviced by a fleet of bucket trucks. Telecom companies were then telephone companies, just experimenting with wireless (the first cellular call in Canada had occurred just 2 years earlier) and the Internet was still primarily a military research technology (commercial service only started in 1989). Phone and electric utilities were highly regarded companies, imbued with a duty for public service and providing lifelong employment to their loyal employees.

By 1997, I owned a cell phone and I was running what was then the largest Internet telephony network (but tiny in comparison to today), competing with international telephone carriers. However, phone companies were in denial on the Internet, seeing us as a temporary nuisance, and trying to control user experience on cellular phones, like they had been doing for a century with rotary phones on landlines.

In 2007 the iPhone was launched. Not only did it merged the Internet and wireless phone, but it profoundly changed the business of the telecom companies. Before the iPhone, the wireless carriers were subsidizing cheap handsets to get customers to lock in for 3-year contracts and using the carrier’s proprietary and closed services. But the iPhone upsets that balance of power. Apple kept control on the user interface, given choice to consumers to buy the best apps from developers. However, by fostering more innovation, the carriers’ networks got more (not less) valuable through this change. People spent – or wasted – more time on their smart phones, generating more revenue for carriers and hardware manufacturers as network capacity expanded through successive generations of technology.

In the meantime, not that much has changed in the electricity business – my father, who worked as a dispatcher at Hydro-Québec until the 1970s, would probably recognize the network today, although he would certainly envy dispatchers using electronic maps rather than the paper ones he used.

However, 2017 has seen the rise of inexpensive solar energy and energy storage. Could 2018 have an “iPhone moment” for electric utilities? After all, the Internet brought us on-demand access to information, like energy storage is bringing us on-demand power. Wireless phones allowed us to cut the cord, and so may be distributed solar energy, at least to some extent. The parallel is striking.

Now who will be the next Steve Jobs? Elon Musk, perhaps?

All my best wishes for 2018!

Strained Customer Relationships in the Future of Electric Utilities?

Low-cost renewable energy and energy storage are reshaping the Canadian electricity industry (see http://benoit.marcoux.ca/blog/canadas-electricity-industry-in-2030/). Along the way, new regulatory frameworks, energy choice, and competition from new energy service providers will transform the relationships between utilities and their customers. If what happened in other industries that went through similar transformations is any indication, such as airlines and telecoms, those relationships could be strained. Utilities should learn and apply lessons from those industries, hopefully not making the same mistakes again.

Twenty years ago, an Angus-Reid survey put Bell Canada #2 among most admired corporations in Canada. In 2017, Bell Canada ranked #291 in a University of Victoria brand trust survey. People love their Apple or Samsung phones, are addicted to Facebook to stay in touch with friends, and use Microsoft Skype to see remote family members, but they mostly hate their phone company.

The transformation of the telephone industry in Canada really started in the 1980s with businesses being able to lease high-capacity dedicated lines from other providers, such as CNCP Communications. Businesses were clamoring for more, and the Canadian regulator, the CRTC, allowed resale of telephone companies services, first dedicated lines and then local phone services. Canadian long-distance market developed slowly until 1992, when Canada unbundled local and long-distance telephone services and allowing competitor entry into long-distance services. When cellular service became more popular around the year 2000, it also offered an alternative to local services. However, if competition in residential long-distance services is seen as a milestone, the fact is that it all started with businesses leasing high-capacity lines from competitive providers — businesses were already resenting being coerced by phone companies. Later, when residential customers got choice, they too got dissatisfied.

It is still early, but we may be seeing the same unfortunate trend with electric utilities. When listening to renewable energy developers or commercial businesses, you already hear an undercurrent of dissatisfaction, although the reality is that there is not much they can do. With low-cost renewable energy, energy storage and microgrids, businesses will start to see alternatives. Eventually, the same will happen with residential customers. Unbundling of the wire business from energy retail will bring more choices. You can readily see a parallel with telecoms .

This is a very real risk for utilities: in 2030, there will be many more potential friction points between utilities and customers than there are now. In addition to traditional transactions such as new connects, outage reporting, energy efficiency and bill payment, there will be multiple demand response schemes, EV charging and energy sales, bringing new expectations along. Even if customer satisfaction surveys are good now, they may not stay that way.

