Blackout in New York City in 1965

A new report by the Institute for Energy Economics and Financial Analysis (IEEFA) shows that major power systems are able to cope quite well with increasing shares of intermittent renewables, if the right measures are taken. The study says that increased generation of these renewables does not make the grid less reliable or compromise security of supply.

Critics of renewable energy have often warned that there are strict limits to the amount of intermittent power that the grid can handle. The U.S. government last year even commissioned a study to find out whether the stability of the grid is being threatened by the increase in renewables. (The conclusion was that it did not.)

Yet so far, despite strong growth of solar and wind, no limits appear to be on the horizon. The expansion of renewables does present challenges and require measures, but with the right measures, systems are able to cope quite well. So says a new report, “Power-Industry Transition, Here and Now,”  from the Institute for Energy Economics and Financial Analysis (IEEFA), a U.S.-based private institute whose mission it is “to accelerate the transition to a diverse, sustainable and profitable energy economy.”

The IEEFA researchers looked at nine countries and regions which last year had shares of renewables ranging from 14.3% to 52.8%, while the global average was 5.2%:

• Denmark (52.8%)
• South Australia (48.4%)
• Uruguay (32.2%)
• Germany (26%)
• Ireland (24.6%)
• Spain (23.2%)
• Texas (18%)
• California (15%)
• the state of Tamil Nadu, India (14.3%)

The level of liberalization in these markets varies: they include liberalized, energy-only markets, markets with some state intervention, and markets with full state regulation.

Reliable grids

To measure the reliability of the grid, the researchers looked at power outages as one indicator. They found no obvious link between wind and solar market share and longer outages. They did find a correlation between income per capita and duration of outages.

Investment in high-voltage transmission systems turns out to be one of the most critical steps to prepare for higher levels of variable renewables.

However, higher-income nations with average power outages of more than one hour, such as Sweden, the United States, Australia or Norway, have a lower market share of variable renewables, they note.

The study outlines various methods for countries to integrate a higher share of wind and solar power into their systems. There is no general rule as to which of the options to follow; countries should adopt and adjust these measures according to their specific needs. The report did not look into the cost of these measures.

Investment in high-voltage transmission systems turns out to be one of the most critical steps to prepare for higher levels of variable renewables, according to the researchers. Building transmission systems helps avoid curtailment, which can increase the cost of renewables generation.

Improving interconnections and cooperation with neighboring countries can help to balance and integrate larger shares of variable renewables.

For example, Texas managed to drastically reduce curtailment by expanding its transmission network. To connect the western part of the state, where most of the wind power is generated, with load centers in the eastern part, the state built 3,600 miles of new transmission lines between 2005 and 2014 at a cost of $6.8 billion. Although curtailment decreased significantly, the state still needs to build more connections as wind power capacities continue to rise.

Backup technologies

Improving interconnections and cooperation with neighboring countries can also help to balance and integrate larger shares of variable renewables, the report says. For example, despite having the highest wind power market share in the world, Denmark has the lowest wind power curtailment among the studied markets. This, in large part, is the result of its strong interconnection with countries such as Sweden, Norway and Germany.

The country’s interconnection capacity today accounts for more than half of domestic generation (51%), which may rise to 59% by 2020. As a result, Denmark can import or export power, taking into account its wind generation, and so balance the grid.  The country continues to expand the number of its interconnectors – a new 1.4 GW capacity submarine cable, able to transport the annual electricity consumption of approximately 2.7 million households – will be built between the UK and Denmark. The cable is expected to be operational by the end of 2022.

Obtaining accurate forecasts for wind and solar generation also helps grid operators to manage the system.

To balance the variability of wind and solar power, backup technologies are needed that can quickly ramp up or down, notes the report. Examples are gas-power stations, hydropower and power-to-heat. In Uruguay, where wind generation has grown more than 30-fold in the past five years, hydropower is used to balance power generation. The country also relies on its interconnectors with Brazil and Argentina when wind power is in surplus. Denmark and Germany redesigned their existing coal plants which are now able to start more quickly and run more flexibly.

Obtaining accurate forecasts for wind and solar generation also helps grid operators to manage the system. Spain has upgraded its national forecasting system, Sipreolico, which provides hourly wind production forecasts for up to 10 days ahead. As a result, it has managed to reduce its 24-hour prediction error, from 18% to 9% between 2008 and 2015.

So how far can the renewable energy share grow in the end?

The study did not seek to answer that question, says Gerard Wynn, a London-based IEEFA energy finance consultant and lead author of the report. It focused on real-world case studies – what countries are actually doing.

“The whole point was to cut through the academic debate about limits of possibility. What we show is that two countries/markets – South Australia and Denmark – have already achieved 50% share of variable renewables. That is 10 times the global average of 5.2%, which shows that most countries can grow their variable renewables a great deal without worrying about limits.”

Jeremy Corbyn presents new economics (or is it old economics?)

Labour Leader Jeremy Corbyn has called for the nationalisation of the UK energy industry in order to deliver the transition to a low-carbon economy. That may sound radical and ambitious, writes Karel Beckman, editor-in-chief of Energy Post, but it is not a solution at all. According to Beckman, the Labour Leader is shirking the responsibility to come up with realistic and effective climate change policies.

Jeremy Corbyn, leader of the UK Labour Party, laid out his vision for the energy sector in a speech he held on 10 February to the Alternative Models of Ownership Conference.

The speech is worth a closer look. Variations on this debate are taking place in many countries, although few will want to go as far as Corbyn is proposing.

Corbyn has two general points to make. First of all, he argues that the privatisation of the energy sector in the UK has been a failure.

He says: “It cannot be right, economically effective, or socially just that profits extracted from vital public services are used to line the pockets of shareholders when they could and should be reinvested in those services or used to reduce consumer bills. We know that those services will be better run when they are directly accountable to the public in the hands of the workforce responsible for their front line delivery and of the people who use and rely on them.  It is those people not share price speculators who are the real experts.”

“Energy independence for some will mean rising bills and unreliable energy for the rest”

According to Corbyn, in many countries privatisations are being reversed, though he mentions no examples from the energy sector. “There are very good reasons for what’s taking place”, he notes. “The neoliberal ideology that drove the privatisation frenzy forgot a key lesson that’s understood even by conventional neoclassical economics; that where there are natural monopolies, markets fail.”

“The architect of Thatcherite privatisation, Professor Stephen Littlechild thought regulators could mimic market competition but he was wrong. The regulators have proved too weak, [too] close to the companies they’re supposed to be regulating and too prone to corporate capture…”

Corbyn says that “Without genuine competition or public accountability private ownership of key utilities has meant customers at the mercy of rip-off price fixing. The case for public ownership is so clear and so popular and we’ve demonstrated how it’s an investment with no net cost for the taxpayer.”

“… We’ve all seen how the big energy companies jack up prices too knowing full well most people don’t switch suppliers.”

“And the energy grids are even worse, overcharging customers by £7.5bn over the last 8 years, according to Citizens Advice.”

Greatest market failure

The second point he makes is that nationalisation is necessary to be able to tackle climate change: “We need to take back control of our energy system because, as [the economist] Nicholas Stern described, ‘the greatest market failure the world has seen’ is climate change.”

According to Corbyn, “the challenge of climate change requires us to radically shift the way we organise our economy.” Why? Because “A green energy system will look radically different to the one we have today. The past is a centralised system with a few large plants. The future is decentralised, flexible and diverse with new sources of energy large and small, from tidal to solar.”

He notes that “Transforming the grid will require investment and planning on a scale that is simply not happening under the current system. Price cap regulation encourages private grid operators to cut costs and pay money out in dividends, not to plan how the grid will need to work in 25 years’ time, or to make the necessary long-term investments we need to get there.”

“Our energy system needs to change but it cannot be workers and local communities who pay the price”

“Grid operators are notorious for overcharging and causing delays in connecting renewables because they have no incentive to make it easy for clean, community generators to connect to the grid, or to encourage community grid initiatives that might end up undermining their profits… With the national grid in public hands we can put tackling climate change at the heart of our energy system, committing to renewable generation from tidal to onshore wind.”

His vision is one of “Investing to connect renewable energy to the grid, giving impetus to the kind of research and innovation that will make our grids smarter, more flexible, and capable of genuine optimisation. And actively devolving power to local communities, by giving community energy practical support and encouragement.”

Does this mean he approves of the “prosumer” model? Apparently not. “There are some who hanker after a Thatcherite so-called ‘prosumer’ model where people produce and consume their own energy and whole communities opt out of the grid”, says Corbyn. “But not everyone has the resources – natural or financial – to go it alone. Energy independence for some will mean rising bills and unreliable energy for the rest. We need a publicly-owned grid to act as the great leveller, distributing energy from where it is plentiful to where it is scarce and guaranteeing that everyone has access to clean, affordable energy  all of the time. Anything else is not only unjust, it risks doing immeasurable harm to the climate cause.”

The Labour Leader stresses that “our energy system needs to change but it cannot be workers and local communities who pay the price. The devastation wreaked when our coal mines were closed, leaving a legacy of decline that former mining communities are still living with, is a brutal reminder of what can happen when those communities are silenced and disregarded in the process of change. Never again. In public hands, under democratic control, workforces and their unions will be the managers of this change, not its casualties.”

He concludes his speech by calling for the creation of “an energy system that doesn’t jeopardise the future of our planet, a joined up transport system that helps us, rather than hinders us, from moving away from reliance on fossil fuels … A society which puts an end to wasteful leakage and environmental degradation, which puts its most valuable resources, the creations of our collective endeavour, in the hands of everyone who is part of that society. Extending the principle of universalism, right across our basic services. Free at the point of use to all who use them. That’s real, everyday, practical socialism. And we’re going to build it together.”

Mimic competition

I believe both points Corbyn makes are questionable. Even more importantly perhaps, it is not clear at all what he means exactly when he speaks of “taking our public services back into public hands”.

With regard to the “failure of privatisation”, according to Corbyn, public ownership of utilities is both more efficient and fairer. But there are of course countless examples of utilities ineptly managed by bureaucrats and politicians, and as often as not to their own advantage rather than “in the public interest”.

Far from being “directly accountable” to the public, as Corbyn claims, publicly owned entities are monopolies that offer the public no alternatives. Do we want the energy sector to be run like the National Health Service?

Market players on the other hand surely are, contrary to what Corbyn claims, “directly accountable” to the public. That is to say, if markets are genuinely competitive. Ask Kodak.

Customers in the Netherlands do switch suppliers. Just a few weeks ago I got a €200 bonus when I switched my supplier

The problem with many privatisations is not the private ownership that goes with them, but the fact that the privatised entities retain monopolies and no real competition takes place. Corbyn may well be right to argue that regulators cannot “mimic market competition”, but that’s not an argument against genuine markets or in favour of nationalisation.

In this context, it should be noted that in most EU countries the electricity grids are regarded as natural monopolies and are publicly owned. In my own country, The Netherlands, the grids are owned by state-owned entities. The rest of the energy market is liberalised.

Contrary to what Corbyn claims, this has led to a much more efficient market than the state-controlled set-up of the past. Customers in the Netherlands do switch suppliers. Just a few weeks ago I got a €200 bonus when I switched my supplier. Electricity prices in the Netherlands have gone down by 13% over the last ten years.

Overall, electricity prices in European countries have risen considerably in recent years, but these increases are mostly caused by higher taxes and levies – i.e. by the State, not the market. If energy poverty is on the rise, as it is said to be, is it because so much of the energy market is still controlled by state institutions?

No net cost

Corbyn’s second point, that we need public ownership of the energy sector to combat climate change, is at least as questionable.

The problem is that it is not at all clear what Corbyn means by public ownership. What assets and activities are supposed to be publicly owned or controlled? The grid, yes. There is not much gained by private ownership of the grid as long as the system is controlled by the regulator. The fact that, apparently, in the UK investments in the grid are lacking is the result, as Corbyn acknowledges, of “price cap regulation”. This is not a real market.

But what about the rest of the energy sector? Offshore wind farms? Solar farms? Production of electric vehicles? EV charging networks? Grid-scale batteries? Are they all supposed to be nationalised? Corbyn manages to avoid this crucial question.

When Corbyn says, “We need a publicly-owned grid to act as the great leveller, distributing energy from where it is plentiful to where it is scarce”, whose energy is he talking about?

Will Tesla not be welcome anymore in the UK?

Will there be no room anymore for commercial companies supplying solar PV panels? Will Shell not be allowed to build EV chargers? Will Statoil be banned from building offshore wind farms? Will Tesla not be welcome anymore in the UK?

If all energy production is to be controlled by “energy communities”, as Corbyn seems to imply, then who will control the energy communities?

If you doubt that Corbyn wants to go that far, note that he says that “basic services” should be “free at the point of use to all who use them”. Tesla and Shell will not deliver free energy. Only the State can do that – although I doubt that it can be done at “no net cost for the taxpayer”.

Yet in the end nowhere in his speech does Corbyn specify the extent of the “democratic control” he is envisioning. It is left purposefully vague.

Policy failure

Let’s assume the entire energy sector is brought under “public control”, would that necessarily result in more renewable energy and lower greenhouse gas emissions, at lower cost?

There is no reason to think so. “Public control”, i.e. direction by the State, can work in different directions after all, depending on who is in charge of the State. Ironically, when Corbyn says that, “The past is a centralised system with a few large plants”, he forgets to mention that this centralised system was a creature of the State. As was the coal mining industry. He also forgets that the renewable energy sector is a hotbed of private entrepreneurship.

Nor is there any reason to believe that, even if the direction of his state-controlled system is towards lower greenhouse gas emissions, the means chosen will be efficient, or the solutions innovative. Corbyn is in effect arguing that to supply everyone with decent food, the best way is to nationalise the supermarkets. Would that be a good idea?

It is clear why policymakers are afraid to take effective measures: because they are afraid these will be unpopular with voters

True, the private sector will not “automatically” deliver lower greenhouse gas emissions. But to call this a “market failure” does not make sense.

The release of greenhouse gas emissions is an unfortunate by-product of the use of fossil fuels. It is a form of pollution in the sense that it affects the environment we all live in. This cannot be controlled by any individual producer or user of fossil fuels. It requires society, governments, to step in and take measures to limit or stop. It does not require nationalisation of economic activities, but effective rules and regulations. For example, a carbon tax. Or strict emission limits.

These are exactly the measures policymakers are failing to take, if we consider that the Paris Climate Agreement is merely a non-binding and still inadequate commitment.

This is policy failure, not market failure.

And, if we look at the UK and other western countries for a moment, it is clear why policymakers are afraid to take effective measures: because they are afraid these will be unpopular with voters. (I am ignoring the politicians who deny that there is a problem in the first place.)

Corbyn is no exception. His call for nationalisation of the energy sector may sound oh so radical and ambitious, but it is, in fact, a clever way to avoid real responsibility, to avoid having to step up and advocate measures that would be much less popular than a promise of “free energy” at “no net cost to the taxpayer”.

image of SMR proposed in Korea

Supporters of nuclear power hope that small nuclear reactors, unlike large  plants, will be able to compete economically with other sources of electricity. But according to M.V. Ramana, a Professor at the University of British Columbia, this is likely to be a vain hope. In fact, according to Ramana, in the absence of a mass market, they may be even more expensive than large plants.

In October 2017, just after Puerto Rico was battered by Hurricane Maria, US Secretary of Energy Rick Perry asked the audience at a conference on clean energy
in Washington, D.C.: “Wouldn’t it make abundant good sense if we had small modular reactors that literally you could put in the back of a C-17, transport to an area like Puerto Rico, push it out the back end, crank it up and plug it in? … It could serve hundreds of thousands”.

As exemplified by Secretary Perry’s remarks, small modular reactors (SMRs) have been suggested as a way to supply electricity for communities that inhabit islands or in other remote locations.

In the past decade, wind and solar energy have become significantly cheaper than nuclear power

More generally, many nuclear advocates have suggested that SMRs can deal with all the problems confronting nuclear power, including unfavorable economics, risk of severe accidents, disposing of radioactive waste and the linkage with weapons proliferation. Of these, the key problem responsible for the present status of nuclear energy has been its inability to compete economically with other sources of electricity. As a result, the share of global electricity generated by nuclear power has dropped from 17.5% in 1996 to 10.5% in 2016 and is expected to continue falling.

Still expensive

The inability of nuclear power to compete economically results from two related problems. The first problem is that building a nuclear reactor requires high levels of capital, well beyond the financial capacity of a typical electricity utility, or a small country. This is less difficult for state- owned entities in large countries like China and India, but it does limit how much nuclear power even they can install.

The second problem is that, largely because of high construction costs, nuclear energy is expensive. Electricity from fossil fuels, such as coal and natural gas, has been cheaper historically ‒ especially when costs of natural gas have been low, and no price is imposed on carbon. But, in the past decade, wind and solar energy, which do not emit carbon dioxide either, have become significantly cheaper than nuclear power. As a result, installed renewables have grown tremendously, in drastic contrast to nuclear energy.

How are SMRs supposed to change this picture? As
 the name suggests, SMRs produce smaller amounts of electricity compared to currently common nuclear power reactors. A smaller reactor is expected to cost less to
 build. This allows, in principle, smaller private utilities and countries with smaller GDPs to invest in nuclear power. While this may help deal with the first problem, it actually worsens the second problem because small reactors lose out on economies of scale. Larger reactors are cheaper
 on a per megawatt basis because their material and work requirements do not scale linearly with generation capacity.

“The problem I have with SMRs is not the technology, it’s not the deployment ‒ it’s that there’s no customers”

SMR proponents argue that they can make up for the lost economies of scale by savings through mass manufacture in factories and resultant learning. But, to achieve such savings, these reactors have to be manufactured by the thousands, even under very optimistic assumptions about rates of learning. Rates of learning in nuclear power plant manufacturing have been extremely low; indeed, in both the United States and France, the two countries with the highest number of nuclear plants, costs rose with construction experience.

Ahead of the market

For high learning rates to be achieved, there must 
be a standardized reactor built in large quantities. Currently dozens of SMR designs are at various stages of development; it is very unlikely that one, or even a few designs, will be chosen by different countries and private entities, discarding the vast majority of designs that are currently being invested in. All of these unlikely occurrences must materialize if small reactors are to become competitive with large nuclear power plants, which are themselves not competitive.

There is a further hurdle to be overcome before these large numbers of SMRs can be built. For a company to invest
in a factory to manufacture reactors, it would have to be confident that there is a market for them. This has not been the case and hence no company has invested large sums of its own money to commercialize SMRs.

