Category Archives: Policies and Regulatory

Wind and Solar PV Are Becoming a Chinese Story

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

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

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

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

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

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

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

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

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


[i]        See and, accessed on 20180116.

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

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

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

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

[vi], accessed 20180118.

[vii], accessed 20180118.

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]


[i]         As reported by UtilityDIVE,, accessed 20180102.

[ii]        See, retrieved 20171229.

[iii]        See, retrieved 20171230.

[iv]       see, 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, retrieved 20171230.

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

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

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

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

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

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

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

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

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

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

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

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

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

Impact of Regulatory Regimes on Executive Behavior

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

Problem Statement for Executives of Investor-Owned Utilities 

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

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

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

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

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

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

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

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

Problem Statement for Executives of Customer-Owned Utilities 

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

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

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.


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.


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.