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

  • Lead the change. Customers want solar panels on their roofs and go off-grid? Make it easy for them! Green Mountain Power (VT) does it. Regulation will be performance-based? Propose it now! ENMAX (AB) did it. Customers want behind the meter energy storage? Install it for them! PG&E does it.
  • Show what you do. The electricity business is complex and not appreciated well enough. For instance, grid upgrades should be media events — see this FPL (FL) video, “crews will be installing automated switches”: https://youtu.be/cs-lMREscpY. The electricity business is highly technical and sometimes dangerous — it deserves more attention in plain words.
  • Understand changing customer expectations. With increasing dependence on reliable power for our vehicles and electronic devices, plus distributed generation earning revenue for customers, outage frequency will become a more and more important factor for customer satisfaction.
  • Partner with community leaders. Mayors and other community leaders, acting locally on a short feedback loop from their constituents, view the challenges of clean energy and climate change on a daily basis — it is about their people getting sick, having clean water, being warm or cool, holding productive jobs, commuting efficiently, and surviving disasters. Yet, few electric utilities work with cities on resiliency and sustainability challenges.

Even with all the talk from consultants about customers wanting more participation, the fact is that electricity will never have the emotional content of communicating with friends and family, would it be telephone or Facebook. This only makes it harder to ensure that electric utilities can maintain healthy customer relationship. Still, it can be done.

Are you up to the challenge?

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

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

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

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

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

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

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

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

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

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

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

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

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

Canada’s Electricity Industry in 2030

The cost of solar and wind energy and energy storage have been coming down at double-digit rate per year for many years. Every year. Double-digit percentages. Again. It continues. Tirelessly. No end in sight. Capitalism and innovation at their best. No government regulation nor corporate ego will stop it. And it will reshape – no, it is reshaping – the power industry in Canada.

By 2030, renewables will be so inexpensive that they will have upended the traditional economics of the industry. But we can see this transformation to its logical conclusions, based on how the power industry is evolving elsewhere in the world and how other industries went through similar transformations.

If ever lower-cost renewables and energy storage triggered the reshaping of the electricity industry, other factors tint how industry stakeholders: the impacts of climate change, our increased dependence on reliable electricity, and the higher cybersecurity threats. Each of these factors helps define how utilities, customers, regulators, policy makers and product and service vendors react to or take advantage of the situation, sometimes trying to accelerate change, sometimes attempting to slow down. However, if broad conclusions can be drawn, we need to be mindful that local specificities in resource availability, cost structure and ownership will mean that the end game will not exactly be the same everywhere.

Wind, solar and storage are not only becoming increasingly cost effective, but doing so at a much smaller size than traditional generation. By 2030, customers will be installing solar panels on their side of the electricity meter, on rooftops and backyard, even in absence of incentives or net metering, taking whatever “free electrons” they can and wasting what they will not be able to use or sell. If wasting electricity seems heresy, think about the iPhone in your pocket: it has more computing power than a supercomputer of a generation ago, and yet it is idling most of the time, its vast computing power wasted. Yet, the iPhone has transformed our daily relationship to computing. Similarly, inexpensive renewables and storage will transform our relationship to electricity.

Even with this abundance of distributed generation, grid defection will be the exception, as customers keep the utility connection as a last resort and because space constraints and the low energy intensity of solar and energy storage make it impractical to generate all the energy needed in urban areas. Nevertheless, abundance will cause energy (kWh) price to plummet, especially since electricity consumption has plateaued in Canada, taking traditional utility revenue along.

Commercial and industrial customers, as well as some residential customers, will take this a step further by having energy storage as well. By adding storage, customers can arbitrage time-of-day rates or peak demand charges, shifting consumption at other times to reduce costs. Having local generation and storage also turns a customer site into a microgrid able to maintain power during grid disturbance or outage, maintaining production for businesses and food stuff cold for consumers. Some smart communities and campuses will also become microgrids regrouping multiple customers and utility-scale resources for better resiliency and efficiency.

Given how low-cost renewables and storage are advancing, by 2030, if not before, the traditional, centralized grid will have been transformed into a digital grid of microgrids integrated to distributed renewable energy resources. This will have repercussions across the industry, transforming competition, energy markets, regulation, grid architecture and utility operations.

Retail Unbundling and Competition

Having so much customer-owned distributed generation will put pressure on policy makers and regulators to allow retail competition, so that distributed generators may sell surpluses on open markets. With retail competition, customers have more choices in what energy they use, what energy they sell, and how they use it, including sophisticated demand response programs to support energy balancing on the grid.