An example is the Westinghouse Electric Company, which worked on two SMR designs, and tried to get funding from the US Department of Energy (DOE). When it failed in that effort, Westinghouse stopped working on SMRs and decided to focus its efforts on marketing the AP1000 reactor and the decommissioning business. Explaining this decision, Danny Roderick, then president and CEO of Westinghouse, announced: “The problem I have with SMRs is not the technology, it’s not the deployment ‒ it’s that there’s no customers. … The worst thing to do is get ahead of the market”.

Delayed commercialization

Given this state of affairs, it should not be surprising that
 no SMR has been commercialized. Timelines have been routinely set back. In 2001, for example, a DOE report on prevalent SMR designs concluded that “the most technically mature small modular reactor (SMR) designs and concepts have the potential to be economical and could be made available for deployment before the end of the decade provided that certain technical and licensing issues are addressed”. Nothing of that sort happened; there is no SMR design available for deployment in the United States so far.

There are simply not enough remote communities, with adequate purchasing capacity, to be able to make it financially viable to manufacture SMRs by the thousands

Similar delays have been experienced in other countries too. In Russia, the first SMR that is expected to be deployed is the KLT-40S, which is based on the design of reactors used in the small fleet of nuclear-powered icebreakers that Russia has operated for decades. This programme, too, has been delayed by more than a decade and the estimated costs have ballooned.

South Korea even licensed an SMR for construction in
2012 but no utility has been interested in constructing one, most likely because of the realization that the reactor is too expensive on a per-unit generating-capacity basis. Even the World Nuclear Association stated: “KAERI planned to build a 90 MWe demonstration plant to operate from 2017, but this is not practical or economic in South Korea” (my emphasis).

Likewise, China is building one twin-reactor high- temperature demonstration SMR and some SMR feasibility studies are underway, but plans for 18 additional SMRs have been “dropped” according to the World Nuclear Association, in part because the estimated cost of generating electricity is significantly higher than the generation cost at standard-sized light-water reactors.

No real market demand

On the demand side, many developing countries claim to be interested in SMRs but few seem to be willing to invest in the construction of one. Although many agreements and memoranda of understanding have been signed, there are still no plans for actual construction. Good examples are the cases of Jordan, Ghana and Indonesia, all of which have been touted as promising markets for SMRs, but none of which are buying one.

Neither nuclear reactor companies, 
nor any governments that back nuclear power, are willing to spend the hundreds of millions, if not a few billions, of dollars to set up SMRs just so that these small and remote communities will have nuclear electricity

Another potential market that is often proffered as a reason for developing SMRs is small and remote communities. There again, the problem is one of numbers. There are simply not enough remote communities, with adequate purchasing capacity, to be able to make it financially viable to manufacture SMRs by the thousands so as to make them competitive with large reactors, let alone other sources of power. Neither nuclear reactor companies, 
nor any governments that back nuclear power, are willing to spend the hundreds of millions, if not a few billions, of dollars to set up SMRs just so that these small and remote communities will have nuclear electricity.

Meanwhile, other sources of electricity supply, in particular combinations of renewables and storage technologies such as batteries, are fast becoming cheaper. It is likely that they will become cheap enough to produce reliable and affordable electricity, even for these remote and small communities ‒ never mind larger, grid- connected areas ‒ well before SMRs are deployable, let alone economically competitive.

Editor’s note:

Prof. M. V. Ramana is Simons Chair in Disarmament, Global and Human Security at the Liu Institute for Global Issues, as part of the School of Public Policy and Global Affairs at the University of British Columbia, Vancouver.  This article was first published in National University of Singapore Energy Studies Institute Bulletin, Vol.10, Issue 6, Dec. 2017, and is republished here with permission.  

Britain has chosen to secure electricity supplies through a scheme which pays power plants to be available several years in advance, but falling prices suggest this capacity market is overkill and poor value for money, with ample alternative approaches, writes energy finance consultant Gerard Wynn. Courtesy Energy and Carbon blog.

The Institute for Energy Economics and Financial Analysis (IEEFA) recently published a review of how nine countries and regions with exceptionally high levels of wind and solar power have coped with the variability of these power sources.

A costly solution

Britain has opted for a capacity market, in combination with other approaches, to cope with an expected increase in variability in electricity supply, as the country switches to the wind and sun.

The UK’s adoption of a capacity market may be overkill, putting vast sums of public money at risk

But it turns out that countries with far higher levels of so-called variable renewables are doing without capacity markets at all, finding that other measures are sufficient, such as investing in transmission capacity, reforming power markets and requiring renewable energy technologies themselves to play a bigger role in meeting power demand.

The UK’s adoption of a capacity market may be overkill, putting vast sums of public money at risk.

The capacity market approach pays utilities and other operators billions of pounds to commit to keep their coal, gas, nuclear and hydro power plants open, for up to four years ahead, regardless of whether they were planning to do this anyway, and regardless of whether they generate any electricity.

The capacity market – whose auctions have now been running for several years – has still not motivated a single large new power plant

The same utilities that are benefiting were big fans of the scheme when it was mooted in 2013. For example, SSE in 2013 warned that the UK was entering a “critical period”, including the risk of blackouts. Centrica also warned in 2013 of blackouts, in 2017/18, and said that it would not build another gas power plant without a capacity market in place.

As it happens, the capacity market – whose auctions have now been running for several years – has still not motivated a single large new power plant, but has allocated some £3.8 billion to power plant operators, including the same utilities, under auctions that are held 1 year and 4 years ahead of delivery, called T-1 and T-4 respectively.

Prices in the two most recent T-1 and T-4 auctions in early 2018 both saw price reductions, suggesting that the UK electricity system is coping well to date – see chart below. One would expect rising prices if the electricity system was short of capacity and needed a rollout of new generation.

Chart – Falling capacity payments under UK capacity market (nominal prices)

Source: the author’s and IEEFA’s interpretation of capacity market results data from the UK’s “EMR Delivery Body”

Falling prices

There are various possible explanations for these falling capacity market prices, including support in the early years of the scheme which motivated the construction of a new wave of very small generators; the prospective buildout of sub-sea interconnection into Europe; rising running times of gas power plants as coal power shuts down; and reforms to so-called cash-out markets to reward power plants that can respond quickly to supply shortfalls.

To its credit, Britain’s energy ministry did foresee the latter, saying before it introduced its capacity market: “In theory, as cash-out is fully reformed and the market has confidence to invest on the basis of scarcity rents the capacity price should tend towards zero under a capacity market.”

Such cash-out reform is a no-brainer, as an efficient market approach to incentivising flexible generation.

It isn’t too late to dial back the scheme, to focus on supporting emerging, enabling technologies such as battery storage

Given that the UK is both building out interconnection and reforming cash-out (which involves lifting caps on penalties and rewards for balancing real-time demand and supply), it may be that its capacity market is redundant.

Given the vast sums already spent, this is an important issue. It isn’t too late to dial back the scheme, to focus on supporting emerging, enabling technologies such as battery storage, and dropping support for existing gas, coal and nuclear, as IEEFA recommended last year.

Or it could even be phased out altogether.

More alternatives

IEEFA’s report reviewed nine case study power markets worldwide with very high levels of wind and solar power, at 14% to 53% of total generation. Only one of these, Spain, had a long-standing, comprehensive capacity market.

The report noted nine alternative actions that local and national grid operators and policymakers in these countries had taken to ease the transition to renewable power.

Those nine measures were: investment in the transmission grid; investment in cross-border interconnection; prioritisation of domestic flexible generation; market reform to boost flexible resources; support for demand-side flexibility; better wind and solar power forecasting; a more responsive distribution grid; making renewables more responsible for meeting demand; and national leadership in enabling renewables.

Editor’s Note

Gerard Wynn is independent energy finance consultant. This article first appeared on his blog Energy and Carbon and is republished here with permission.

Energy Post published an article about  IEEFA’s report earlier this month. 

The experience of the German Energiewende shows that increasing amounts of renewable energy on the power system, while at the same time reducing inflexible baseload generation, does not harm reliability write Michael Hogan, Camille Kadoch, Carl Linvill and Megan O’Reilly of the Regulatory Assistance Project (RAP). American policymakers who are still skeptical can look across the Atlantic, to Germany, for a concrete example of a successful transition away from traditional baseload, the authors note. Courtesy Public Utilities Fortnightly.

The power system in the United States, like that in numerous other countries throughout the world, is in a period of transition.

Overall, generation is shifting away from large, inflexible thermal generation, that is, traditional baseload generation, and toward smaller, more dispersed, variable renewable resources. This transition is occurring both because citizens are calling for less carbon-intensive resources, and simply because wind and solar have become among the least expensive resources.

U.S. natural gas prices have declined and the cost of renewables has come down dramatically.

A recent report from the R Street Institute, “Embracing Baseload Power Retirements,” noted that “Historically, conventional baseload resources were integral to achieving portfolio reliability at least cost, but some of these resources no longer provide the most economical means to meet reliability needs.”

Most studies have found that reliability and least cost are best served by reducing the share of inflexible baseload generation

This shift has triggered a debate among some U.S. policymakers about reliability and the continued need for baseload power plants such as coal and nuclear. Scott Pruitt, head of the Environmental Protection Agency, has said that coal-fired power plants are key to preserving electricity reliability. This thinking is likewise reflected in the U.S. Department of Energy’s recent proposal to allow special cost recovery for generators that can store ninety days of fuel on site.

Reliability with renewables

However, numerous studies sponsored by utilities, system operators, the national labs, and others show that a large share of variable renewable energy production can be integrated while keeping the lights on, without any valuable role for traditional baseload.

No study, not even by the Department of Energy, which examined this issue in an August 2017 Staff Report on Electricity Markets and Reliability, has found evidence that baseload generation is required for reliability. Most studies have found that reliability and least cost are best served by reducing the share of inflexible baseload generation.

To the extent that reliability is a concern, it is not one driven by a lack of available generating capacity. A recent report from Rhodium Group found that a mere 0.00865 percent of all customer service hours lost from 2012 to 2016 were due to either fuel supply emergencies or other concerns about the availability of generation.

In spite of the fact that Germany is meeting nearly a fifth of its electricity requirements with VREs while retiring inflexible thermal generation, the nation has not experienced reliability problems on either the distribution or bulk electric system

American policymakers who are still skeptical can look across the Atlantic for a concrete example of a successful transition away from traditional baseload. Germany traditionally relied on a significant share of inflexible thermal generation such as coal and nuclear to supply the grid. Resources were dispatched to meet load, and variable resources were few.

Now, Germany is a leader in the early adoption of variable renewable energy resources (VREs). The country has shown leadership by pursuing what it calls the Energiewende or energy transition, which has set a national goal of eighty percent decarbonization
by 2050.

Government statistics show that VREs now make up eighteen percent of the German electricity mix, and all renewables, including hydro, account for twenty-nine percent. At the same time, Germany is phasing out baseload nuclear plants and is also working on decarbonizing its remaining energy mix by phasing out inflexible baseload coal- fired generation.

In spite of the fact that Germany is meeting nearly a fifth of its electricity requirements with VREs while retiring inflexible thermal generation, the nation has not experienced reliability problems on either the distribution or bulk electric system. If anything, government data show that the reliability of the German system has increased.

About the Energiewende

The German Energiewende is one facet of the government’s commitment to an aggressive, economy-wide reduction in greenhouse gas emissions. The Energiewende has set ambitious targets for renewable energy.

Renewables should make up at least fifty percent of the power generation mix by 2030, sixty percent by 2040, and eighty percent by 2050. Germany has significantly diversified its electricity mix toward renewables, which grew from just four percent in 1990 to the current twenty-nine percent.

As a spokeswoman for the Federal Ministry of Economics and Energy has put it, “baseload is no longer needed,” otherwise it could “block the grid”

Germany’s goal of eighty percent renewable energy by 2050 now has to be met at the same time as the country retires its nuclear fleet. After the nuclear accident at Japan’s Fukushima Daiichi plant in March 2011, the German government set a nuclear phase-out deadline of 2022. As part of this move, the seven oldest nuclear reactors were immediately shut down.

To meet these goals, the country is anticipating a future with large amounts of variable renewables, no nuclear power, and very small amounts of fossil fuels. In this context, dispatching large thermal power plants in baseload service to meet demand is increasingly outmoded.

Germany already produces hours of nearly a hundred percent renewable electricity on the system. As a spokeswoman for the Federal Ministry of Economics and Energy has put it, “baseload is no longer needed,” otherwise it could “block the grid.” This has consequences for the inflexible thermal generation that remains on the system.

See Figure One.

During hours of low VRE production, baseload plants that were displacing cheaper energy sources leading up to these hours have little or no capacity in reserve, requiring investment in additional, peaking generation capacity that sits idle most of the time.

By contrast, more flexible, dispatchable generation that can ramp down during periods of high VRE production can maximize the use of cheap energy, while at the same time inherently providing the reserve capacity needed for other hours.

Germany eventually envisions moving to an electricity market 2.0 where the focus shifts to balancing net load. Inflexible baseload generation will be used infrequently because it is not competitive with more flexible supply-side and demand-side resources in many hours. Wind and solar would provide the bulk of energy over a regional grid, with smart demand-side flexibility and more flexible load-following thermal generation helping to balance out the system.

What has this meant in practice?

With the share of renewable production now close to a third of the total electricity mix, and with nuclear plants retiring, how is the reliability of the German electricity system faring?

The chart below tracks the trends in the country’s energy mix as well as System Average Interruption Duration Index (SAIDI), a measure of the annual average duration of interruption in customer service from all causes, indicated in minutes per year.

The chart also shows Loss of Load Expectation (LOLE) numbers, a widely-used measure of resource adequacy that assesses how many minutes a year, on average, the available generation capacity in a given control area is likely to fall short of total demand.

Both the SAIDI and LOLE numbers show that increasing amounts of VREs and decreasing baseload production have not negatively affected reliability in Germany to date.

See Figure Two.

Both the SAIDI and LOLE data indicate that reliability has followed historic trends. e potential uptick in LOLE numbers for 2025 reflects the fact that LOLE nearly always shows an increase that far into the future, because LOLE only reflects committed generation investments and commitments to new resources that are normally made within a five-year time frame.

Even the projected uptick should be put into perspective: it projects an LOLE of less than twenty minutes per year, well below the prevailing U.S. standard of a hundred and forty four minutes per year.

A more granular analysis of SAIDI numbers over the past decade indicates that the reliability of the medium- and low-voltage system has in fact improved over this period. The next chart tracks the duration of disruptions attributable to distribution system events between 2006 and 2015 – showing a clear decline over that period.

The Bundesnetzagentur Monitoring Report 2016, from which this data is drawn, noted that “the energy transition and the associated increase in embedded generation does not appear to have had a discernible impact on the quality of supply in 2015.”

See figure three.

System adequacy in Germany is based on a national power balance, but given that electricity is traded cross-border in the European interconnected system, the SAIDI and LOLE numbers in this context are being considered in a vacuum. Weighing the availability of resources across the wider European system would presumably increase reliability even further.

What does the Energiewende teach us about what resources are needed?

The Energiewende also demonstrates the types of resources that are needed on a system with large amounts of VREs. The figure below illustrates this.

Prior to integration of VREs, system operators needed to meet fairly predictable total demand (top line in purple) with dispatchable generation sources, with a substantial amount of non- fluctuating demand.

However, in a system where variable resources are integrated fully, dispatchable resources now need to follow changes in the residual “net demand” (blue line) not already served by “free” energy from variable renewables, and very little of the net demand is non- fluctuating.

See Figure Four.

Baseload resources, traditionally nuclear and coal plants, are not technically or economically well suited to this new paradigm. It will be more volatile and costly to balance the system if the dispatchable resource base continues to be dominated by inflexible baseload generation. To the extent there is a demand for generation to be operated round the clock, more flexible plants are fully capable of meeting this need.

This is good news for consumers. Currently, grid operators dispatch wind and solar first because they have the lowest operating costs. The weather-dependent nature of the resources creates a need for other resources to adjust their dispatch more frequently and extensively to balance system supply and demand.

By removing inflexible baseload in favor of more flexible load-following plants, consumers realize the full benefit of the lowest-cost resources while receiving the same quality of service

Continuing to rely on inflexible baseload would require curtailment of less costly energy. The alternative is an economic mix of VREs and load-following plants that displaces baseload operations. By removing inflexible baseload in favor of more flexible load-following plants, consumers realize the full benefit of the lowest-cost resources while receiving the same quality of service.

Germany is now debating how increasing shares of VRE can be integrated cost-effectively. In the spring of 2017, the country’s national regulatory authority published a report that analyzed five events in 2015 where a high share of VREs on the grid coincided with negative market prices.

The report closes by recommending further ways to decrease costs of VRE integration while decreasing inflexible thermal generation. Recommendations included better forecasting (of load, and of renewable energy supply), support for infrastructure investments, better use of spinning reserves, and other system improvements.

Resource capabilities, not baseload resources

The experience of the Energiewende shows that increasing amounts of renewable energy on the power system, while at the same time reducing inflexible baseload generation, does not harm reliability and can lower the cost of VRE integration. Indeed, the German data suggest that reliability has actually improved under these conditions.

For regulators and policymakers in the U.S. deliberating whether and how to respond to federal officials and others who insist that inflexible baseload is essential for reliability, the German experience offers important evidence to the contrary

What the Energiewende does demonstrate is a need for greater system flexibility. Germany’s energy transformation envisions a grid where conventional thermal generation would follow “net load,” meeting short- term energy demand in some hours and the demand for flexible reserves in other hours, and variable renewable energy such as wind and solar energy would provide the bulk of energy over a regional grid. The Energiewende provides evidence that this type of system can be reliable and is attainable.

For regulators and policymakers in the U.S. deliberating whether and how to respond to federal officials and others who insist that inflexible baseload is essential for reliability, the German experience offers important evidence to the contrary.

Editor’s Note:

The Regulatory Assistance Project (RAP) is a globally operating independent and nonpartisan team of experts. Michael Hogan is a senior advisor to the Regulatory Assistance Project (RAP), working on issues related to power market design, integration of low-carbon supply, system planning, and demand response in the United States and Europe. Camille Kadoch is RAP’s general counsel and publications manager. Dr. Carl Linvill is a RAP principal, leading the organization’s efforts on renewable energy integration and trans- mission planning in the Western United States. Megan O’Reilly is an environmental lawyer and principal and owner of Arc Research and Analysis; she worked with RAP and Agora Energiewende as a Robert Bosch Fellow in 2016-2017.

This article was originally published in the February 2018 issue of Public Utilities Fortnightly ( www.fortnightly.com ). Permission to republish this article in EnergyPost has been granted by the publisher.