The retail arm of utilities and the wire business will be unbundled (as it is already the case in Alberta), allowing energy service providers to compete in energy retail, perhaps along with utilities’ unregulated subsidiaries. This will also expose the capacity-driven cost of the distribution grid, now charged separately. This is similar to long-distance telephone service unbundling in the 1990s. With competition forcing energy market players to keep price low, energy price regulation will be lightened, just like telephone regulations are much lighter now than they were 25 years ago.

Renewed Energy Markets

Today’s energy markets were not designed for the large number of players distributed across the grid with varying capabilities that we will have in 2030. Energy markets will evolve to improve the way electricity is priced, scheduled and procured in order to ensure reliability, transparency, efficiency and at the lowest cost. Through the energy market, distributed energy storage systems will accumulate electricity when the sun is shining or the wind blowing, releasing it at time of use. Demand management will shape the load curve to better match availability of inexpensive renewable resources. Electric vehicles will be charged during the day, and give power back to the grid if needed.

New transactional technologies, such as blockchain, may be required to deal with the sheer volume of automated transactions. Market intermediaries to act on behalf of distributed asset owners, simplifying the process and offering financing.

Performance-Based Regulation

In the traditional Canadian rate-of-return regulatory framework, electric utilities earn a return on investments based on the depreciated cost of past capital expenditures approved by the regulator. This model will no longer be suitable in 2030 to regulate the wire business of utilities because of its “capital bias”, its insensitivity toward grid reliability, its inhibition of innovation, and its short-termism. The regulatory regime will evolve to incentivize lower total costs (including incentives to use non-wire alternatives such as third-party energy storage) and better reliability (to avoid momentary service interruptions that trip distributed generators offline), with utilities freed to implement innovative solutions without regulators and interveners second-guessing investment in technology. Multi-year incentive plans will allow utilities to plan ahead better. Similar approaches already exist, as in Great Britain, where the regulator developed its RIIO (Revenue = Incentives + Innovation + Outputs) 8-year model.

High-Availability Distribution Grid?

By 2030, we will obviously not have replaced all poles, conduits and wires that make up the legacy grid – nor should we try to. Utilities, however, will have transformed this critical infrastructure to make it resilient (especially against the impacts of climate change) and reliable (to keep now-essential distributed energy resources online).

We will more storm-proofing of critical feeders, including undergrounding of mainlines, with intelligent protection devices on laterals, near customers and distributed energy resources to minimize disturbance while faults are being cleared on overhead lines. Protection devices, switches and sensors will be automated to the best extent possible and remotely operated, from a control room or from a truck, freeing operators and crew to better manage and repair outages. Remote control will allow protection settings to be more sensitive to limit the risk of forest fires caused by the electrical grid.

New Operating Model in Distribution

In a technology-intensive environment in constant innovation and with ever-increasing cybersecurity threats, utilities will develop new skills and will learn to leverage partnerships with vendors. This is very different than traditional distribution grid operation, still largely relying on physical work and manual switching.

In their new high-tech and fast-changing environment, utilities will implement new business process and organizational structures to take advantage of the latest technology innovations. At the same, new skills technology skills are required, including cybersecurity. Rather than doing things internally, as they are often used to, utilities will partner with technology vendors that have the scale and the expertise to provide better products and professional services at a lower cost. Essentially, utilities will follow the path already taken by telecom network operators.

New business models in the industry

New businesses will cater to energy customers, distributed generators and microgrid owners, removing complexity and turning energy into services.

Energy customers, distributed generators, and microgrid owners will be supported by an ecosystem of third-party vendors and unregulated utility subsidiaries. Vendors will support customers with low-cost financing and technology to optimize the use of distributed assets on energy markets, lowering costs. For utilities, this is a clear growth opportunity, not limited to traditional territories. With transportation electrification, the electric industry will essentially replace the petroleum industry, with new businesses supporting public charging of electric vehicles – a welcome development as it could prevent further reduction in electricity consumption.

Conclusion

This new, distributed and digital-enabled electrical grid will be more resilient and sustainable. Its resiliency is based on multiple and alternate energy local sources and paths, with reduced reliance on large infrastructure. This new resilience is welcomed given the growing importance of electricity in energy use, as residential and industrial customers are dependent on electricity to power our modern life in smart communities and with the advent of electrical transportation. The new grid will also be more sustainable, reducing the environmental impact of communities and improving quality of life – while being financially affordable.

Preparing for the future is essential for Canadian electric utilities and new players. In an industry traditionally defined by centralized generation and rigid geographic boundaries between utilities, new linkages need to occur: utilities and customers, vendors and entrepreneurs, cities and businesses, ensuring that all see the opportunities that didn’t exist before and have the support they need to get their ideas to market quickly. The structure of the industry will emerge transformed, with Canadian-owned service providers offering novel energy solutions in Canada, backed by a web of hardware, software, and professional service vendors. Realizing this vision will increase opportunities for Canadians to export their energy, their expertise, and the fruit of their labor.

AIEQ Conference on Smart Grid

Today, I moderated a panel on microgrids at a smart grid conference hosted by the electric industry association of Québec (AIEQ). I think that it went quite well. Chad Abbey (Smarter Grid Solutions), Michel Carreau (Hatch), Teddy Chettiar (S&C) and Ronald Denom (Ossiaco) were on the panel. Chad presented 3 microgrid cases, including one on the Shetlands Isles off Great Britain – an obviously remote community. Michel continued by presenting the challenges of microgrids (and the recent progress) in the Canadian North. Further South, Teddy both in-front and behind-the-meter examples, including one in North Bay. Ron focused on behind-the-meter applications, with the “nano grid” concept.

Other panels focused on the smart grid proper, with Greg Farthing (ABB) moderating Gary Rackliffe (ABB), Jayant Kumar (GE) and Mark Feasel (Schneider), and on cybersecurity, with Oral Gürel (Schneider), moderating and Dominique Gagnon (CGI) , Robert Nastas (PM SCADA), Bruno Lafeytaud (Accenture) and Pierre Taillefer (Vizimax) presenting.

The panels were followed by a dynamic luncheon presentation by Eric Filion, VP Customer Service at Hydro-Québec Distribution. Éric highlighted the goal of Hydro-Québec to become more of a lifestyle service provider and increase customer loyalty (going well beyond customer satisfaction). Éric presented 5 innovation trends (see picture) which, I think, are worth sharing.

Thanks to all panelists and to the AIEQ for organizing this very successful event.

Strategic Electricity Inter-ties Committee of the House of Commons

On October 25, I appeared before the Standing Committee on Natural Resources discussing Strategic Electricity Inter-ties. The Standing Committee on Natural Resources studies bills, government activities and expenditures, and issues related to Canada’s energy, forest, minerals and metals, and earth sciences sectors.

The idea behind strategic electricity inter-ties is to improve power exchanges between provinces by increasing tie capacity with new transmission lines. The brief that I wrote  and my testimony argued that that energy storage may be a better alternative in light of the long time frame to build new transmission lines (15-20 years is typical), the current state of the art in storage, and expected growth in performance and cost decline of the technology.

It was my first experience of appearing before such a committee, and I like the experience. I was impressed by the questions that the members of parliament asked. They also seemed to like my arguments, as many came to me afterward to thank me.

Here is the brief that was presented: S&C Brief Standing Committee RNNR 20171024.

Telecom as a Model, not a Service, to Electric Utilities

On September 27, 2017, I presented at the Utilities Technology Council of Canada. I have attached the presentation, and here is the abstract.

Abstract: The telecom industry has seen tremendous changes, replacing in just a few short years the Plain Old Telephone System that took over a century to build with the Internet and cellular networks. Since telecom and electric utilities have a lot in common, like linear assets, large customer base and territory, and technology-driven culture, what can we learn from the transformation of telecom to better manage the ongoing technological changes in electric utilities?

A pillar of the Canadian economy is undergoing a profound transformation

Now is a time of innovation in the electric industry, like no other since Thomas Edison.

Now is the time when wealth can be created as we use our resources and our brains to ensure a resilient and sustainable energy future for all.