Krišjānis Karinš is rapporteur on the revised electricity regulation for the European Parliament

As a new regulatory design for the EU electricity market is taking shape, there are grave concerns in the sector that the new rules will not advance the internal energy market very much. Or might even undermine it. Energy Post editor-in-chief Karel Beckman talked to a number of key players in the sector who will debate the proposed market design rules at an Energy Post event in Brussels on 20 March.

Over the coming months the European Council (representing the EU Member States) and the European Parliament will be hammering out a new “design” for the European electricity market, in “trilogue” negotiations with the European Commission.

In its Clean Energy Package, in particular the proposals for a revised electricity regulation and revised electricity directive, the Commission is trying to create a new regulatory structure for the EU electricity market, one that is capable of dealing with the steadily increasing amounts of renewable energy into the system. The Commission is convinced that to make this energy transition happen cost-effectively, a well-functioning internal market is key. The European Parliament mostly agrees with that vision.

“When we speak of backup, offshore wind offers great potential”

But the Member States are concerned about the effects the new energy system will have on their security of supply. To ensure that “the lights don’t go out”, they each tend to pursue their own solution, in the form of different schemes for backup capacity and “strategic reserves”. Many observers in Brussels, including many representatives of the Commission, are worried that this preoccupation with national concerns will lead to legislation that will, in the end, do little to enhance the functioning of the internal energy market, or might even make it worse.

As one Commission official complained at a recent event, “for years the Heads of State have been saying they want to see an integrated electricity market. We translated that commitment into the Clean Energy Package, but now they are trying to water it down.”

Capacity mechanisms and strategic reserves

One of the most contentious parts of the legislation relates to the conditions under which member states should be allowed to set up capacity mechanisms or strategic reserves. Through these schemes they pay generators or suppliers to keep backup capacity available to be used in case of shortages or emergencies. Many critics feel the schemes are used to subsidize incumbent generators and do not provide enough incentives for alternative, market-based solutions, such as “demand response” schemes.

To address these concerns, DG Energy has proposed certain key principles that capacity schemes should adhere to, such as technology-neutrality and a level playing field for foreign suppliers. It also demands that Member States undertake an “adequacy assessment”, including cross-border sources, on which their scheme should be based. The European Parliament to some extent supports this approach, but the Member States want to have more say over how they evaluate adequacy in their own country.

At the same the Directorate-General of Competition of the European Commission (DG Comp) has its own guidelines to ensure that capacity mechanisms do not become a form of illegal state aid. Just recently, DG Competition approved four capacity mechanisms (in Poland, Italy, France and Greece) and two strategic reserve schemes (in Belgium and Germany). However, many observers feel that DG Competition is not doing enough to ensure a level playing field. Some say there is “inconsistency” between the policies of DG Competition and DG Energy.

Jérôme Le Page, Director of European Electricity Markets at the  European Federation of Energy Traders (EFET), says he is “not convinced” by the recent decisions from DG Competition. EFET, whose goal it is to “help create a competitive, transparent, integrated energy market in the EU”, published a position paper in 2013 suggesting “design principles” that capacity mechanisms should follow. “DG Competition’s guidelines are 90% identical to ours”, says Le Page. “But how they apply them is a little bit disappointing. They are not as firm as they could have been to make sure that the spirit and letter of the principle they established are applied in practice.”

Le Page mentions the UK’s capacity market as one that is flawed. Spain’s capacity market also “violates EU competition guidelines”, notes Le Page. “But it was set up before the guidelines became law.”

Overall, says Le Page, “we see that Member States have a declining confidence in the ability of markets to deliver security of supply. We believe the market can deliver security of supply very well, but some Member States are not even trying.”

Anne-Malorie Géron, Vice-President EU Affairs at Finnish energy company Fortum, one of the largest generators in Europe, is concerned that the way capacity markets are being set up by member states “will make cross-border trade more difficult”. “Capacity markets may be needed for security of supply, but they should contribute to making the market more flexible and competitive. That is not what I am seeing today.”

Anne-Malorie Géron, Vice-President EU Affairs at Finnish  energy company Fortum, one of the largest energy producers and retailers in northern Europe, is concerned that the way capacity markets are being set up by member states “will make cross-participation of generators  difficult”. “Capacity mechanisms may be needed for security of supply, but they should not undermine markets to become more flexible and competitive.”

Simon-Erik Ollus, Chief Economist at Fortum, says there is a risk that capacity markets become a form of “central planning”. “You become dependent on the regulator’s decisions.”

According to Ollus, policymakers are underestimating developments in renewable energy and technological innovation. “They lack vision”, he says. “There already is huge flexibility in the system today. But it’s not being used. For example, there is a lot of demand side management potential, but it can’t be used because responsibilities are not clear. It is not clear who needs to optimize what.”

Simply a necessity

Andreas Schröter, Executive Vice President Central Europe & Mediterranean at the globally operating technical consultancy DNV GL, concurs with Ollus. “Relying on capacity markets is trying to be on the safe side. That’s understandable from a political perspective. But so much could be done if we let markets develop. With the use of digitalization and big data, the market will come up with cost-effective and smart solutions that we can’t even imagine today. This will also create jobs.”

He mentions offshore wind as an example. “A few years ago we thought this would be a very expensive, intermittent technology. Now we see it as an increasingly competitive, controllable, reliable technology that offers electricity the entire time. When we speak of backup, offshore wind offers great potential.”

Vincent Dufour, EU Affairs Director at French energy company EDF, stresses that the debate over capacity mechanisms should not be “black or white”. “For us”, he says, “it’s not an ideological issue. At the end of the day, policymakers are responsible for security of supply. They have to think of worst-case scenarios. At the same time we don’t want the market to be undermined.”

Dufour does have a problem with the distinction that is being made in the regulations between capacity mechanisms and strategic reserves. Germany, for example, has a strategic reserve scheme that is used when there is a crisis. But foreign players cannot participate in that. The French capacity market works very differently. It aims to avoid a crisis and allows for broad participation. “We believe strategic reserves should have the same conditions as capacity markets”, says Dufour. “They serve the same purpose.”

“We need to stop talking about carbon content in this context. It is polluting the debate on capacity mechanism and on carbon pricing”

James Matthys-Donnadieu, head of Market Development at Belgian transmission system operator (TSO), presents yet a different perspective. “For us setting up a capacity mechanism is simply a necessity”, he says.

Belgium, he explains, is committed to phasing out its nuclear power by 2025. “We did a thorough scientific study, the results of which concur with other independent studies,  in which we found that Belgium will need 3.6 GW of new capacity by 2025. That takes into account other flexibility options, such as importing power, and demand response. This capacity will not be built without a capacity market. That’s a simple reality.”

Belgium already has a strategic reserve, Matthys-Donnadieu notes, “but that is not a structural solution for us. Whatever we do, we need new capacity to ensure the lights won’t go out.”

Michael Jenner is Director Policy and Regulation at UK Power Reserve, a company that specializes in providing “flexible generation capacity” to the market. It is the largest developer of new capacity resulting from the UK capacity market and has a portfolio of over 1 GW of small-scale, local gas power generation and battery storage assets. According to Jenner, the UK capacity market serves a useful purpose. “If there was no capacity market, we would still deliver flexibility to the market”, he says, “but not as much.”

Jenner notes that the UK capacity market helps his company finance the building of new capacity by providing secure “bankable” revenues. In the UK, an asset that is successful in the capacity market auction receives the auction clearing price for 15 years. The UK regime also supports flexibility by allowing the participation of demand-response schemes as well as interconnectors. However, Jenner does believe that it can still be improved. “Right now the capacity market just delivers kilowatts. But to support intermittent renewables, what we really need are flexible kilowatts. Assets that can provided this flexibility and rapid response should be rewarded.”

Polluting the debate

Virtually every one in the energy industry is critical of the proposal in the market design legislation to include a 550 g CO2/kWh emission standard limit for capacity mechanisms. This is intended to exclude coal plants from public support, but the industry experts feel that capacity mechanisms should not be used to carry out climate policy.

“The availability of import is extremely important for us. We have plenty of interconnector capacity, but can the electrons be delivered?”

“We already have an Emissions Trading System”, says Jenner. “In the UK we also have carbon price support which is added on top of the ETS price and companies have to factor these costs into their capacity market auction bids. How do you mix that with an emissions standard?”

Le Page of EFET agrees. “We need to stop talking about carbon content in this context. It is polluting the debate on capacity mechanism and on carbon pricing.”

Extremely important

A more complex debate has arisen around proposals from the Council and the ITRE committee of the European Parliament to require transmission system operators (TSOs) to make 75% of cross-border capacity available to the market. This at first sight seems to be a rule that would be good for competition and trade, and put a brake on government intervention. But most industry experts do not see it that way.

Le Page notes that 75% is an arbitrary number that does not guarantee welfare maximisation. Besides, he adds, “it is not clear at all what it refers to. 75% of what exactly? There are differences of opinion about that.”

“In the Nordic markets we balance demand and supply without capacity markets. We accept that we are dependent on each other for our security of supply”

He points out that ACER, the agency for the cooperation of EU’s energy regulators, in 2016 already issued a decision that should ensure that TSOs do not unnecessarily remove capacity from the market. “This is a problem that is being tackled through the implementation of Third Package network codes and guidelines.”

Matthys-Donnadieu of Elia is more positive. “The availability of import is extremely important for us. We have plenty of interconnector capacity, but can the electrons be delivered? It’s true that the ACER guideline aims to solve this, but the 75% proposal, provided it is adequately defined, puts a firm number in place.”

Integration of renewable energy

Another point of discussion in the market design debate is how renewables should be treated in the energy system. In some countries they get priority in the system (“priority dispatch”). They also generally do not have balancing responsibilities. The proposals aim to abolish these advantages, though the European Parliament wants to maintain priority dispatch for small-scale and existing installations.

Again, most industry experts agree that any kind of special treatment should be phased out. “We are against priority dispatch”, says Dufour of EDF. “We don’t understand why the European Parliament wants to extend this.”

“Of course priority dispatch should be abolished”, notes Ollus of Fortum.

Finally, there is debate about price caps, which are still used by certain Member States and which current proposals would keep to some extent. These are also strongly opposed by the industry. “We need to eliminate price regulation”, says Le Page. “Policymakers don’t seem to realise that by installing price caps they will ultimately pay the price through the capacity mechanisms.”

For Le Page price regulation is just another sign that “confidence in the market is declining”. That’s a pity, he says, because “the market is working. Wholesale prices have fallen since the beginning of market liberalization in the 1990s.”

Ollus offers the Nordic market as an example for the rest of the EU. “In the Nordic markets we balance demand and supply without capacity markets. We accept that we are dependent on each other for our security of supply. That’s possible because we have well-integrated markets. This is where the EU needs to be if it wants to deliver on its 2050 goals.”

Map inside the UK National Grid electricity control room

The European Commission has proposed new European legislation that could put Europe’s distribution system operators in a powerful position to bend market rules to their own advantage, writes Julie Finkler of NGO ClientEarth. According to Finkler, this could seriously hamper other market players, like community energy initiatives, renewable energy producers and aggregators. She calls on the European Parliament and the Member States to ensure this will not happen.

The European Parliament’s industry and energy committee (ITRE) recently adopted its position on reforming the EU’s internal energy market. This position forms part of the negotiations on the Commission’s ‘Clean Energy for All Europeans’ package.

The committee supported new rules on electricity distribution system operators (DSOs) that could change the design of Europe’s electricity market. They include creating a new EU-level entity for DSOs, an “EU DSO body”.

This body would promote coordination amongst the Europe Union’s approximately 2,750 DSOs and pave the way for them to take on more tasks to ensure their grids are smarter, flexible and capable of integrating more renewable energy resources.

Without the right legal framework, however, the EU DSO body has the potential to hinder, rather than facilitate, the transition to a renewable energy future, as it would let DSOs create their own rules and largely police themselves.

The risks of self-regulation

The EU DSO body will provide technical expertise in developing rules and best practices to promote a more flexible, clean and decentralised energy system.

The new body will also be responsible for drafting regulations known as ‘network codes’. Network codes are binding legal instruments that aim to harmonise the internal electricity market. They are key to improving competition within the internal energy market and ensuring that renewables and demand response are properly embedded in the market.

Under the Third Energy Package, the organisation ENTSO-E representing electricity transmission operators (TSOs) was granted similar powers to draft its own network codes. It has since been criticised for lacking a clear separation between its roles

Worryingly, however, these network codes would not only govern the conduct of the DSOs themselves but other market participants as well.  This puts DSOs in a position to draft regulations that may facilitate their business interests, while disadvantaging those of their competitors.

For example, under EU law, DSOs can remain closely connected to their parent utilities. This creates the potential for DSOs also to attempt to influence the content of the regulations in a manner that gives their parent utilities an unfair advantage over new market players, such as small-scale renewables, energy communities, or third-party aggregators. The risk of self-dealing is high.

What’s more, the drafting process for the regulations could be drawn out if the EU DSO tried to secure agreements from all of the potential 2,750 members and may result in ambition being diluted.

Reinventing the wheel

This is not the first time such a policy mistake has been made. Under the Third Energy Package – the current legislation governing the EU internal electricity market – the organisation ENTSO-E representing electricity transmission operators (TSOs) was granted similar powers to draft its own network codes. It has since been criticised for lacking a clear separation between its roles as a lobbyist, drafter, implementer, and overseer of network codes.

What makes matters worse is that, as the Commission’s proposal currently stands, the body would also be able to effectively monitor itself with little regulatory oversight

As proposed by the Commission, the EU DSO body risks reproducing this fundamentally flawed governance structure. This could easily compromise the EU DSOs’ ability to act independently and in the public’s interest when carrying out their work.

What makes matters worse is that, as the Commission’s proposal currently stands, the body would also be able to effectively monitor itself with little regulatory oversight.

Given the central role of DSOs in facilitating the transition to a renewable energy future, which is essential to achieving the Paris Agreement’s climate ambition, the Commission’s proposal simply doesn’t work.

Enabling a cleaner energy system and effective competition

Through its position, the ITRE committee attempts to improve some of the EU DSO body’s governance issues by:

• Requiring the EU DSO body to act independently from the interests of its members to ensure effective competition in energy markets;
• Ensuring robust regulatory oversight of the EU DSO by ACER – the European Agency for the Cooperation of Energy Regulators; and
• Clarifying that independent regulators – national regulators and ACER – will oversee the implementation of and compliance with network codes, not the industry itself.

These measures correct the flaws in the Commission’s proposal. However, almost paradoxically, the European Parliament appears to undermine these improvements by also proposing to open up the EU DSO body’s membership to existing EU-level associations who represent DSOs. Many, however, also represent the interests of energy utilities, which may try to protect and advance their interests over potential competitors and new market players.

This is clearly at odds with the obligation of DSOs to act as neutral market facilitators. If the interests of these stakeholders are reflected in the best-practice reports, recommendations and network codes drafted by the EU DSO body, the market may become biased.

If the proposed safeguards are too weak, there is a danger that the EU DSO body and the regulations it drafts will hinder the integration of renewables, storage and demand response into the grid

The European Parliament and the European Council will soon enter into trilogues and it is imperative that the outcome of the negotiations on this matter increase the EU DSO body’s legitimacy and ensure its proper functioning. The Parliament and the Council must guarantee that the new entity plays a positive and proactive role in transforming Europe’s energy system and supports further deployment and integration of renewable energy.

If the proposed safeguards are too weak, there is a danger that the EU DSO body and the regulations it drafts will hinder the integration of renewables, storage and demand response into the grid. This may ultimately delay and increase the costs of the transition to a smarter, more flexible and decarbonised energy system and jeopardise the European Union’s commitments to address climate change.

Editor’s Note:

Julie Finkler is Law and Policy Advisor at ClientEarth. She joined ClientEarth’s London office in December 2014. She holds a Master’s degree in Energy and Environment Economics from Grenoble University, France.

The recent deal between German utilities RWE and Eon will lead to a concentration of power in the different segments of the energy market, writes Marius Buchmann of Jacobs University in Bremen. According to Buchmann, the big question is whether the new companies will become innovation engines or will impose new market entry barriers.  Article courtesy of Buchmann’s blog Enerquire.

Since 2016, the largest German utilities, which happen to be major international players in the European energy market as well, have been in a strategic transition period. What happened in 2016 is that Eon and RWE separated their conventional generation business from network, retail and renewable business units.

For RWE, Innogy became responsible for renewable generation, distribution networks and the retail business. RWE itself, on the other hand, focused its business on conventional generation.

The separation of renewable and conventional generation seems reasonable because an investment in renewable generation cannibalizes revenues from conventional generation

In the case of Eon, a new subsidiary, Uniper assumed the task of conventional generation, while Eon itself kept the distribution grids, the renewable generation business and retail solutions. In this post here, we analyzed in greater detail the different drivers for this strategic shift in 2016.

Most importantly, the separation of renewable and conventional generation seems reasonable because an investment in renewable generation cannibalizes revenues from conventional generation via reduced operation hours and lower prices at the spot market.

This threat of self-cannibalization makes it difficult to develop a renewable generation portfolio within a company that depends on revenues from conventional generation. In this post, we discussed the potentially disruptive nature of renewable generation for the conventional generation business.

The changes in 2018

On 12th March 2018, both Eon and RWE announced that they will exchange resources to form two more focused companies. Eon will sell its renewable generation business to RWE and will in exchange receive the network and retail business from Innogy.

Figure 1: The new structure of E.on and RWE (E.on 2018)

The details of the proposed deal between Eon and RWE are specified in Figure 2.

Figure 2: An overview of the asset exchange between Eon and RWE (E.on 2018)

The future Eon – focus on regulated income and innovation in the retail business

For Eon, selling its renewable generation assets will result in a stronger focus on regulated incomes from network operation. Today, Eon’s EBIT is based 65% on regulated earnings, mainly from the networks and partly from renewable generation.

The new Eon will increase its regulated asset base from € 23 billion in 2017 to € 37 billion, which equals an increase of 62%. With the networks from Innogy, the new Eon will potentially derive 80% of its EBIT from regulated earnings. At the same time, the customer base will increase from 31 million to 50 million customers – again an increase of 62%. Figure 3 shows how the new Eon relates to other major players in the European energy market.

Figure 3: The European market position of the new Eon (E.on 2018)

Several reasons come to mind why Eon chooses to focus on the regulated business in combination with the consumer segment. From our point of view, this strategy primarily aims at risk reduction. While renewable generation is a regulated business, this is likely to change in most European markets soon.

Even today, due to decreasing subsidies and increasing competition, revenues from renewable generation are falling. At the same time, competition in the consumer segment is increasing. With digitalization, it is likely that competition in existing and new markets (such as smart homes) will intensify soon. Reducing the risk by focusing on one of the competitive segments (renewables or retail) might therefore be a reasonable response.