Potential wealth creation stems from the fundamental changes occurring in the electricity sector:

  • Globally, electricity and heat production are the largest contributors to greenhouse gas (GHG) emissions. Canada is blessed with abundant carbon-free hydroelectric generation, but our energy sector as a whole is a major emitter of climate-changing GHG.
  • In response, major investments have been made across the world in designing and implementing renewable sources and energy storage, including wind and solar. The price of those sources is decreasing at double-digit rates per year and they are getting increasingly competitive with traditional sources.
  • Wind and solar generation are not only becoming cost effective, but doing so at a much smaller scale than traditional generation. Distributed generation is being installed deep in the electrical grid, at its edges or even behind the meters. The traditional and centralized grid designed by Edison is being transformed into a digital grid of microgrids integrated to local energy resources.
  • The new, distributed and digital-enabled electrical grid is more resilient because it relies on multiple and alternate energy sources and paths. The electrical grid then becomes more resilient to extreme weather events that, unfortunately, become more frequent with climate change.
  • Residential and industrial customers benefit from improved reliability as they are increasingly dependent on electricity to power our modern life in smart communities and with the advent of electrical transportation.

Innovation and wealth creation opportunities are everywhere in this context. Technical innovation is what drives the decreasing costs of renewable sources for energy users. Vendors need to invent new commercial solutions to balance the new distributed grid and ensure that customers stay powered up. Increasing energy efficiency means that we can do more with less. Utilities and entrepreneurs adopt new business models to better serve customer segments. In particular, utilities, previously defined by their geographic territories, are morphing into energy service providers, often competing with offerings from new entrants, or even competing with each other like never before, driving cost down for Canadian consumers and businesses. The digitalization of the electrical grid creates large quantities of data that new software applications can leverage to increase efficiency and create commercial opportunities. Canadian customers, now with the power of choice, can no longer be taken for granted and demand more.

What is even more dramatic is that the changes affecting the electric industry are shaking a pillar of the Canadian economy. The electric industry touches every home and business in Canada and reliable power is an essential ingredient for the competitiveness of our economy. Electric power generation, transmission and distribution utilities contribute almost $30 billion to the Canadian economy, with electrical equipment manufacturers contributing another $4 billion. This industry employs over 100,000 Canadians, but the Conference Board has estimated that 156,000 workers will be needed to carry out the renewal of Canada’s electricity infrastructure. Canada’s net exports of electricity and electrical products amount to billions of dollars every year. The Canadian electricity system is in need of massive infrastructure renewal. The Conference Board of Canada estimates that by 2030, close to $350 billion in new investment will be required just to maintain existing electricity capacity, with most of Canada’s non-hydro assets needing renewal or replacement by 2050. The importance of the electric industry scales up the potential of wealth creation, but also underlines the perils that we are facing: should the Canadian electric industry fail to renew itself for the challenges of the 21st century, the entire economy of Canada would suffer, with foreign service providers taking control and energy exports dwindling.

In conclusion, accelerating the transformation of the Canadian electric industry is essential. In an industry traditionally defined by centralized generation and rigid geographic boundaries between utilities, new linkages need to occur: utilities and customers, vendors and entrepreneurs, cities and businesses, ensuring that all see the opportunities that didn’t exist before and have the support they need to get their ideas to market quickly. The transformation of the electric industry will ensure that Canadians benefit from the billions of dollars to be invested in the electricity system. The structure of the industry will emerge transformed, with Canadian-owned service providers offering novel energy solutions, backed by a web of hardware, software, and professional service vendors. This will increase the opportunities for Canadians to export their energy, their expertise, and the fruit of their labor.

The Sun for a Penny

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

Impact of Regulatory Regimes on Executive Behavior

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

Problem Statement for Executives of Investor-Owned Utilities 

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

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

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

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

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

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

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

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

Problem Statement for Executives of Customer-Owned Utilities 

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

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

The New Grid Needs to Be a Lot More Complicated

The Old Grid used to be relatively simple, with generation following load:

Old Grid

It is now a lot more complicated:

New Grid

The grid is transforming and getting more complicated.

  • We are decommissioning fossil plants to reduce GHG emission and nuclear plants because of safety concerns.
  • There is only so many rivers, so the solution of building new hydro plants is not sufficient.
  • We are then replacing fossil and nuclear base load plants with renewables that are intermittent.
  • To compound the problem of balancing the grid, loads are also becoming peakier, with reduced load factor. Interestingly, many energy conservation initiatives actually increase power peaks.
  • To connect the new renewable generation, we then need to build more transmission. The transmission network also allows network operators to spread generation and load over more customers – geographic spread helps smooth out generation and load.
  • Building new transmission lines face local opposition and takes a decade. The only other alternatives to balance the grid are storage … and Demand Management.
  • Another issue is that we are far more dependent on the grid that we used to be. With electrical cars, an outage during the night may mean that you can’t go to work in the morning. So, we see more and more attention to resiliency, with faster distribution restoration using networked distribution feeders as well as microgrids for critical loads during sustained outages.
  • Renewable generation and storage can more effectively be distributed to the distribution network, although small scale generation and storage are much more expansive than community generation and storage.
  • With distributed generation, distributed storage and a networked distribution grid, energy flow on the distribution grid becomes two-way. This requires additional investments into the distribution grid and a new attention to electrical protection (remember the screwdriver).

All of this costs money and forces the utilities to adopt new technologies at a pace that has not been seen in a hundred years. The new technology is expensive, and renewable generation, combined with the cost of storage, increases energy costs. There is increasing attention to reduction of operating costs and optimization of assets.

“Resilient Power for Sustainable Cities” Presentation at the Canadian Electricity Association

I presented this to senior managers of Canadian utilities attending the 24 February Distribution Council of the Canadian Electricity Association. It can be found on SlideShare at http://www.slideshare.net/bmarcoux/resilient-power-for-sustainable-cities.

Abstract

The cost of disasters has been increasing exponentially since the 1970s – and cities are mostly affected, which is not surprising since cities produce 80% of the world gross domestic product (GDP). Since the majority of disasters are related to climate events, cities are also part of the root cause, since they generate 75% of our greenhouse gas (GHG) emissions. Mayors, acting locally on a short feedback loop, view the challenges they face on a daily basis – it is about their constituents getting sick, having clean water, being warm or cool, holding productive jobs, commuting efficiently, surviving disasters. They see that a smart city needs, first and foremost, to be both resilient to face increasing disasters and sustainable to reduce its environmental impact and to improve quality of life – while being financially affordable

Cities can’t function without electricity. It moves subways and trains. It cools, heats and lights our homes and businesses. It pumps our water and keeps fresh the food we eat. And it powers the technologies that are the foundation of a smart city. By implementing smart grid technologies such as microgrids and distribution automation, electric utilities play a key role in making cities both resilient and sustainable. Yet, many electric utilities do not partner with mayors to work on cities’ resiliency and sustainability challenges. A better approach is to see city policy makers as major stakeholders and a driving force in modernizing the grid.

Have you talked to your mayor(s) lately?

The Cost of Outages Is a Policy Issue

Based on my work with Canadian and Australian utilities, the cost of outages is first a policy issue – not a regulatory one, not an operation one. Arguments based on the cost of outages may resonate with policy makers, including Smart City stakeholders, because of public pressure or impact on the economy at large. However, these arguments do not resonate with regulatory agents (who follow policies) nor with utilities (who do not have customer outage costs in their financial statements. Individual users may or may not know their specific costs related to outages, but broad outage cost assessments will not affect them

While utility customers are the ones bearing the cost of outages, multiple surveys have shown that customers are not willing to pay more for more reliable power. Even in individual cases, where a utility would propose to split specific reliability improvement costs with industrial users, the customers decline even though the associated payback period was much shorter than would be required for other purchasing decisions. Essentially customers are saying to policy makers and regulators that they pay enough and that reliability is something that is just expected. Public opinion, regardless of the actual costs incurred, is a powerful tool for disgruntled customers, who can vote policy makers in or out of office. Public opinion may incite policy makers to act, requiring utilities to invest in reliability improvement

This being said, customers incur real costs when an interruption occurs, but accurately capturing these costs is elusive – the ICE calculator is the best developed attempt at estimating overall economic costs. Policy makers, stewards of the economy, can be sensitive to the economic cost argument, when reliability improvement costs are seen through the lens of an industrial policy, with may lead to subsidies to improve reliability

The regulatory agencies follow policies. Traditionally, rates that utilities charge are based on the cost of generating, transmitting and distributing. In return for their obligation to serve customers in an exclusive service territory, utilities are allowed a guaranteed rate of return on their capital expenditures. Reliability is attained tacitly through conservative engineering and maintenance activities. However, policy and regulatory changes over the last 20 years or so have put tremendous pressure on utilities to reduce their costs, and many have gone through or are still going through massive downsizing. As a direct consequence, reliability suffered for some systems. If reliability incentives or penalties are used, reliability targets are typically based on historical values, not the economic costs of outages