Eon and Innogy share the vision that digital consumer solutions rather than generation should become the focus of energy utilities in the future

In the consumer segment, both Eon and Innogy have concentrated on similar markets, which offers the potential for synergies. Furthermore, Eon and Innogy have invested money in the development of new innovation processes (e.g. both make use of innovation hubs and accelerator programs) that aim at developing new digital business models for utilities.

While this is a rather new business area for energy utilities, Eon and Innogy share the vision that digital consumer solutions rather than generation should become the focus of energy utilities in the future.

RWE – an even bigger dinosaur?

In contrast to Eon, RWE specializes in non-regulated earnings from conventional and renewable energy generation (which will become non-regulated earnings in the near future). The new RWE will become an even larger player in the conventional generation business than it is today, by gaining Eon’s shares in nuclear and gas power plants.

Today, RWE receives roughly 65% of its total earnings from generation. This share will increase to 90% after the deal with Eon has been closed. In addition, RWE will gain all renewable generation capacities from Eon. Together, the new RWE will then own 8 GW of renewable capacity in total.

As a result, RWE will operate the second largest renewable generation portfolio in Europe. Still, compared to the conventional generation of 46 GW, renewables will play a minor role at RWE. The interesting question will be how RWE will deal with the risk of self-cannibalization.

Investing in renewables results in decreasing earnings from conventional generation. So far, experience from the last decade has shown that RWE will rather focus on conventional generation than actively shape the energy transition.

The potential implications for energy markets in Germany

In general, the deal will lead to a concentration of power in the different segments of the energy market. RWE will gain significant market power in the generation business, while Eon will be very dominant in the consumer and network segment. While the network segment is regulated, the consumer segment is not. Therefore, regulatory authorities might oppose the proposed restructuring of the two energy giants.

If the deal is closed, Eon will gain a powerful position, especially when it comes to the development of new consumer services. Whether these new services are data-driven or not, in order to sell products, it is always a competitive advantage to have an established connection with existing consumers.

After the restructuring, RWE will own even larger shares of conventional generation in Germany, which gives this company more market power and political weight when discussing the future of energy production in Germany

Especially in the context of energy consumption, most private households have not made much use of competition so far. Switching rates in Germany and other European countries are rather low. Therefore, once a utility has won a customer, it is quite unlikely they will switch to another competitor.

Though this might (hopefully) change in the future with more digital products entering the energy realm, it puts Eon in a better starting position compared to its competitors.

The potential implications for the energy transition

First of all, we need to take into consideration that large utilities are only minor players in energy transition. All utilities together own less than 15% of total renewable capacity in Germany. Although in this segment RWE would gain a significant role after the restructuring – it would be the largest utility investor in renewables in Germany, especially in on- and offshore wind – RWE will not be able to determine how the energy transition evolves.

However, when it comes to conventional generation, after the restructuring RWE will own even larger shares in Germany, which gives this company more market power and political weight when discussing the future of energy production in Germany.

Whether the government will listen to RWE’s positions remains to be seen. But it seems certain that RWE’s ability to influence politics related to the energy transition might increase after the deal.

The merging of Innogy and Eon might lead to more innovative solutions that support energy transition on the consumption side

On the other hand, the energy transition strives to develop an energy system based on decentralized generation and distributed flexibility. Especially the latter requires new solutions and services that unlock the flexibility potential of all user groups: industrial, commercial and residential.

Here, the merging of Innogy and Eon might lead to more innovative solutions that support the energy transition on the consumption side. But only if Eon implements innovation processes and builds cooperation with other innovators to develop successful services and products in the retail realm.

This is questionable as consumer-centric innovation has not emerged as a strength of German utilities so far. In addition, the new Eon is certainly not smaller and hence less likely to adapt fast to changing environments.

Eon and RWE push for centralization to cope with ongoing decentralization

It seems clear that both Eon and RWE strive for market power to address the challenges of increasing competition and decentralization. Whether this strategy will be successful remains to be seen.

For those of us who favor the benefits of decentralization (higher shares of renewables, less market power, product differentiation, resilience etc.), the centralization targeted by Eon and RWE might be a step in the wrong direction. In our opinion, it is less important how RWE proceeds with the generation business since this business model is focused on conventional generation which does not offer any solutions for the overall challenges from climate change.

More importantly, we should observe how Eon uses its market power: Will it evolve into an innovation engine for energy transition or will it impose market entry barriers for those innovators that strive to make decentralized the energy transition a success?

Editor’s Note:

Marius Buchmann holds a Ph.D. in energy economics and works as Post Doc at Jacobs University in Bremen, Germany. He writes about energy on his blog Enerquire. This article was first published on Enerquire and is republished here with permission.

Lithium-ion battery energy storage facility in the US

A world of low-cost batteries will transform the way the electricity and automotive industries operate and how homeowners, businesses and utilities produce and use power, write Eric Hittinger and Eric Williams of the University of Rochester. What is more, their research shows that storage is “future-proof” – it works no matter how the energy system evolves. Article courtesy The Conversation.

The market for energy storage on the power grid is growing at a rapid clip, driven by declining prices and supportive government policies.

Based on our research on the operation and costs of electricity grids, especially the benefits of new technologies, we are confident energy storage could transform the way American homeowners, businesses and utilities produce and use power.

Balancing acts

Energy storage in this context simply means saving electricity for later use. It’s like having a bunch of rechargeable batteries, but much larger than the ones in your cellphone and probably connected to the grid.

After annual average growth of about 50 percent for five years, the U.S. electricity industry installed a total of 1 gigawatt-hour of new storage capacity between 2013 and 2017, according to the firm GTM Research. That’s enough to power 16 million laptops for several hours.

While this amount of storage is less than 0.2 percent of the average amount of electricity the U.S. consumes, analysts predict that installations will double between 2017 and 2018 and then keep expanding rapidly in the U.S. and around the world.

To see why this trend is a big deal, consider how electricity works.

Without the means to store electricity, utilities have to produce just enough to meet demand around the clock, including peak hours

It takes a hidden world of complexity and a series of delicate balancing acts to power homes and workplaces because the grid has historically had little storage capacity. After being generated at power plants, electricity usually travels down power lines at the speed of light and most of it is consumed immediately.

Without the means to store electricity, utilities have to produce just enough to meet demand around the clock, including peak hours.

That makes electricity different from most industries. Just imagine what would happen if automakers had to do this. The moment you bought a car, a worker would have to drive it out the factory gate. Assembly lines would constantly speed up and slow down based on consumer whims.

It sounds maddening and ridiculous, right? But electric grid operators basically pull this off, balancing supply and demand every few seconds by turning power plants on and off.

That’s why a storage boom would make a big difference. Storage creates the equivalent of a warehouse to stow electricity when it is plentiful for other times when it is needed.

Stretching power

Energy storage can help in a variety of ways, essentially serving as a Swiss Army knife for electricity grids. It can help balance short-term power fluctuations, manage peak demand or act as a backup to prevent or recover from power outages.

As utilities, businesses and consumers bring more renewable energy online, the grid may become harder to balance without additional storage

And it can be deployed at any scale and at any point in the grid, from a small home storage system to a pumped hydroelectric reservoir big enough to power a small city. While storage actually consumes a little electricity rather than producing any, it makes the electricity business more economically efficient. As the volume of storage grows, we expect grids to become more stable and flexible.

Storage may also make a big difference with electricity generated through solar or wind power – which can only be harnessed when the sun is shining and the wind is blowing.

But, in general, it isn’t necessary for that purpose yet. While those industries are growing quickly, wind power generates only about 6 percent of U.S. electricity and solar less than 2 percent.

Electricity grids can currently use almost all of that power as it is produced.

Grid operators, accustomed to managing the variable supply and demand for power, can manage the extra unpredictability they get from wind and solar energy now. But as utilities, businesses and consumers bring more renewable energy online, the grid may become harder to balance without additional storage.

Once energy storage scales up, utilities will meet peak demand more easily with less total capacity and fewer power plants

To be sure, hydroelectric plant operators have been storing power for a long time. The U.S. has the capacity to store some 22 gigawatts in pumped hydropower, about 2 percent of U.S. generating capacity. Yet its reliance on large water reservoirs, which can’t be easily constructed near power markets, limits the growth potential of this energy option.

Competing with natural gas

Once energy storage scales up, utilities will meet peak demand more easily with less total capacity and fewer power plants. If they can rely on storage to supply power during high-demand hours instead of building new power plants, it can save money all around.

But storage isn’t the only game in town – other technologies offer similar benefits. Utilities can install new transmission lines or rely on flexible natural gas, which is essentially the biggest competitor for energy storage.

Natural gas generation produces about a third of the nation’s electricity today and provides many of the same benefits as storage since these power plants are easy to switch on and off. The relatively low prices for natural gas, less than half of what they were a decade ago due to widespread hydrofracking, have probably slowed energy storage growth until now.

If storage gets cheap enough, storage could threaten the economics of natural gas generation

Natural gas has become increasingly popular for power generation, displacing demand for coal since 2000. But if storage gets cheap enough, this equation may flip and storage could threaten the economics of natural gas generation.

Help from the government and better batteries

One reason why this industry is growing is that it’s getting a boost from the government.

California, Maryland, New Jersey and Nevada are subsidizing storage, mandating its adoption or both. A similar measure is pending in Hawaii’s legislature.

And despite the Trump administration’s efforts to maximize fossil fuel extraction, the federal government is now laying the regulatory groundwork for the storage industry to compete directly in open wholesale energy markets for the first time.

Improvements in technology have made a difference, too. Battery technology, led by the same lithium-ion design that powers mobile phones, is making big strides and getting much cheaper.

The grid currently has relatively little storage for the same reason that only about 200,000 of the 17.2 million vehicles Americans bought in 2017 were electric. It’s expensive today

Lithium-ion batteries are both responsible for most of this new wave of grid-connected energy storage and the critical component inside the rapidly growing number of American electric vehicles. For example, the lithium-ion battery used in the the Tesla Powerwall, a home battery system, is the same as the one the company uses in its vehicles.

Grid-scale lithium batteries often differ from those in cars but use the same basic technology. The price of utility-scale lithium-ion battery systems fell 40 percent in just five years to around US$1,200 per kilowatt-hour in 2015 from roughly $2,100 in 2010 and are expected to continue falling.

The future

The grid currently has relatively little storage for the same reason that only about 200,000 of the 17.2 million vehicles Americans bought in 2017 were electric: It’s expensive today.

Electric vehicles do not yet save money for most U.S. drivers. But market experts project that electric vehicles ownership will cost less than standard vehicles powered by gasoline within a decade and continue getting cheaper after that.

Likewise, for the electricity grid, if storage gets cheap enough, its potential market could expand from 1 gigawatt-hour to dozens or even hundreds of gigawatt-hours.

If or when that happens, wind and solar power would become more competitive, increasingly displacing both coal and natural gas – now the nation’s two top sources of electric power.

No matter what happens, we believe that storage is “future-proof” because it works well on the current grid and with a wide variety of other technologies

And this cheaper storage would also make electric vehicles more affordable, reducing the amount of gasoline and diesel Americans consume. The electricity and automotive industries operate nearly the same way they did 50 years ago. But a world of low-cost batteries would change them both in exciting and unprecedented ways.

No matter what happens, we believe that storage is “future-proof” because it works well on the current grid and with a wide variety of other technologies. If the wind and solar industries keep up their current momentum (and they probably will), storage will become even more valuable.

But if the grid goes another direction – relying more on large and expensive generation plants, for example – storage would make it easier to manage peak demand without surplus capacity. Even if we can’t say exactly what the grid of the future will look like, we are pretty confident that storage will keep it humming in new ways.

Editor’s Note:

Eric Williams is Associate Professor of Sustainability at Rochester Institute of Technology. Eric Hittinger is Assistant Professor of Public Policy at the same institute.

This article was first published on The Conversation and is republished here with permission from the authors.

Collapsed electricity pylon after a tornado in Australia

A low-carbon world is an electrified world. But electricity has an Achilles heel: it is vulnerable. And will become more so as digitalization progresses and extreme weather increases, notes Mark Byrne of the Total Environment Centre in Australia. To reduce vulnerability, Byrne believes we need to create a system of enmeshed micro-grids. Keywords: “mutual interdependence”.  

Recently it was reported that a political dispute between Serbia and Kosovo is sapping a small amount of energy from the local grid, causing a domino effect across the 25-nation network spanning the continent from Portugal to Poland and Greece to Germany.

“The deviation from Europe’s standard 50 Hz frequency has been enough to cause electric clocks that keep time by the power system’s frequency, rather than built-in quartz crystals, to fall behind by about six minutes since mid- January.”

Fragility of complex systems

This is a good example for a phenomenon known as the fragility of complex systems: the tendency for multilayered and interconnected systems like electricity grids, transport networks (think gridlock) and the world health system (think pandemics and antibiotic resistance) to become increasingly prone to failure as layers of organisation and connectivity are added.

Why? Complex systems have more levels and points of vulnerability. There are more things that can go wrong. And when things do go wrong, the impacts can spread further throughout the system than would be the case with a simpler or more localised system.

To give an example, one of the advantages of electric cars is that electric motors have few moving parts, while internal combustion engines have hundreds. Electric engines are also more efficient.

Simplicity doesn’t always equal efficiency, but it does usually equal reliability. A system with multiple layers of complexity is more vulnerable to a breakdown.

In South Australia, in 2016 the impact of a localised severe weather event led to a statewide “black system” due to the cascading impacts of supposedly protective responses higher up in the system

The counterargument is that complex systems usually have correspondingly greater layers of inbuilt safeguards and redundancies that result in the maintenance of a high level of resilience. In the case of weather and climate or natural ecosystems, resilience is the product of millions of years of evolution.

Even they have limits and breaking points, though, as we are seeing by pumping more CO2 into the atmosphere than it can cope with.

In human-made systems, resilience usually develops by trial and error. Fellow aficionados of plane crash television programs will know that it usually takes three things to go wrong before a big modern plane goes down. But mistakes often have to be made before technology, regulation or behavioural change results in an increase in system resilience.

This process – call it breakdown, learning and repair; or disease, diagnosis and treatment – needs to be repeated as system complexity increases over time and space. And every such every failsafe or backup system adds its own layer of cost and complexity.

Growing complexity

Electricity, in essence, is not complex. But the Promethean process of turning the physical properties of electromagnetism into circuits to safely harness its properties for power, lighting, heating, electronics and so on adds a layer of complexity.

It’s like putting lightning in a box. Converting from DC to AC or vice versa complicates the process.

This system becomes still more complex when we construct a geographically dispersed grid, and have to install substations to distribute energy and to deal with voltage and frequency fluctuations in a system that must be synchronised over thousands of kilometres to within tens of milliseconds.

In Australia’s electricity system, grid resilience has typically been equated with short-term security and reliability, and maintained by tweaking the technical and operational parameters of the system

And interconnectors, too, when we want to link previously separate regions.

A financial market to trade energy creates yet another layer of complexity: the spot and futures markets; forecasting and settlements; inter-regional trading; hedging contracts and power purchase agreements.

More recently, the rooftop solar revolution has led to two-way energy flows, including times and places where the net energy flow is back up the system to substations – something they were not designed for but must be adapted to suit.

Even more layers of complexity are emerging, including:

• the growth of variable, non-synchronous large-scale renewable energy generation;
• the rise of home automation (often connected to global IT systems) and Internet of Things-enabled appliances and devices; and
• the need for the energy system to respond to the increasing variability of Australia’s climate (e.g., by having greater strategic reserves to call on during heatwaves).*

The classic case of fragility in Australia’s grid is the blackout in South Australia on 29 September 2016.

To put it simply, the impact of a localised severe weather event (“two tornadoes with wind speeds between 190 and 260 kilometres per hour tore through a single-circuit 275-kilovolt transmission line and a double-circuit 275kV transmission line, about 170km apart”, says the ABC) led to a statewide “black system” or total shutdown due to the cascading impacts of supposedly protective responses higher up in the system.

The responses were, in the case of the protection settings of the wind farms involved, apparently too conservative or sensitive.

In other words, the multiple layers of technical complexity in a system undergoing rapid change, and its dispersed nature, resulted in the impacts being felt far more widely than they might otherwise have.

Climate change responses

In Australia’s electricity system, grid resilience has typically been equated with short-term security and reliability, and maintained by tweaking the technical and operational parameters of the system.

But a range of potential threats to electricity systems – climate change; cyberattacks; and an economic crisis –  is increasingly likely to expose the fragility of this complex system.

Let’s consider only the first of these. We know that higher summer temperatures are increasing the incidence of thermal overload on transformers; and that the greater incidence and intensity of bushfires and severe storms is increasing the risks to poles and wires.

There are other impacts, though, that we need to consider, including coastal inundation, flooding and reduced rainfall in some areas.

“The current market design is not sufficiently valuing resource characteristics of flexibility and dispatchability”

The industry has already turned its mind to these risks. Responses to date include risk assessment planning, recommending more interstate interconnectors* to provide backup supply in case of regional outages; taking customers off grid in areas with high bushfire risk; and speeding up the rollout of smart meters, which enable easier fault identification.

All well and good, but there is so much more we need to think about and do.

The best attempt to date to plan for a more resilient grid is the CSIRO/Energy Networks Association’s 2016 Network Transformation Roadmap. It recognised the increasing complexity of this ‘system of systems’ and proposed solutions to deal with the technical challenges.

It didn’t, though, specifically consider increasing system complexity to be a risk in itself.

Last week the Australian Energy Market Operator (AEMO) took a big step in this direction with the release of its “observations” on operational and market challenges to reliability and security in the National Electricity System (NEM).

AEMO is concerned that “the current market design is not sufficiently valuing resource characteristics of flexibility and dispatchability” to respond to increasing variable renewable energy (VRE) and climate change impacts, and proposes a number of market reforms to improve system security and reliability.

Balancing independence and dependence

At a conceptual level, AEMO’s response amounts to increasing resilience by building more safeguards or levels of redundancy into the system as it becomes more complex and unpredictable. This is a valid response, but in the longer term there are others worth considering.

Abandoning the system – by going off grid, say – isn’t a financially viable option for most people at this time. Neither is it a good use of resources, with excess solar energy going to waste when the batteries are full and the batteries sitting idle much of the time.

After Hurricane Maria ripped up Puerto Rico’s grid last September, Elon Musk claimed that Tesla’s solar and battery systems could restore power across the island.

Essentially Tesla would replace the old, unreliable, oil-dependent centralised grid with a series of offgrid systems or microgrids.

Going entirely local is not always the best solution, though. Aside from the relatively high cost and inefficiency (i.e., low load factor) of offgrid systems, even an isolated microgrid may not always be the best solution.

At present, most towns and cities are unable to operate in islanded mode. Being designed to be supplied from a distance, they simply shut down if the centralised supply is cut

A big fat hurricane is one thing, but if the outage is caused locally (a bushfire or tornado, say), the lack of a connection to a centralised grid could be a minus, not a plus.

Logically, a grid that is composed of interconnected microgrids that can be islanded from the main grid when a crisis strikes would appear to be the happy medium between a grid that is either totally centralised or entirely composed of offgrid systems.

That might work for individual households and businesses, and for purpose-built microgrids. At present, though, most towns and cities are unable to operate in islanded mode. Being designed to be supplied from a distance, they simply shut down if the centralised supply is cut.

To work differently, they need more local generation and metering and communication systems that are suited to part-time or backup microgrid use; and rules that recognise the costs and benefits of the local use of the system.

Ideally, we would eventually see a system of nested or meshed microgrids at different levels of the system, from individual buildings through individual feeders to distribution and zone substations covering whole towns, suburbs or sub-regions. It sounds expensive, but then, so are prolonged outages.

These microgrids could talk to and supply each other without the need for centralised hub-and-spokes communications.

Valuing resilience

Other responses to increase system resilience in the face of climate change might include:

• Less investment in areas or assets at greatest risk of climate change impacts.
• Ensuring there is a variety of scales, locations and types of renewable generation and storage available.
• Undergrounding power lines.
• Decreasing reliability standards where this might favour a greater variety of supply and distribution types.
• And, as ever, ensuring that consumers are better incentivised to use less energy to meet their needs.

All fine in theory; but how do we value resilience in the grid?

In other words, how do we place a dollar or other value on long-term planning and investments into infrastructure that takes such threats seriously?

There is nothing in the National Electricity Rules to incentivise taking climate change impacts into account when making investment decisions – particularly in relation to high impact but relatively low probability events like severe weather or longer-term climatic changes.**

An example of the problem. In AEMO’s otherwise excellent Integrated System Plan Consultation, climate change raises only one single entry, and that relates only to “climate and energy policy uncertainty”.

As a result, the Snowy region and adjacent regions in New South Wales and Victoria are mooted as potential Renewable Energy Zones.

If you look at the Federal Government’s Climate Analogues tool, 2050 projections for the Snowy region show warming of up to 3 degrees and a reduction in rainfall of up to 15 percent.

This might be the worst case scenario, but globally, climate change data are mostly tracking at the upper end of earlier IPCC projections, so we should take this prospect seriously.

Yet if you then look at the Snowy 2.0 Feasibility Study, how many references are there to climate change and reduced rainfall as risks potentially affecting the engineering and financial viability of this $4 billion-plus taxpayer-funded project?

As far as I can tell, none. As a potential stranded asset, that ranks up there with the National Broadband Network (NBN).

A holistic vision

Indian Buddhism spoke of a vast net of jewels hanging from the palace of the great god Indra. Each jewel reflects and is reflected in every other jewel in an infinite, multidimensional net of hologram-like connections.

Whether you think of each jewel as a building, a community or a substation, the vision is one of neither total dependence nor complete independence but mutual interdependence.

* See, e.g., AEMO’s 2016 National Transmission Network Development Plan

** For instance, in the regulatory investment tests (RITs) for transmission and distribution.

Editor’s Note:

Mark Byrne is Energy Market Advocate at the Total Environment Centre.

This article was first published on Reneweconomy.com.au and is republished here with permission from the author.

New scenario sees little room for shale gas in Europe

For the first time ever, the gas and electricity transmission system operators in the EU have joined forces to develop a series of joint scenarios for the European energy system out to 2040. Takeaways: high carbon prices, no shale gas, hardly any CCS, less gas in heating/more gas in transport, less nuclear and more biomethane and power-to-gas. The scenarios matter because they will ultimately help decide which energy infrastructure projects get EU support. This article is published in full on our premium website Energy Post Weekly in Sonja van Renssen’s weekly Brussels Insider.

 The European bodies representing network operators for gas and electricity – ENTSO-G and ENTSO-E – have teamed up for the first time to develop a series of joint scenarios for the future of the European energy system out to 2040. These scenarios will form the basis for their respective Ten Year Network Development Plans (TYNDPs) due out this autumn.

Those plans will in turn support the European Commission’s next selection of Projects of Common European Interest (PCIs) in 2019. Those projects get put on a regulatory fast-track and can apply for EU funds. All this to say that this latest bout of modelling in the EU capital is not without consequence.

In their press release on the joint scenarios on 30 March, the ENTSOs recommend them to “any party wishing to perform their own analysis of future policies, market designs or technologies”. They plan to “take initiatives to increase their usability” and talk about how “transparent” their scenarios are.

In their TYNDP 2018 Scenario Report, they explain an elaborate stakeholder consultation process and cite input from industry, NGOs, National Regulatory Authorities (NRAs) and Member States. It appear that here, finally, is an alternative to the much criticised – also for its lack of transparency – PRIMES modelling that has been the basis for EU energy policy to date.

The ENTSOs have actually included one of the Commission’s PRIMES scenarios alongside their own three scenarios for the future. More on that in a moment. First, all the scenarios make a few basic assumptions. They all assume, for example, that European greenhouse gas emissions will need to be cut by 80-95% by 2050.

That’s current EU policy, even if Green MEP Claude Turmes is trying to introduce a net zero emissions goal by mid-century via a new governance regulation in the Clean Energy Package. Realistically, the goal is likely to be revisited next year, when EU leaders have asked the European Commission to come up with a new 2050 climate strategy.

A second foundation for all the scenarios is that they are “broadly technically feasible; for instance making it possible to maintain the energy balance at all times in each country”, the report says.

To the scenarios themselves then. The ENTSOs have come up with three, which they develop for 2020, 2025, 2030 and 2040:

1. Sustainable Transition, or let’s call it the GAS scenario. It’s the most conservative scenario, with a big role for gas. It’s the preferred decarbonisation option even for passenger cars. This scenario foresees defining roles for national regulation, emissions trading and subsidies, and maximum use of existing infrastructure. The EU is only just on track to its climate goals in 2030 and will need to up the pace after 2040. Economic growth is moderate.

2. Distributed Generation, or the PROSUMERS scenario. This one’s all about small-scale generation and batteries. Consumers are engaged and empowered. This scenario has the highest penetration of electric vehicles and the highest electricity demand. There is substantial demand side flexiblity. There is also a strong EU Emission Trading Scheme (ETS). Both electricity and gas are important in the transport sector; hybrid heat pumps are the preferred option for heating.

3. Global Climate Action, or in our view, the LARGE-SCALE ELECTRIFICATION scenario. This imagines a world on-track to rapid decarbonisation, with large-scale renewables development in both the electricity and gas sectors. There is a big role for a strong CO2 price and a steady decline of demand for gas in heating thanks to electrification. Gas retains a role in transport however. This is the secenario with the strongest development of power-to-gas.

Finally, the Commission’s PRIMES scenario that is included alongside is “EUCO 30”. It models the minimum that the EU has committed to deliver by 2030: 27% renewables (still backed by many Member States; the Parliament wants 35%), 30% energy efficiency (the Parliament also wants 35%) and a 40% greenhouse gas emission cut (the Parliament’s preceding demands would automatically bump this up to 47.5%).

In practice, the parameters for this scenario resembled those for scenario 3 above so EUCO 30 will replace it for the TYNDP.

Below is our take on interesting points in the new modelling exercise, beyond what’s already been noted above.

To read the rest of this article, go to Energy Post Weekly.

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As the number of “prosumers” with batteries grows, huge opportunities will be opened up for aggregators who will be able to optimize these behind-the-meter-assets, writes energy expert Fereidoon Sioshansi, publisher of newsletter EEnergy Informer. Sioshansi explains how this development is likely to transform the electricity sector.

If the number of prosumagers grows, as expected, they will no longer be dependent on net kWh purchases from the grid – in fact some may become net exporters. For prosumagers (a prosumager is a “prosumer” who has made additional investments in distributed storage, usually in the form of batteries – editor), the critical service provided by the network is no longer energy per se but rather balancing services, voltage and frequency support, power quality and, most important, service reliability. After all, prosumagers will not cut the cord as they continue to rely on the network during extended periods when there is no sunshine and their batteries dry up.

Changing values

This fundamentally changes the value proposition for being connected to the network. It will no longer be about energy, the net kWhs, but about service reliability, not worrying about how much juice is left in the battery before the lights go out. It is the equivalent of “range anxiety” for current electric vehicle (EV) owners on a long cross county road trip.

The grid becomes a form of insurance and backup for prosumagers who essentially operate their own mini micro-grids

In turn, this requires fundamental new thinking about the value of service and how much should prosumagers pay when and if they consume very few net kWhs, if any. In this context, volumetric tariffs make little sense while reliability of service makes a lot of sense and has a lot of value. The grid becomes a form of insurance and backup for prosumagers who essentially operate their own mini micro-grids.

That, however, is not the end of story as two other developments are rapidly emerging:

• Aggregation and optimization of distributed loads, generation and storage; and
• Intermediation and peer-to-peer trading through open platforms.

The former is already here as businesses emerge to aggregate the distributed loads, generation and storage of multitudes of consumers, prosumers and prosumagers while remotely monitoring, controlling and managing the portfolio of assets in real time. This allows the intermediary not only to optimize the virtual dispatching of the diverse collection of resources but to monetize and capture their value.

New opportunities

Aggregation and optimization of massive portfolios of behind-the-meter assets is likely to grow as a business opportunity because individual prosumagers will have limited capabilities and/or financial incentives to mess around with capturing the modest value streams of their own mini micro-grids, creating a huge opportunity for the aggregators.

It is the equivalent of the powerful network effect in social media. Facebook or LinkedIn may not be the best, but who wants to set up a second social network when everyone is already using these? The exponential power of large numbers favors aggregation of massive portfolios. Scale matters.

Numerous companies have emerged in the past few years to take advantage of the collective capacity of hundreds, thousands – and, in the future possibly millions – of diversified loads, distributed generation and storage. While the business models vary, virtually all are focused on remotely monitoring individual customer loads, generation and storage, managing and optimizing the aggregated portfolio and maximizing the inherent flexibility and diversity of the behind-the-meter assets.

By doing so, they can monetize streams or stacks of value

• By charging customers’ batteries when wholesale prices are low, or discharging them when the opposite is true;
• By adding flexibility to loads by scheduling energy intensive devices or operations – say preheating or pre-cooling buildings depending on the prevailing prices; and
• By supporting local distribution networks at times and locations when/where they are stressed.

In theory at least, these and a multitude of other services can be offered at substantial cost savings to participating assets in the portfolio with little or no inconvenience or service degradation.

How? Through remote real-time monitoring of multitudes of devices on customers’ premises, which can be analyzed and optimized by software using artificial intelligence (AI) and machine learning (ML). There is no other way to do it – the task gets quickly complicated.

The aggregator’s business model is based on sharing a portion of the achieved savings from the optimized portfolio with the participating customers. 

Participating customers define their operating requirements – such as: I don’t want the lights to go out during business hours, or the freezer to thaw, or the water storage tank to be empty or overflow, or the elevators to get stuck between the floors, or the warehouse get too cold or too hot. In practice, the software gets to know each customer intimately over time. Some fine-tuning may be required. But once the basic parameters are understood, the software essentially takes over, refining and optimizing so that the customers are not even aware that their operations and equipment are being remotely monitored, controlled and manipulated. Nor do they care that the aggregator is making money off the portfolio, so long as their energy service needs are met at a cost lower than they could do on their own.

The aggregator’s business model, of course, is based on sharing a portion of the achieved savings from the optimized portfolio with the participating customers. It is win-win, indeed win-win-win if the benefits to the network are included.

How much can be gained and shared is an open question since many technical, operational, contractual and regulatory hurdles need to be resolved. And there are risks to all parties as investments have to be made in remote sensing, real-time communication, software development as well as taking measures against cyber-security and other risks. Most important, the participating customers have to get comfortable with the aggregators and vice versa.

Opportunities in open platforms allowing peer-to-peer (P2P) trading and transaction energy – are likely to follow along with business models to monetize the value streams. While promising, they are mostly work in progress.

Different approaches

Eventually, the two approaches may merge. While some customers with certain applications – say an independent system operator (ISO) – may prefer to manage their own critical requirements – say optimizing the locational pricing interface with a distribution system operator (DSO) in real-time – using an open platform providing real-time locational price visibility – others may prefer to delegate the implementation details to a platform service provider who is better at it.

On that note, providing real-time locational price visibility on an open or public platform has already emerged as a viable business (box). Start-ups such as London-based Open Utility and its competitors are frantically exploring viable business strategies and service options. The key, as with everything else in business, is to find a way to make the service profitable by monetizing the streams of value in the value chain.

Whether aggregating and optimizing distributed assets or offering platforms with real-time locational price visibility, scale is critical to success since the values derived from individual transactions are likely to be modest at best.

 The focus of action is shifting from managing generation assets to managing behind-the-meter assets

It is fair to say that the focus of action is shifting from managing generation assets – much of it coming from variable renewable generation in the future and thus essentially unmanageable – to managing behind-the-meter assets.

Why has it taken so long for this realization to sink in? Partly because of inertia in an industry that is not used to innovating or taking risks and partly because regulators are even more risk averse – and possibly further behind in acknowledging the changes that are impacting the industry.

This explains why much of the changes expected are not likely to come from within the power sector but from outsiders, start-ups and newcomers who are not encumbered by the industry’s lethargic culture or bound by the regulatory status-quo. They will, however, have to learn to deal with both. There is no easy way around that.

How to make a profitable business out of a platform or an app?

This was not an easy question to answer before Uber and Airbnb emerged as multi-billion-dollar companies.

Today, of course, many successful enterprises have emerged making good money by doing virtually nothing – by relying on others to do the work. For example, consider platforms offering flower delivery. They do not grow the flowers, nor transport them, nor make the flower arrangements, nor bother with the final delivery. They merely collect money and direct others to do the hard work. They need no assets, no hardware, no physical presence – which is why successful ones with massive scale can be enormously profitable. The same goes for airline and hotel booking platform operators, cousins of Airbnb.

Even more striking, however, are food delivery companies such as Just Eat in UK or its counterparts such as GrubHub, Delivery Hero and Takeaway.com. According to an article in the Wall Street Journal (1 Mar 2018), Just Eat enjoys a 20% operating margin for doing virtually nothing. It offers a platform on which customers can order food from participating restaurants. As described in the WSJ article, these intermediaries

“… make money by charging restaurants a cut of orders placed through their platform. The restaurants, for the most part, handle getting the food to the customer.”

Amazing. No kitchen, no cooking, no physical assets, no rent, no hassle, no delivery and a 20% operating margin. Too good to last? The same article points out that, “Traditional platforms need to invest in delivery or risk having their lunch eaten.”

Delivery, especially for hot and perishable food, is – you guessed it – a capital intensive and low margin business. One option is to find other intermediaries to handle the drudgeries, say Uber Eats or its counterparts. Many restaurant chains, of course, have internalized the delivery service – such as Domino Pizza – where most of the business is take-away.

Why talk about flower or food delivery business in an energy newsletter? Because platforms will be coming to the electricity marketplace sooner than you may think, and they will eat the incumbents’ lunch as has happened in other industries.

Source: Food delivery gets a new threat, by Stephen Wilmot, The Wall Street Journal 1 Mar 2018

Editor’s Note

Fereidoon Sioshansi is president of Menlo Energy Economics, a consultancy based in San Francisco, CA and editor/publisher of EEnergy Informer, a monthly newsletter with international circulation. This article was first published in the April 2018 edition of EEnergy Informer and is republished here with permission.

Electricity distribution networks in Europe run at well below their full potential, finds a new study from the Regulatory Assistance Project (RAP). The findings show that the unused network capacity could be utilised for charging electric vehicles with little or no need for additional capacity. Smart pricing and smart grid technologies will be the keys.  

“Waste not, want not,” goes the old saying. Airbnb and Uber have leveraged that principle—exploiting unused capacity in existing homes and cars—to build businesses that, in less than ten years, are together worth over $100 billion. So why not apply the same principle to electricity networks?

A lot of unused capacity is available on existing networks, capacity that is especially well suited to accommodating electric vehicle charging. A combination of appropriate pricing and smart technology deployment could help drive the best use of existing assets, helping to minimise the costs of the energy transition.

Shape of e-mobility uncertain

Transport and energy stakeholders and policymakers alike have identified the electrification of road transport as a key route to achieving decarbonisation of mobility. The combined effect of rapidly declining battery and electric vehicle (BEV, or simply EV) costs and improvement in their performance makes them a promising option.

Shifting EV charging to periods when existing resources are readily available would keep incremental investment in infrastructure to a minimum

EV adoption rates could stall, however, if infrastructure needs are gauged based on worst-case assumptions about impacts on electricity demand. Many variables factor into the EV equation. EVs and related technologies, such as chargers, keep improving; fuel-cell electric vehicles will compete to play a role; and new developments are reshaping road transportation, including a trend toward vehicle sharing. The investments needed to electrify transport will depend on how these and other trends play out.

The good news is that EVs are a flexible load that can be charged at any hour when the vehicle is not in use. Shifting EV charging to periods when existing resources are readily available would keep incremental investment in infrastructure to a minimum. All consumers, not just those with EVs, would benefit from spreading the costs of existing infrastructure over more load and minimising risky new investment.

Utilisation of existing networks low

In our study Treasure Hiding in Plain Sight: Launching Electric Transport with the Grid We Already Have, we focused on distribution networks and found that existing networks generally run at well below their full potential.

We looked at the “network utilisation rate”—that is, actual throughput as a percentage of maximum possible throughput over a given period—for three areas in Europe: the Westnetz and Edis networks in Germany, distribution network. The results are estimates because, surprisingly, few distribution system operators (DSOs) monitor the utilisation rate of their networks.

Our analysis demonstrates that ample network capacity is available to take up new loads such as EVs

The graph below presents the results for three different timeframes: the annual utilisation rate, the rate for the peak demand day, and the rate for a typical summer day. The results suggest that these systems are operating at 50-70% of their potential. To place this in perspective, all current light-duty vehicles could be electrified with little or no need for additional network capacity. Furthermore, because we employed the conservative assumption that peak demand on the system is equal to the maximum capacity of the system, the rates presented here likely overestimate actual rates of utilisation. (This was a system-wide estimate and does not preclude the likely need for specific localized reinforcement.)

Our analysis demonstrates that ample network capacity is available to take up new loads such as EVs. Even on peak demand days, significant load can still be added outside peak hours, which are of relatively short duration, as shown in the next two figures. So how can we take advantage of this?