Utilities would like to invest more to improve reliability. These investments would add to the asset base upon which investors get a guaranteed return. However, regulators may not let utilities spend for reliability improvement because of the impact on rates unless policy requires them to

Since outage costs may resonate with policy makers, it is a worthwhile argument for Smart City initiatives. Cities cannot function without electricity. It moves subways and trains. It cools, heats and lights our homes and businesses. It pumps our water and keeps fresh the food we eat. And it powers the technologies that are the foundation of a Smart City. By implementing smart grid technologies such as microgrids and distribution automation, electric utilities play a key role in making cities both resilient and sustainable. Yet, many electric utilities do not partner with mayors to work on cities’ resiliency and sustainability challenges. Policy makers could then use outage cost arguments when working with their utilities on reliability improvement initiatives.

 

GTM Squared Report

I just finished reading the annual survey of utilities prepared by GTM Squared (http://www.greentechmedia.com/squared/read/annual-survey-report-2016-the-future-of-global-electricity-systems). I found it a useful reference to understand the challenges faced by utilities worldwide, and I thought of sharing some interesting highlights:

  • 3/4 of utilities say that regulatory hurdles are the greatest challenge they face today. Preference is to develop market-based reforms, as well as clear interconnection/net metering rules – in other words, mechanisms that deal with/assign value to Distributed Energy Resources. Note that DER (such as distributed generators and storage) will play an increasing role in utilities worldwide.
  • Half of respondents see the consumers at the forefront of the industry’s evolution. However, it is surprising that utilities in the same survey do not put a greater priority on customer engagement.
  • On storage, respondents see an increasing emphasis toward actual projects, and less on the physics and technology of storage. DER vendors now offer better systems intelligence and grid integration to companies focused on building a next-generation power grid (more sustainable and more resilient). Energy storage is now living up to the hype, having seen record installations in 2015.

Utility-Scale Solar Report

I finally got around to read the US Department of Energy report on utility-scale solar energy (https://emp.lbl.gov/sites/all/files/lbnl-1000917.pdf) published a couple of months ago. Here are my highlights:

  • Installation trend is compelling. Installed capacity is now 30,000 MW – about 30 times more than 5 years ago.
  • Installation costs are falling – by more than 50% since the 2007-2009 period, the lowest-priced projects being around $2/W (AC).
  • Capacity factor is now improved to 27.5%. The main factors of this variation are, in order of importance: the strength of the solar resource at the project site; whether the array is mounted at a fixed tilt or on a tracking mechanism; the inverter loading ratio; and the type of PV modules used.
  • Power purchase agreement prices have fallen. Utility scale solar PPA is now as low as $40/MWh. At these low levels – which appear to be robust, given the strong response to recent utility solicitations – PV compares favorably to just the fuel costs (i.e., ignoring fixed capital costs) of natural gas-fired generation, and can therefore potentially serve as a “fuel saver” alongside existing gas-fired generation (and can also provide a hedge against possible future increases in fuel prices).

Evolution of Energy Generation and Distribution in Canada’s Smart Power Grid – Innovation 360 Conference Panel

On September 29, I was asked to participate on a panel titled “Evolution of Energy Generation and Distribution in Canada’s Smart Power Grid” at the Innovation 360 conference in Gatineau, Québec (http://innovation360.ca). Here is the essence of what I contributed.

By definition, in an electricity network, energy consumption plus losses equal electricity generation. This must be true at any point in time, or protection systems will shed load or trip generators.

There are 4 ways to balance load and generation:

1) Traditionally, dispatchable generators that can easily ramp up or down were tasked to follow the load. Big hydro plants and natural gas generators are particularly good at this. However, we are running of big hydro opportunities, and natural gas are sources of greenhouse gas emission, contributing to global warming.

2) Another way to balance load and generation is to interconnect with neighboring network that may not have the same load profile. Today, all of North America is interconnected in some way. However, building transmission lines is a lengthy process that typically faces major local opposition. As a result, most transmission lines run at capacity during peaks, weakening the bulk transmission system as the Northeast blackout of 2003 demonstrated.

3) In the last couple of decades, we have started to control load, like turning off air conditioning units by pager or getting large industrial like smelters to go offline for a couple of hours during a major peak. Time-of-use or market pricing are also attempts to have loads better follow available generation capacity. However, much of the conservation focus thus far has been on energy efficiency, not peak load reduction.