Both pricing and technology essential

Policy will be needed to drive exploitation of this existing network capacity for transport electrification, either directly by EV owners or by enabling innovative new business models. Two equally critical policy levers are available.

Time-differentiated, usage-based (or dynamic) pricing for both energy and delivery is one key. It empowers consumers to take action and save on their electricity bills, while benefiting the system as a whole. While dynamic pricing for energy has garnered increased attention in recent years, dynamic pricing for networks has gained little attention. On the contrary, recent trends are toward capacity-based, fixed network charges in several places in Europe.

In the short to medium term, time-of-use and critical peak pricing are feasible options to extract as much value as possible from network assets; a wealth of experience exists for such tariffs. In the longer term, as our power system becomes “smarter,” more sophisticated pricing, including real-time pricing, provides a more sustainable solution.

It will be difficult to assess the potential for these measures and gauge their effectiveness unless DSOs and their regulators better monitor network utilisation

The other key is timely deployment of enabling network technology. Pilot projects for dynamic pricing have demonstrated that the benefits of smart prices increase when accompanied by smart technology, and vice versa. Consumers also sustain new behaviours longer when automated controls are available, through either individual adopters or demand aggregators. Policymakers and regulators should consider financial incentives and other measures to spur investment in smart technologies that help deliver public policy objectives, and they should remove all barriers to the active participation of aggregators in all markets.

Adopting proven models for dynamic network charging can spur innovative new service business models whilst also ensuring fair network cost recovery

Regulators and relevant authorities should not overlook consumer education. Educational programmes will be necessary to ensure consumers are aware of and can take full advantage of the opportunities smart pricing and technology provide.

Monitoring the utilisation of network investments key

It will be difficult to assess the potential for these measures and gauge their effectiveness unless DSOs and their regulators better monitor network utilisation. Examples of best practices can be found in markets like Sweden, where regulators have implemented regular monitoring coupled with outcomes-based regulation. Outcomes-based regulation is essential to ensure accountability, provide appropriate incentives, and identify any needed adjustments to regulatory frameworks.

So, what are we waiting for?

Exploiting unused existing capacity to integrate new electric transport at least cost and least risk to consumers is a no-brainer. Doing so, however, requires policymakers and regulators to act now. Network tariff design should reward rather than punish EV owners for charging behaviour that benefits overall system efficiency.

Adopting proven models for dynamic network charging can spur innovative new service business models whilst also ensuring fair network cost recovery. Policy support for deployment of appropriate technology will ensure that smart tariffs deliver maximum and sustainable benefits. Policymakers have an opportunity to set the table for the next great “sharing economy” success stories.

Editor’s Note:

The Regulatory Assistance Project (RAP) is a globally operating independent and nonpartisan team of experts. 

Michael Hogan is a senior advisor to the Regulatory Assistance Project (RAP), working on issues related to power market design, integration of low-carbon supply, system planning, and demand response in the United States and Europe.

Christos Kolokathis, Associate, provides research, analysis, and technical assistance to RAP’s Europe team on issues related to power markets, power sector emissions, demand response, and integrating renewables into the grid.

Wind turbine construction

As the cost of renewables goes down, the old approach of subsidizing generation no longer makes sense, writes Johannes Urpelainen of The Center on Global Energy Policy. We need a revolution in energy policy. Article courtesy The Center on Global Energy Policy.

Driven by decades of aggressive government policy, renewable electricity generation has grown rapidly. This expansion has, in turn, contributed to lower costs and renewable power that is no longer prohibitively expensive. In fact, wind and solar power are already cheaper than coal-fired power generation or natural gas power generation.

As the primary obstacles to a renewable energy transition is no longer cost, the old approach of subsidizing renewable generation until it can compete with fossil fuels no longer makes sense. Rather, the challenge stems from the need to integrate intermittent power supplies into the electric grid, and governments interested in clean energy and decarbonization can use policy to remove systemic obstacles to growth.

Governments need to invest in technology innovation to support energy storage and other measures to mitigate the problem of intermittency

Governments can address this problem with real-time electricity pricing, two-way metering, demand-side management to match supply and demand, and with policies that separate electricity consumption from the cost of system maintenance.

Most importantly, governments need to invest in technology innovation to support energy storage and other measures to mitigate the problem of intermittency. These policies can unleash an era of renewable energy progress and thus contribute to climate mitigation, clean air, and energy security.

The cost of renewable energy has fallen over time

In 2008, both solar and wind power were very costly propositions (Lazard 2014). In 2009, the levelized cost of wind electricity generation in the United States was $101-169 per megawatt-hour (MWh) and the same cost for solar power $323-394. The price of coal, on the other hand, was about $66-151 per MWh at the time.

By 2017, however, both the sun and the winds could offer affordable power (Lazard 2017). At that time, the costs of wind and solar power had, respectively, fallen to $43-48 and $30-60 per MWh. In a stark contrast, coal-fired power generation cost $60-143. Both wind and solar power had lower generation costs than coal.

It was not the invisible hand of markets that made renewable energy affordable

While these costs do not consider the need for storage or other problems with integrating intermittent power supplies into the grid, they do show that generation costs are no longer an obstacle to a comprehensive transition to a renewable power system.

These cost reductions have contributed to a global investment boom in renewables (IEA 2017). According to the International Energy Agency (IEA 2017), renewable generation capacity increased by about 165 gigawatts in 2016, accounting for two-thirds of all new capacity. This growth was worldwide with China, India, and the United States leading the way. Record-low auction prices for solar power in the Middle East, Latin America, and India fell as low as $30 per MWh.

Policy has played a key role in transforming renewable energy

It was not the invisible hand of markets that made renewable energy affordable. As our research in Renewables: The Politics of a Global Energy Transition (Aklin and Urpelainen 2018) shows, the cost reductions in renewable power generation have followed aggressive support policies in forerunner countries such as Germany, Denmark, and China.

Once the cost of renewable energy reached a critical threshold, governments around the world pushed it further down with auctions and other market-based mechanisms

When renewable energy was still expensive relative to coal and natural gas, governments used policies such as feed-in tariffs to offer generous benefits and reduce risk to renewable power producers. These were often high-cost policies, as Germans may have at times paid over twenty billion euros for their renewable energy feed-in tariff (Aklin and Urpelainen 2018), but they got the job done: renewable energy generation grew over time, and the costs fell precipitously.

Once the cost of renewable energy reached a critical threshold, governments around the world pushed it further down with auctions and other market-based mechanisms. Even though renewable energy was still more expensive than conventional fossil fuels, the cost difference was sufficiently small to encourage project developers to respond to competitive tenders and auctions. Unlike feed-in tariffs, auctions rewarded project developers with the lowest costs and thus led to accelerated technological and business innovation.

The time is ripe for another revolution in renewable energy policy

Renewable energy has by now achieved a certain momentum that will make it difficult to stop, despite the opposition it faces from some governments. But renewables still face major obstacles to the kind of exponential growth the world needs to avoid dangerous climate disruption.

Because of the intermittent nature of wind and solar power, going from marginal amounts of renewable power generation to a system that is dominated by renewables requires a policy revolution. In Germany, for example, intermittent solar and wind power accounted for almost 20% of all generation in 2016 (IEA 2017). At such levels, managing the intermittency becomes a critical policy challenge.

All electricity consumers should contribute to covering the cost of the electric grid regardless of how many kilowatt-hours they consume and produce

To address these challenges, new policies will need to encourage real-time pricing of electricity to avoid an oversupply of renewable power when the sun shines and the wind blows.

Importantly, policymakers need to look for ways to enable two-way metering to ensure that distributed power generators can sell their surplus to other consumers when demand is high. Policy should also include demand-side interventions to shift electricity consumption profiles such that demand meets the supply of wind and solar power.

Additionally, all electricity consumers should contribute to covering the cost of the electric grid regardless of how many kilowatt-hours they consume and produce. If consumers paid a fee for the costs of the electric grid, distribution power generation would not threaten the finances of grid maintenance. Quite to the contrary, two-way metering would enable micro-level power exchange between households and companies that both produce and consume renewables.

Markets alone cannot remove barriers to a carbon-free power sector

Finally, technological innovation remains a critical driver of renewable energy expansion. Besides improved policy and grid management, less expensive energy storage both on small and large scales would solve the problem of intermittency. Policies should support innovations that enhance the competitiveness of renewable energy, with a particular emphasis on battery storage.

While the cost of renewable electricity generation has collapsed, removing systemic obstacles to growth in renewable energy use requires a new generation of renewable energy policy. Markets alone cannot remove barriers to a carbon-free power sector, and governments around the world should adopt new strategies focused on solving the problem of intermittency. Such a policy revolution can unlock the full potential of renewable energy

Editor’s Note:

Johannes Urpelainen is a non-resident Fellow at the Center on Global Energy Policy, Columbia University in New York. In his full-time capacity, he is a tenured faculty member at SAIS (School of Advanced International Studies) at John’s Hopkins University in Washington, D.C. His research focuses on environmental policy, energy poverty, and international cooperation and institutions. He is an award-winning author of four books and over a hundred refereed articles on environmental politics, energy policy, and global governance.

This article was first published on the website of The Center on Global Energy Policy and is republished here with permission.

Windmills in Germany

Renewable energy generation is still on the rise in Germany, though at a much lower pace than in the years around 2010, writes Marius Buchmann of Jacobs University in a detailed overview of the German electricity market in 2017. Costs of the feed-in tariff are stagnating, notes Buchmann, but redispatch costs which grid operators incur to keep the system stable, reached a new record far above €1 billion. Courtesy of Buchmann’s blog Enerquire.

Recently Tennet, the Dutch transmission system operator which is responsible for a significant part of the German transmission system, published its report on the developments in the electricity markets in Germany and the Netherlands in 2017.  Within the following, we will briefly summarize the key findings of the report for Germany. If you are interested in the full picture, you can find the full report here.

Wholesale prices on the rise in 2017

We have already discussed here on enerquire that wholesale prices are under pressure from increasing shares of renewable electricity supply. In 2016, monthly average day-ahead prices in Germany fluctuated between 30 €/MWh and 20 €/MWh most of the time (from January to September 2016).

In comparison, the same prices stayed above 30€/MWh in 10 out of 12 months in 2017.  Figure 1 quite nicely illustrates that prices in the Central Western European bidding zone (CWE) have recovered accordingly, with a yearly average in 2017 above the level of 2015.

Figure 1: Monthly average of hourly day-ahead wholesale prices in the CWE region (TenneT 2018)

Additionally, we can learn from figure 1 that Germany (which is sharing a bidding zone with Austria till October 2018) has the lowest wholesale prices in the CWE. Especially in France and Belgium, monthly average prices differ more significantly between the winter and summer season (due to electrical heating) than they do in Germany and the Netherlands.

From day-ahead towards intraday-trading

There is an ongoing trend in electricity trading which is directly linked to renewable generation. The trading volume on the day-ahead market, especially in the German/Austrian bidding zone, is decreasing (See figure 2) while intraday trading volumes are increasing (see figure 3).

The mechanism behind this movement is quite straightforward. Predicting renewable generation 24hrs in advance is still rather imprecise. As a result, electricity from renewables is usually traded close to delivery when production can be predicted more accurately.

Figure 2: Annual trading volumes at day-ahead exchanges (Telnet 2018)

Figure 3: Intraday trading volumes in Germany/Austria and the Netherlands from 2015-2017 (TenneT 2018)

Figure 3 depicts that the annual trading volume on the intraday market in Germany/Austria has increased by more than 50% from 2016 to 2017 (ID EPEX auction in figure 3), while the hourly trading volume has increased by roughly 20% (ID EPEX hourly). Still, intraday trading for the German/Austrian bidding zone adds up to only 20% of the volume that is traded one day ahead for the same bidding zone.

Compared to the Netherlands, the intraday volume in Germany/Austria is quite significant. There are several drivers behind the increasing intraday trading in Germany. Most prominently, TSOs in Germany are obliged to sell all renewable generation in the day-ahead or intraday market.

The German/Austrian bidding zone split

In October 2018, Germany and Austria will become two separated bidding zones. The current baseload futures contracts (which are contracts that focus on long-term delivery, e.g. for the next 12 or 24 month and are often used for baseload power) for Germany and Austria in 2018 and 2019 show that prices are likely to decrease in Germany compared to the futures of the current German/Austrian bidding zone. Prices in Austria will potentially increase after the split.

Primarily, these price developments are driven by the larger market in Germany and different support schemes for renewable electricity supply. Figure 4 summarizes the price spread of baseload contracts valid from fall 2018 onwards between the new bidding zones of Germany and Austria compared with the current joined bidding zone Germany/Austria.

Figure 4: Price spread between different baseload futures for Germany and Austria (TenneT 2018)

Base load power plants under pressure from rising fuel costs

It is old news that the margins of conventional power generators have become smaller in Germany over the last five years. However, in 2017, the German power generation market faced some significant changes. Most prominently, prices for gas and especially for hard coal increased significantly.

Though the average price of natural gas increased by 20% from 2016 to 2017, the price level is still below the prices in 2015, which was a very unprofitable year for gas-fired power plants in Germany.

Even more interestingly, annual average prices for hard coal have jumped by 40% in 2017 compared to the prices in 2015 and 2016. This price increase for coal was mainly driven by China’s coal policy in 2017, which reduced global supply significantly. Though wholesale prices in Germany increased in 2017, the income for generators did not rise enough to compensate for the increasing operating costs of conventional power plants, at least at base load.

Compared to 2016, utility-scale battery storage capacity has nearly doubled

Increasing fuel costs resulted in very low baseload spreads (the difference between the marginal costs of power plants, plus CO2 prices and wholesale electricity prices) for base load coal power plants, which faced low spreads only slightly above 0 €/MWh from February till November 2017. For base load gas-fired power plants, the situation was even worse with spreads below 0€/MWh from February 2017 throughout the whole year.

Gas-fired peak power plants, on the other hand, remained profitable with a higher spread in 2017 than in 2015 and 2016. Figure 5 summarizes the Clean Dark Spread Base (relevant for hard coal power plants) and the Clean Spark Spread Base and Peak (base for gas-fired power plants in base load, peak for gas-fired power plants in peak load) from 2015 till 2017.

Figure 5: Monthly average clean dark spread base and clean spark spread base/peak in Germany/ Austria (Tennet 2018)

Utility-scale battery storage in Germany – significant growth, but still on a very small level

Utility-scale battery storage is still the exception in Germany. While the residential and industrial battery storage markets are developing quite fast, utility-scale battery storages only added up to about 230 MW in 2017.

Still, compared to 2016, this capacity has nearly doubled. Further utility-scale battery storage projects will be carried out in 2018 (e.g. two large battery storages are currently built in Northern Germany: a lithium-ion system of 7.5MW/2.5MWh, plus a sodium-sulfur unit of 4.4MW/20MWh (renews.biz 2018)).

Figure 6: Installed capacity of utility-scale battery and power-to-gas storage technologies in Germany (TenneT 2018)

Renewable generation in Germany

Renewable generation is still on the rise in Germany, even though at a much slower pace than in the years around 2010. Due to favorable weather conditions, renewable generation provided 38% (33% in 2016) to total electricity generation in Germany in 2017.

Figure 7 illustrates that a particularly windy last quarter of 2017, as well as significant electricity production from photovoltaics in the summer of the same year (with a new record in June) were the primary drivers for the increase in total electricity production by renewables.

Figure 7: Monthly feed-in of RES in Germany (TenneT 2018)

The costs of the Feed-In Tariff (EEG) are stagnating – first tenders successful

In Germany, the costs of the feed-in tariff scheme are covered by a surcharge on the consumption of each kWh of electricity. While this surcharge is still on a very high level being slightly below 7€cent/kWh, it has remained rather constant compared to 2016 (it has even decreased a little bit).

Figure 8 illustrates how the different tariffs for different renewables developed on average from 2010 till 2017, and compares this to the EEG surcharge (levy) which is paid for by the consumers to cover the costs of the tariffs.

Figure 8: Average feed-in tariff (left axis) and EEG levy (right axis) (Tennet 2018)

Especially subsidies for PV-power plants are decreasing significantly and thereby reduce the pressure on the EEG surcharge. Furthermore, the subsidy scheme in Germany is currently in a transition period from governmentally defined feed-in tariffs towards tendering systems. Figure 9 shows the different results of tenders for large photovoltaic-power plants and onshore wind farms in Germany.

Figure 9: Average auction results for solar panels and onshore wind turbines in Germany (Tennet 2018)

Both solar PV and onshore wind farms participating in tenders required a subsidy below 7 €ct/KWh or even less in 2017. Similar developments can be observed at offshore windfarms in Germany (see figure 10).

Figure 10: Strike prices of offshore wind auctions (TenneT 2018)

Note that the strike prices shown in figure 10 are not directly comparable between different states since different rules apply for network connections, etc. Still, the first result of the offshore tender in Germany reached a very low level as well.

Redispatch costs in Germany reach new record in 2017 – far above 1 billion €

Network congestion has been one of the key topics for network operators in Germany for quite a while now. With increasing shares of renewables and intensifying cross-border trading, the situation gets more complex from year to year.

While in 2016 redispatch costs were lower, mainly due to weather conditions, they reached a new record in 2017

In a previous post, (which you can find here) we have already introduced the processes behind redispatch and the resulting costs for the system in the period from 2014 till 2016. In 2015, redispatch costs in Germany for all TSOs added up to more than one billion €, which was quite significant at that time.

While in 2016 redispatch costs were lower, mainly due to weather conditions, they reached a new record in 2017. Even though the figures for all TSOs are not yet published, redispatch costs for TenneT indicate that redispatch costs reached a new maximum in 2017 in Germany. In 2017, TenneT alone had to pay more than one billion € for redispatch.

Figure 11: Redispatch costs in the TenneT control area between 2015 and 2017 (Tennet 2018)

2017 – a year of records in the German electricity system

The data collected by TenneT points at several important aspects of the German electricity market in 2017. While wholesale prices increased, power plant operators (especially those focusing on base load) were facing decreasing revenues close to or below zero. Renewable generation increased again while the renewable surcharge remained stable.

The first tenders for renewable generation reached low subsidy levels below 7€cent/kWh. The market of utility-scale battery storage seemed to take off, but it remains a rather small market for now.

From network operators’ perspective, the most significant development in 2017 was the increasing need for redispatch in Germany, which led to costs of more than one  billion for TenneT alone. What can we expect from 2018? In the first quarter of 2018, renewable generation was up 18% compared to the same period in 2017. The first hint for another year of records to come?

Editor’s Note:

Marius Buchmann holds a Ph.D. in energy economics and works as Post Doc at Jacobs University in Bremen, Germany. He writes about energy on his blog Enerquire. This article was first published on Enerquire and is republished here with permission.