4) Very recently, energy storage has been getting attention. Traditionally, the only utility-scale storage technology available was pump-storage, like the Sir Adam Beck plant in Niagara, but few of those plants are possible, and they are not efficient. Going forward, batteries, either utility-scale or distributed storage, will grow, although for now utility-scale batteries are MW-class, when hundreds of MW or GW are needed.

Balancing load and generation is also becoming more and more difficult. On one hand, consumption is getting peakier, partly due to side effects of some energy saving programs, like turning down thermostats at night in the winter, and then turning them back up in early morning, just in time for the morning peak. On the other hand, wind and solar generators are replacing fossil generators, adding unpredictability to generation and taking away controllability, thus requiring even more balancing resources.

Integrating renewable into the grid is not only causing balancing problems. It also creates voltage management and protection problems. Those are solvable, but significant, engineering problems that require expensive upgrades to the electricity grid.

Ultimately, load and generation balancing, voltage management and grid protection adds costs that are ultimately born by subscribers. It therefore quickly becomes a political issue.

As a society, we have been subsidizing fossil fuels. Clearly, going forward, we will need to greatly invest in the grid if we want to limit the predicaments of global warming for our children and grand-children.

Using Analytics to Assess Station Thermal Risks Caused by Reverse Power Flow

With sufficient Distributed Generation (DG – embedded generation in Europe) installed on the feeders of a substation, reverse power flow may occur at the station when load is low. This is especially the case when large generators (such as wind farms) are connected on express feeders dedicated to their use.

Substations have been designed, rated and operated as step-down substation with power flowing from higher system voltage to lower system voltage. Some substation transformers also have dual secondary winding transformers that do not allow for reverse power flow conditions, as unequal reverse flow in the two secondary windings would cause overheating and potential failure of the transformer.

Utilities limit DG capacity downstream of a station to avoid excessive reverse-flow and to prevent overheating of substation transformers. For example, Hydro One requires that generation shall not exceed 60% of the maximum MVA rating of a single transformer plus minimum station load.

The (worst-case) engineering assumption is that maximum generation coincides with lowest load at a station. Is it the case? Some years ago, I ran a Monte-Carlo simulation between load and wind generation, based on theoretical distribution of both, but doubling the generation normally allowed. It found that generation would be excessive… less than 2% of the time (and not by much, and at a time when load is low and so are prices). Using actual smart meter data, it is now possible to actually know what is going on and better assess risks. For solar generation in hot climates, there is a negative correlation between load and generation – in other words, maximum generation does not happen in times of minimum load.

Even better: correlating with forecast weather data can assess whether reverse flow could be excessive in a few hours, and require large DGs to go off-line ahead of a problem (and this would not happen frequently). While I have not seen such an application, it is clearly in the realm of possibilities.

Deep analytics, used as a planning tool or in support of operations, enables safe integration of more distributed integration by managing thermal limit of station transformers operating in reverse flow.

Tutorial: Key Players in the Energy Markets: Rivalry in the Middle

The players described in the previous post have vastly different characteristics. The most striking difference is the level of rivalry.

IMG_2174

Distributors operate in a defined territory, often corresponding to a city, a state or a province, where they are the sole provider – thankfully, as there would otherwise be multiple lines of poles along roads. Given this monopoly, distributors are subjected to price regulation, meaning that the price they charge for the use of their infrastructure (poles, conductors, cables, transformers, switches, etc.) is set, typically equal to their costs plus an allowed return on their investment. This is done by filing tariffs that are approved by the regulatory body following a rate hearing.

Retail is often a competitive industry, as there is no structural barrier to having multiple players. However, some distributors are also given the retail monopoly over their territory. Some may also provide retail services in competition with other retailers. In those cases, the distributor-owned retailer is also regulated and has to seek approval of its rates, but other retailers typically do not, although they may have to file their rate plans.

It is possible to have multiple transmission companies operating in the same territory, each owing one or a few transmission lines. However, because those transmission lines are not perfect substitutes (they do not necessarily have the same end-points in the network) and because transmission capacity is scarce, electricity transmitter typically have regulated rates, although they may compete for new constructions.

System operators are monopolies over a territory, and they have to maintain independence. They are, in effect, monopolies, although system operators are often government- or industry-owned. Their costs are recharged to the customer base, directly or indirectly.

Large generators are in a competitive business, competing in an open market, although distributed generators, which are much smaller, usually benefits from rates set by a regulator or a government.