Wind farm in Xinjiang, China

• Current technology-forcing policies imply that wind and solar power, combined with battery electric vehicles, represent our only viable energy future, observes independent researcher Schalk Cloete. Given the fundamental limitations of these technologies, this is a very dangerous notion, he argues. A shift to technology-neutral policies is needed, especially in developing nations.

It is undeniable that wind and solar power and battery electric vehicles (BEVs) will play an important role in the energy system of the future. They are, however, fundamentally limited regarding the speed and extent to which they can grow. Despite these fundamental limits, current policy frameworks imply that they are essentially our only options for a clean energy future – a very dangerous notion indeed.

This article will discuss the dangers associated with current green technology-forcing in more detail, outlining why it can easily hurt much more than it helps. A follow-up article will then detail some of the other options at our disposal together with some musings about how these options will respond in a more intelligent technology-neutral policy scenario.

Technology-neutral policies target the real issue and alter the competitive landscape in favor of any technology that can address this issue

Before we start, here is a quick clarification on what I mean by technology-forcing and technology-neutral policies. Technology-forcing promotes certain technologies over others through mechanisms like subsidies, tax-breaks, mandates, portfolio standards, low-interest financing, accelerated depreciation, guaranteed prices, etc.

Technology-neutral policies target the real issue and alter the competitive landscape in favor of any technology that can address this issue. Examples include a carbon tax to combat climate change, fuel taxes to limit congestion and oil dependence, and vehicle/plant emissions taxes to improve air quality.

Fundamental limitations

Let’s start by revisiting the fundamental limits to the growth of wind, solar and BEV technology. If these limits did not exist and there really could be a tipping point beyond which these green technologies would mercilessly sweep aside fossil fuels for good, I’d be all for it. But unfortunately, this is not the case.

Grid integration issues are already hampering wind/solar scale-up even at the current low market share

The fundamental limits that will restrict wind and solar to moderate market shares include the following:

• Their variable and non-dispatchable nature that leads to sharp value declines and a perpetual subsidy dependence.
• The poor correlation between wind/solar resource availability and population density.
• The fact that they only supply electricity, which currently accounts for only 22% of final energy demand.

Cost and value decline of wind and solar power.

As a practical illustration of the growth limitations faced by wind and solar power, the graph below compares primary energy growth in China. Clearly, despite massive technology-forcing, combined wind and solar output is increasing at about a 10x slower rate than coal grew a decade earlier.

This large difference is even more striking when considering that the productive capacity of the Chinese economy was almost 3x smaller during the coal growth period than the wind/solar growth period.

It is also noteworthy that grid integration issues are already hampering wind/solar scale-up even at the current low market share, whereas pollution concerns of coal started limiting deployment at much higher market shares.

Data (1, 2) showing China’s impressive recent wind & solar scale-up relative to coal growth from a decade earlier.

The fundamental limits that will restrict BEVs to moderate market shares include the following:

• The most suitable market segment, passenger light duty vehicles, represents only about 21% of global oil consumption and 7% of fossil fuel CO2 emissions.
• Even within this segment, economic attractiveness fades quickly for longer-distance highway driving applications.
• Unless a new battery technology emerges, technology metal availability will pose serious scale-up constraints.

Drivetrain and fuel costs for BEVs and hybrids employing assumptions consistent with commuter cars on the left and highway cars on the right of the graph (previous article).

However, the most important issue to me is the fact that all of these green technologies are highly capital intensive. Furthermore, commitment to an energy future dominated by these technologies also demands a wide range of complex and capital-intensive supporting investments.

This complex, large upfront investment requirement makes these technologies fundamentally unsuitable for supporting rapid economic development, which is a much higher priority than sustainability for about 80% of global citizens.

Contour lines showing the welfare-optimized wind/solar market share under different discount rates (WACC) and CO2 prices (discussed in detail earlier). Developing nations will generally fall towards the bottom-right of the graph.

What can go wrong?

So what if we continue current technology-forcing policies, but eventually have to concede that we cannot push these technologies beyond about a quarter of final energy demand. What harm would be done? Surely it is better than doing nothing. Well, not quite…

Firstly, the policy-driven growth of these technologies attracts a lot of capital and initiative that would have gone to the myriad of alternative sustainability options under a technology-neutral framework. Given the typical multi-decade development pathway from concept to fully cost optimized commercial scale deployment, putting all of our eggs in one basket is a very risky ploy.

Solar PV illustrates the time required to go from concept to commercial reality (image source).

Secondly, the enormous supporting infrastructure buildouts required by this pathway will impose a massive cost if things don’t work out as expected. For example, getting anywhere close to 20% of our final energy from wind and solar will require a total redesign of the power system with heavy investments in flexible power plants, long distance transmission lines, demand response and energy storage.

Rapid economic development directly shields people against the effects of climate change

If we eventually realize that the required deep decarbonization is not possible through this pathway, switching to an alternative pathway will be incredibly costly (both in terms of time and money).

Large value declines of solar PV in a high carbon tax scenario when changing from policies excluding nuclear and CCS (green line) to policies including all options (orange line).

Thirdly, forced deployment of these capital-intensive technologies at a scale that will actually make a difference will divert unacceptable amounts of capital away from other infrastructure investments capable of stimulating compounding economic development in the developing world.

Such development is critical to increase life expectancy and quality of life, and impeding this development can have massive humanitarian costs (below). As a quantitative illustration, I previously estimated the net cost of this effect at $750/ton of CO2 avoided.

An important omission from the enormous cost mentioned above is that rapid economic development directly shields people against the effects of climate change. Improved housing, sanitation, utilities, medical care, international trade connections and general productivity will all greatly reduce the impacts of a more hostile climate on the lives of developing world citizens.

Rapid increases in global productivity will make it much easier to balance our carbon budget by the end of this century

Ironically therefore, CO2 released to maximize the speed of this massive infrastructure buildout will actually lower the climate impacts experienced by the majority of global citizens.

Economic development offers excellent protection against climate change (image source).

Finally, we should acknowledge that rapid increases in global productivity will make it much easier to balance our carbon budget by the end of this century. As a simple example, it is now finally becoming more generally accepted that broad deployment of carbon negative technologies will be required to achieve our climate goals.

Let’s consider a worst-case scenario where we eventually need to extract a massive 2000 Gt of CO2 from the atmosphere via bio-CCS, direct air capture and reforestation at a high average cost of $150/ton.

Currently, the enormous total cost of $300 trillion is more than double global GDP (PPP). However, if we can bring the developing world up to developed world productivity, the total cost suddenly reduces to less than 6 months of global production (1% of output spread over 50 years) – certainly a manageable number if we consider what is at stake.

Illustration of rapidly growing emission gaps that will enforce carbon negative solutions later this century.

Thus, any economically inefficient decarbonization effort in the developing world will result in a broad range of costs totaling far more than the $750/ton CO2 estimate given above. And yes, technology-forcing is per definition economically inefficient.

Conclusion

Technology-forcing policies promoting wind/solar power and BEVs may do much more harm than good in the long term. This is especially true for the developing world where about 90% of economic and energy growth will take place over coming decades.

It is crucial that people concerned about our great 21^st century sustainability challenge stop bickering about which technology class is best. This time and initiative can be invested much more productively in advocacy for technology-neutral policies leveling the playing field for all clean energy technologies.

Such policies will unleash a broad range of creative sustainability solutions, some of which will be covered in the second part of this article. Given the urgency and magnitude of our global sustainability challenge, we can no longer afford to persist with inefficient technology-forcing of the most ideologically attractive solutions.

Editor’s Note

Schallk Cloete describes himself as “a research scientist searching for the objective reality about the longer-term sustainability of industrialized human civilization on planet Earth. Issues surrounding energy and climate are of central importance in this sustainability picture and I seek to contribute a consistently pragmatic viewpoint to the ongoing debate.”

This article was first published on The Energy Collective and is republished here with permission.

High voltage switchgear

SF₆, the most potent greenhouse gas in existence, was banned for all applications in the EU in 2014 – except in the electricity industry. The reason for the exemption, writes Nicholas Ottersbach, researcher at German cleantech startup Nuventura, was that there was no viable alternative. But according to Ottersbach that is no longer the case. He calls on EU policymakers to ban SF₆, in the electricity industry when the relevant EU legislation is reviewed in 2020.

In 2014 the European Union (EU) reinforced a 2006 F-Gas regulation, aiming to strengthen measures to contain the polluting emissions of fluorinated gases (F-gases) (EU Commission, 2015). F-gases are a family of man-made gases with the strongest greenhouse effect. Of all the F-gases, SF₆ (the focus of this paper), is the most potent.

This regulation’s aim is to bring down the EU’s F-gas emissions by two-thirds from 2014 levels by 2030 as part of the ultimate objective of cutting overall greenhouse gas (GHG) emissions by at least 80% by 2050 against 1990 levels (Biasse, 2014). However, the new restrictions on the use of SF₆ did not affect its largest user, the electrical power equipment industry. The EU regulation mentions phase-out dates for F-gases used in many applications, depending on their global warming potential (GWP) yet it does not mention SF₆ in switchgear meaning, in effect, that there are no restrictions (Biasse, 2014).

SF₆ is a long-lived, highly potent greenhouse gas. It is manmade and combines excellent electrical properties with chemical stability and low toxicity.

Having said this, the regulation does have a provision for reviewing the situation in 2020 which should provide fresh impetus for policy makers, and interested actors, to give this gas the serious attention it deserves. This is especially pertinent as large parts of EU regulations are often followed by developing countries’ laws, to get access to the EU market.

What is SF₆? and how is it used?

SF₆ is a long-lived, highly potent greenhouse gas. It is manmade and combines excellent electrical properties with chemical stability and low toxicity. Moreover, It’s non-flammable and low in cost. These characteristics have led to its widespread and enthusiastic adoption by the electrical industry, which uses approximately 80% of all SF₆ produced (Powell, 2002: 6).

Within the electrical industry SF₆ is used as an insulating medium for medium (MV) and high (HV) voltage electrical switchgear. A switchgear is the combination of electrical disconnect switches, fuses or circuit breakers used to control, protect and isolate sections of electrical grids. Low-voltage (LV) switchgear are used for controlling electrical circuits within buildings, medium voltage (MV) switchgear for controlling the electrical grids within cities and towns, and high voltage (HV) switchgear for grids that span a greater geographical area such as countries and regions.

Is SF₆ a danger to human health?

In its normal and inert form SF₆ is relatively harmless to humans. However, when exposed to electrical discharges through everyday usage within SF₆-filled equipment, highly toxic by-products are produced that pose a serious threat to those in close proximity to the switchgear (ICF Consulting, 2002: 1).

These byproducts include, among other things, disulfur decafluoride (S₂ F₁₀) which is a highly toxic gas (Blackburn 2015: 2). It has been referred to by the US Environmental Protection Agency (EPA) as “the byproduct of greatest concern due to its relatively high toxicity.” (ICF Consulting, 2002: 2)

Unlike gases such as CO₂, SF₆ has no natural sink, origin or effective disposal method, making its accumulation in the atmosphere virtually irreversible

S₂ F₁₀’s toxicity is on a par with phosgene, the infamous chemical warfare pulmonary agent used during the First World War (Blackburn, 2015: 2). Its weaponization was also considered during the Second World War due to its toxic nature, as it provided little warning of exposure to the victim (Blackburn, 2015: 2).

The presence of such by-products is of real concern due to the documented fact of leakage, as well as uncontrolled releases or discharges that occur during routine development, testing, commissioning, maintenance and repair, and decommissioning of SF₆ -filled equipment. For companies using SF₆  these dangers represent, at best, increased handling costs due to required safety measures, and at worst a real risk to human life. They also lead to legitimate concerns over the health and welfare of utility employees as well as the communities that host switchgear stations.

How environmentally damaging is it?

With a GWP of around 22,800 over a 100-year time horizon, SF₆ is the most potent greenhouse gas regulated under the Kyoto Protocol (Rigby et al, 2010: 10305). Its GWP of 22,800 means that it is 22,800 times more effective at trapping infrared radiation (i.e., creating the greenhouse effect) than an equivalent amount of carbon dioxide over a 100-year period (Blackburn, 2015: 5).

Moreover, it is widely believed to have an atmospheric lifetime of 3,200 years (Diggelmann et al, 2016: 70), although recent research suggests shorter lifetimes. Some say 850 years (with a range from 580 to 1,400 years) (Ray et al, 2017: 4626) while other research suggesting closer to 1,278  years (with a range of 1,120   to 1,475) (Kovács, 2017: 883). In any case, it is clearly an extremely long-lived gas, and poses a serious problem through its contribution to the immediate threat of global warming.

As well as having an extremely long lifetime, unlike gases such as CO₂, it has no natural sink, origin or effective disposal method, making its accumulation in the atmosphere virtually irreversible (Blackburn, 2015: 5). Without disposal methods that completely destroy SF₆, it can be expected that all of the SF₆ that has been or will be produced will eventually end up in the atmosphere (Dervos and Vassiliou, 2000: 138).

Studies also show that atmospheric concentrations of SF₆  have increased by more than a factor of 10 since measurements began in 1973 (Rigby et al, 2010: 10305). They also found that global emissions are higher now than ever, and have increased by almost 50% between 2000 and 2010 (Rigby et al, 2010: 10305).

Global annual SF₆ production is currently around 8,000 tonnes (Damsky, 2016: 1). Furthermore, based on atmospheric data, global SF₆ emissions in 2012 were 8,100 tonnes (Dunse et al, 2015: 20) essentially creating a production-emission parity. These emissions are the equivalent of the annual greenhouse footprint of approximately 40 million cars (EPA, 2017). Despite these environmental consequences, SF₆’s use in the electrical industry is forecast to grow by around 50%, from 2005 levels, by 2030 (Rhiemeier et al, 2010: 29). .

Has the environmental impact even been underestimated?

Although SF₆’s GWP of 22,800 firmly establishes it as the most dangerous known greenhouse gas, the number may be unrepresentative of its true environmental threat. The IPCC, for example, gives SF₆ a higher GWP of 23,500 (Myhre & Shindell, et al. 2013: 733). Moreover since GWP accounts only for 100 years of the gas’ atmospheric lifetime, the real impact is much higher. If one assumes a 500-year time horizon, it grows to 32,600 (IPCC, 2005) and, even then, remains only a fraction of its true impact on global warming. This begs the question as to whether the gravity of SF₆’s impact on global warming has really been understood? And whether we can continue to rationalize its use in the electrical industry?

Considering that the measurement approaches on which emissions regulation is based are fundamentally erroneous, how can we be certain that the SF_6-reduction measures taken so far by the EU, and by extension the electrical industry, have been effective?

Furthermore, research shows that up to 80% of SF₆ emissions are not reported at all (Levin et al. 2010: 2655). A reason for this is that Asian countries, such as China, India and South Korea, who are driving the increase in emissions, do not report their SF₆ emissions to the United Nations Framework Convention on Climate Change (UNFCCC) (Rigby, 2010: 10316). Another reason is that developed countries that do report emissions to the UNFCCC, such as the USA, UK, and Germany, are likely to be underestimating their emissions (Rigby et al, 2010 :10318).

Developed countries are likely under-reporting their emissions because emission reduction legislation relies on a ‘bottom-up’ measurement approach, which greatly underestimates real emissions (Weiss and Prinn, 2011: 1934). There are two broad approaches to measuring emissions: bottom-up and top-down. The bottom-up approach measures SF₆ emissions at the source of emission, while the top-down approach measures changes in the atmospheric concentration of SF₆. The aforementioned increase in global atmospheric SF₆ emissions was measured and modelled extensively and independently by several research studies (Weiss and Prinn, 2011: 1934). They all came to the same general conclusion, namely that global SF₆ emissions are greatly underestimated by bottom-up emissions reported to the UNFCCC by developed countries (Weiss and Prinn, 2011: 1934).

Considering that the measurement approaches on which emissions regulation is based are fundamentally erroneous, how can we be certain that the SF_6-reduction measures taken so far by the EU, and by extension the electrical industry, have been effective?

Is the mitigation of SF6 emissions difficult? Do better solutions exist?

Due to SF₆’s high GWP, its use is regulated by national and international governing bodies (Deux, 2013: 2). This creates further costs and a myriad of bureaucratic compliance legislation for companies, that must be adhered to. For example, when SF₆-filled equipment is near the end of its life or has technical problems, special care must be taken in its recycling process and maintenance. Only licensed or authorized hazardous waste managers are permitted to handle, transport and recycle the gas according to national or regional regulations and standards (Deux, 2013: 4). These lifecycle management costs will continue to rise as the global demand for electricity, and, thus, switchgear, increases.

With EU regulation No 517/2014 due to be reviewed in 2020, policy makers should campaign for further legislation with the final aim of phasing out SF₆

All the externalities of SF₆ described in this paper have incentivised big and small manufacturers to find SF₆-free solutions to switchgear. Several manufacturers – predominantly in the medium voltage (MV) level – have developed effective solutions based on vacuum switching technology in combination with solid or air insulation as alternatives for SF₆ (Porte and Schoonenberg, 2009: 1). Rapid innovations in the MV range have brought into question the industry claim that SF₆ is a necessary evil and that alternatives are too costly (Porte and Schoonenberg, 2009: 1). Unfortunately, similar progress has not yet been made for high voltage (HV) applications.

From a pricing perspective, research comparing SF₆-containing switchgear and SF₆-free switchgear found no evidence that the latter was more expensive than the former (Benner et al, 2012: 23). In actual fact, it found that SF₆-free switchgear generally can be up to 10% cheaper than the corresponding SF₆-containing alternative (Benner et al, 2012: 23).

Conclusion

SF₆ is the most potent greenhouse gas in existence and for this reason was included in the Kyoto Protocol’s list of substances of which the use and emission should be minimized. Consequently, SF₆ has been banned for all applications in which alternatives exist. However, an exception has been made for HV and MV switchgear in the electrical industry.

The rationale for this was that there was no viable alternative. However, as has been made clear this in this paper, this is no longer the case, at least not in the case of MV switchgear. There are alternatives which are technically and commercially viable. With EU regulation No 517/2014 due to be reviewed in 2020, policy makers should campaign for further legislation with the final aim of phasing out SF₆. This will further invigorate the research and development of SF₆ -free technologies, not only for MV switchgear, but also for HV applications. These measures will represent a significant step in the fight against climate change and also help reestablish Europe as a leader in cleantech.

Editor’s Note

Nicholas Ottersbach is a business developer and researcher at Nuventura, a cleantech startup looking to contribute to a greener, smarter and more sustainable global power sector. The company is involved in developing an alternative for SF_6.

Bibliography

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Biasse, J.M., 2014. ‘SF6 in Medium Voltage and High Voltage switchgear unaffected by new EU F-gas regulation’. Schneider Electric. Available at: https://blog.schneider-electric.com/utilities/2014/10/28/sf6-mv-hv-switchgear-unaffected-new-eu-f-gas-regulation/

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Dunse, B.L., et al. 2015. ‘Australian and global HFC, PFC, Sulfur Hexafluoride, Nitrogen Trifluoride and Sulfuryl Fluoride Emissions’. CSIRO. Available at: https://www.environment.gov.au/system/…/australian-hfc-pfc-emissions-2015.pdf

ICF Consulting, 2002. ‘Byproducts of Sulfur Hexafluoride (SF6) Use in the Electric Power Industry’. U.S. Environmental Protection Agency (U.S. EPA). Available at: https://www.epa.gov/sites/production/files/2016-02/documents/sf6_byproducts.pdf

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Block Island wind farm, Rhode Island

Offshore wind may seem like a pricey option, but it’s actually an extremely valuable investment, writes Mike O’Boyle of San Francisco-based think tank Energy Innovation. According to a new analysis, the market value of electricity generated by offshore wind will soon exceed its cost in New York and several New England states.

Offshore wind may seem like a pricey option, but it’s actually an extremely valuable investment.  A new analysis from the Lawrence Berkeley National Laboratory (LBNL) shows that the market value of electricity generated by offshore wind will soon exceed its cost in New York and several New England states.

The economic impact of offshore wind is even more significant after adding in the tens of thousands in new jobs and billions in new investment that come from steel in the water. Massachusetts, Maryland, and New York are already accelerating offshore wind’s expansion, and states like New Jersey aren’t far behind in a race to the top.

Even the Trump Administration is touting offshore wind’s upside. “As we look to the future, wind energy – particularly offshore wind – will play a greater role in sustaining American energy dominance,” wrote Interior Secretary Ryan Zinke. “Offshore wind uniquely leverages the natural resource off of our East Coast, bringing jobs and meeting the region’s demand for renewable energy.”

Offshore wind’s attractive East Coast economic attributes

On a levelized cost of energy basis, offshore wind still seems more expensive than more ubiquitous onshore wind and solar, but when and where power is generated matters a great deal for whether generators provide value to buyers.  LBNL’s new analysis shows that high capacity factors of offshore wind, the coincidence of wind with customer demand, and potential locations adjacent to congested coastal load centers like New York City and Boston already make offshore wind an economic option.

LBNL quantifies the value of offshore wind by adding the energy, capacity, and renewable energy certificate (REC) revenues power plants could expect by participating in each market.  When averaged over the entire 2007-2016 period, LBNL found the median marginal value for offshore wind sites connecting to New England’s ISO-NE grid is roughly $110 per megawatt-hour (MWh), compared to $100/MWh for sites interconnecting to New York’s NYISO grid, $70/MWh for sites in the Mid-Atlantic’s PJM Interconnection grid, and closer to $55/MWh for sites in the non-competitive Southeast.

Total offshore wind market value at each site averaged over 2007-2016.

$110-100/MWh values in the Northeast already approach near- to medium-term anticipated all-in costs to build offshore wind, evidenced by recent auction results.  Maryland paid $132/MWh REC prices for 386 megawatts (MW) of offshore wind capacity in 2017 to come online in 2020, down from over $250/MWh paid for Rhode Island’s 30 MW Block Island offshore wind farm, which came online in 2016.

Much larger offshore wind auctions are on the horizon, with nearly 8,000 MW of offshore wind procurement announced by state governments in the Northeast U.S.  By the time Europe reached that capacity figure, offshore wind contracts were being signed for $80/MWh or less, and that was with inferior technology, i.e. smaller turbines.

Median energy, capacity, REC value by year for offshore wind sites within each region.

Offshore wind’s extreme value in Northeast states shouldn’t come as a surprise.  Higher REC prices primarily drive LBNL’s finding, but energy prices are also higher in New England and New York than in PJM and the Southeast U.S.  These high REC prices derive from difficulty siting projects on the most constrained land in the U.S. and relatively lackluster onshore wind and solar resources, combined with some of America’s most ambitious renewable energy goals, which on average will require the region to hit 40% renewables by 2030.

LBNL found that offshore wind prevents the most emissions of carbon dioxide and other pollutants in the Mid-Atlantic PJM region, mostly due to the higher emissions intensity of the generators running in that market

It’s remarkable that with just 30 MW of installed capacity, the U.S. is close to offshore wind turbines being in the black.  Falling wholesale market electricity prices, driven by a glut of cheap gas and excess coal and nuclear generation that could soon retire due to economic pressure, have undercut this value proposition, but that could very well rebound as excess supply retires.

Ancillary environmental and consumer cost benefits

Depending on how fast costs fall, cheaper offshore wind could even keep regional electricity prices low for some time to come, creating additional consumer benefits.  LBNL also quantifies the potential environmental and economic benefits of offshore wind, finding offshore wind significantly reduces air pollution and reduces natural gas and energy prices – to consumers’ benefit.

Avoided SO2, NOx, PM2.5, and CO2 emissions rate by year for average offshore wind profile in each region.

LBNL found that offshore wind prevents the most emissions of carbon dioxide and other pollutants in the Mid-Atlantic PJM region, mostly due to the higher emissions intensity of the generators running in that market.  By their measure, 1 MWh of offshore wind avoids 800 kilograms (kg) of carbon emissions.

But 800kg/MWh is a bit hard to understand, so let’s take a deeper look at how this applies in practice. Maryland’s 2017 offshore wind solicitation procured the 120 MW Skipjack offshore wind farm, with an implied capacity factor (i.e., how much it produces relative to its maximum theoretical output) of 43%.

Because offshore wind bids into a wholesale market at zero marginal cost, it would also reduce wholesale energy prices and demand for natural gas, which has a marginal fuel cost, thereby reducing gas and electricity costs to customers

Applying this avoided emissions rate around 800kg/MWh, which is what you would see if Skipjack sells its power into PJM, the 120 MW wind farm would avoid 364,000 metric tons of CO2 annually – that’s about equal to the emissions of 80,000 passenger vehicles.

Because offshore wind bids into a wholesale market at zero marginal cost, it would also reduce wholesale energy prices and demand for natural gas, which has a marginal fuel cost, thereby reducing gas and electricity costs to customers.  LBNL calculates these “merit order effects” at $6/MWh for natural gas prices, and $25/MWh in wholesale energy costs in wholesale market regions. The savings are significantly lower in the states south of the PJM region.

Median energy, capacity, and REC value along with the in-region natural gas price effect and wholesale electricity price effect averaged over 2007-2016.

Evidence is also growing that offshore wind will create tens of thousands of jobs in the Northeast.  Combining existing contracts with New Jersey’s 3,500 MW goal, New York’s 2,400 MW goal, and Massachusetts’ 1,600 MW goal, the regional market would reach at least 8,000 MW by 2030.

The Northeast Wind Center projects this would create 36,300 full-time jobs, while New York expects a $6 billion in-state industry by 2028, and Massachusetts projects up to $800 million in direct economic impacts along with up to 3,170 job years from offshore wind in the next decade.

Massachusetts is already reaping dividends from its offshore wind goal. Three coastal communities that have suffered economically from manufacturing and fishing industry declines are in the final running for developer Deepwater Wind’s new wind turbine assembly facility and its 900 new jobs. In addition, the retired Brayton Point coal plant was recently acquired by a real-estate developer with plans to turn it into a construction hub for planned offshore wind farms and connection point to the regional grid once projects begin operation.

Levelized cost of energy doesn’t always tell the whole story

The levelized cost of energy, though a valuable metric for comparing different technologies, fails to tell the whole story of the value of energy.  Offshore wind is more valuable in Northeast states where renewables’ policy value combines with higher wholesale energy prices to create a more attractive market than in the Mid-Atlantic and Southeast regions.

Couple this with the industry’s history of rapid cost declines and regional demand for clean energy, and it’s easy to see a bright future for offshore wind developers in the near to medium term – along with billions in upside for the states who embrace offshore wind’s economic potential.

Editor’s Note:

Mike O’Boyle is Energy Innovation’s Electricity Policy Manager and Project Manager at America’s Power Plan.

This article was first published on Forbes.com and is republished here with permission.

solar power in Singapore

Renewable energy auctions have seen very low prices in many parts of the world. Why do auctions seem to be so effective in driving down costs – and what are the risks? Ana Amazo-Blanco, Silvana Tiedemann of Navigant[1], and Dr. Stephen Tay and Monika Bieri of SERIS looked at a solar PV rooftop auction in Singapore and an offshore wind auction in Germany to discover the key factors behind the bids and suggest how project developers can make sure the projects are realized successfully.

Renewable electricity auctions have seen record low prices for solar and offshore wind energy  in places like Saudi Arabia, India, Mexico, Germany, and the Netherlands. What are the reasons behind this aggressive bidding? And what could be the risks? To find out, we have looked at two recent cases in Germany and Singapore.

Germany’s offshore subsidy scheme

The German Network Agency held the first round of the offshore wind auction we looked at in April 2017. It produced a near subsidy-free result. Three out of the four awarded projects, which have a total capacity of 1,490 MW, will be built without subsidies, i.e. had a bid price of zero cent/kWh. The projects in question are the 900 MW He Dreiht site that EnBW will develop and the 240 MW OWP West and 240 MW Borkum Riffgrund West II sites, which Ørsted (formerly “DONG Energy”) will build.

The possibility to recover incurred costs by winning the auctions was arguably an important consideration in the applied bidding str­ategies

The second round of the auction, implemented in April 2018, also saw subsidy-free bids being awarded. One of these projects is the 420 MW Borkum Riffgrund West 1 project to be developed by Ørsted. Higher bids were awarded at this auction for three reasons.

First,  projects from the Baltic Sea were protected against competition from more competitive projects from the North Sea by the so-called “Baltic Sea” quota of 500 MW.

Second, a skilful bidding strategy allowed Ørsted to secure a bid with a relatively low volume but high price “filling up” of the remaining volume difference (Ørsted’s second successful bid was Gode Wind 4 with a capacity of 131.75 MW at a price of EUR 98.30 per MWh). Third, the least expensive projects had already been awarded in the first round of the auction.[2].

Both rounds of the auction were open to bidders that had invested in developing their site first. Therefore, if bidders were not successful in the auction, the predevelopment cost would largely have been lost. The possibility to recover incurred costs by winning the auctions was arguably an important consideration in the applied bidding str­ategies.

But do projects that bid zero get no remuneration at all? No, they receive the revenue from the electricity market but without any subsidy.

This is an even more compelling reason why the German offshore market structure invites aggressive bidding for offshore windfarm operators. Winning the auction is the only way to become eligible for a grid connection and thus gain access to the wholesale electricity market.

Singapore’s SolarNova programme

In Singapore, renewable auctions were introduced to grow the private solar sector, decrease carbon emissions, and reduce reliance on imported fuels. The SolarNova programme, led by the Singapore Economic Development Board, was launched in 2014. Its particular target is to achieve 350 MW of installed photovoltaic capacity on the rooftops of government-owned buildings by 2020. In the programme, the aggregate demand for solar energy is auctioned in public bids, which allows government agencies to benefit from economies of scale.

Winning the auction also provides these companies with renewable energy certificates RECs) they can sell to interested multinational corporations

The first auction was awarded to Sunseap Group in December 2015 (with a plan to install 76 MWp), while the second round was won by Million Lighting in June 2017 (minimum installed capacity 40 MWp).

The award decision was mainly based on the discount bidders’ offer against an electricity benchmark tariff. A total of nine bidders offered discounts ranging from 30% to 99.9% for public housing blocks and from 20% to 65% for buildings owned by government agencies. At the second auction, the same number of bidders offered discounts from 10% to 99.9% and from 20% to 90%, respectively.

Against the current prevailing electricity tariffs of S$215.60/MWh (approximately €135.56/MWh) for public housing blocks and S$186.60/MWh (approximately €117.30/MWh) for agency buildings [3],  the winning company for the first tender, Sunseap Group, provided discounts of 99.9% for public housing blocks and 65% for agencies.

This results in public housing blocks receiving virtually free onsite solar power, while agency buildings pay for consumption of power at a highly discounted rate. The solar power generated on public housing blocks, however, can only be used to power common loads such as corridor lighting, elevators, or water pumps and is not allowed to be channelled (or sold) directly to the residential units.

In Singapore, winning an auction enables a company to position itself as a leader in the local market just because of the sheer size of the tender

The aggressive bidding at these auctions was made possible through other income sources the winning parties could rely on. With payments for electricity consumed onsite only providing a small (or no) contribution to revenue streams, bidders have two more options for income and cash flows.

First, winning companies can sell electricity that the respective building does not consume back to the grid. For the first auction, external sales will be remunerated at the regulated tariff minus the grid fee (at the current quarterly price this is about S$162.60/MWh); for all subsequent auctions the remuneration will be the prevailing half-hourly wholesale electricity price (currently averaging around S$80-S$90/MWh).

Winning the auction also provides these companies with renewable energy certificates RECs) they can sell to interested multinational corporations.

Factors triggering aggressive bidding

In comparing the two auction schemes, there are three common factors that trigger aggressive bidding strategies.

Lack of alternative investment opportunities: The auction volume was limited to specific sites where bidders can build their projects under the auction scheme. The lack of alternative business opportunities outside the auction scheme increases bidder’s incentive to bid aggressively, win a contract, and secure the site to build their project. In land scarce Singapore, sites for PV deployment are strongly limited by the availability of buildings where rooftop PVs can be installed on (e.g., those that are not heavily shaded).

In Germany, offshore wind project operators’ access to the market is limited by grid connection. Therefore, and unlike onshore wind or solar PV projects, offshore wind market players cannot build projects outside the auction scheme.

Scale effects: The opportunity to drive down costs through scale effects can be an important motive to offer low-price bids. In Germany, synergies between nearby offshore wind farms can help reduce the high cost for tailor-made maintenance concepts and downtime management.

Ørsted, for example, plans to combine the OWP West and Borkum Riffgrund West 2 projects into one large-scale project with the option of adding more volume in the 2018 auction[4], which they successfully achieved.

In Germany, large incumbent utilities see offshore wind as a new investment area with project volumes similar to what they are familiar with at conventional power stations

In the case of Singapore, economies of scale could be reached by aggregating demand as the auction winner is to supply all rooftops that are part of the scheme in question. Bidders in the SolarNova programme also benefit from a portfolio effect of financing distributed PV installations.

This can only be achieved through bundling numerous small projects. Hence, bidders might choose scale as dominant strategy instead of developing sustainable margins to receive bank financing. Bundling various rooftops into a well-diversified PV portfolio gives access to a number of financing options, such as green bonds or asset-backed securities.

Market share: Even if projected margins for the developer may be relatively low, bidders are prepared to bid aggressively if winning brings them the additional benefit of keeping or expanding market share in the electricity market or, more broadly, in the renewables sector.

In Singapore, winning an auction enables a company to position itself as a leader in the local market just because of the sheer size of the tender. It also offers the almost unique chance to have sufficient renewable energy certificates available to be an attractive contractual party for larger multinationals (e.g., RE100 companies). In addition, winning an auction provides the winner with a valuable government project reference.

In Germany, large incumbent utilities see offshore wind as a new investment area with project volumes similar to what they are familiar with at conventional power stations. Low-price bid strategies demonstrated at previous offshore wind auctions are also proof of the fierce competition between large project operators in the North Sea region.

Increased risk of nonrealisation and market concentration

In situations like the ones observed in Germany’s offshore and Singapore´s SolarNova programme, auctions provide an alternative mechanism for allocating subsidies and open the door to the market. Public support is reduced to a minimum –  a necessary condition for a sustainable market in the long term. Yet, aggressive bidding may lead to difficulties in terms of project realisation and may result in market concentration.

Involving banks and financiers at an early stage, when the PPA or auction documents are being prepared, could help reduce the risk of delays and non-realisation

If aggressive bidding results in underbidding (i.e., the revenue stream does not cover project costs) there is a risk that the project may not be realised. Therefore, auction initiators need to watch carefully the trade-off between the efficiency and effectiveness of an auction.

Having a larger portfolio may help deal with the loss of a project. This suggests that larger and more established industry players are better positioned to win at this type of door-opening auctions. Repeated rounds of auctions where larger parties win can lead to a concentration of actors, which could lower participation rate and ultimately decrease competition.

Recommendations – risk mitigation through auction design

There are several policy measures which may help avoid harmful market concentration and ensure project realisation. By inserting performance clauses in contracts, the risk of having a project with inadequate quality can be lowered. For example, the SolarNova auction requires the winning company to produce a certain amount of electricity annually and sets a limit on the system degradation rate over time. Components in the PV system, for example PV modules and inverters, are required to be certified according to international standards as this also reduces the risk from the government’s or auctioneer’s perspective.

Finding the right mix of measures and balance in the local market context is vital for an effective auction design, especially for technologies as different as solar and offshore wind

Secondly, due to possible delays in securing financing, the commissioning of a project may fall behind schedule. Thus, involving banks and financiers at an early stage, when the PPA or auction documents are being prepared, to improve bankability, could help reduce the risk of delays and non-realisation. This would be particularly helpful in jurisdictions where country risk and capital costs are high, and institutional capacity is limited.

Third-party bid evaluations, for example, can ensure the soundness of the financial offer. Targeted credit lines can facilitate the participation of smaller and more diverse actors.

Finding the right mix of measures and balance in the local market context is vital for an effective auction design, especially for technologies as different as solar and offshore wind.

In summary, aggressive bidding is more likely in markets where auctions act as a door opener to important revenue sources, when bidders aim to achieve scale effects, and secure market share by winning the auction. For policymakers, this kind of market situation can be a signal to adapt auction design by implementing measures that mitigate the risk of inadequate quality projects winning the auction or facilitate the participation of more diverse actors.

Editor’s Note:

Ana Amazo-Blanco is Energy Policies Consultant at Ecofys.

Silvana Tiedemann (M.Sc.) works as a Senior Consultant at Ecofys. She is an expert on policy instruments and regulation for renewable energy and other energy technologies.

Stephen Tay is the Head of National Solarisation Centre at the Solar Energy Research Institute of Singapore (SERIS).

Monika Bieri is a Research Associate at the Solar Energy Research Institute of Singapore (SERIS).

[1] Ecofys, a Navigant company, was part of the consortium advising the Ministry of Economic Affairs and Energy of Germany in the design and implementation of auctions for solar PV, onshore wind, offshore wind, and biomass.

[2] Only existing projects that had not been awarded in the first call could participate. Source: Bundesnetzagentur (BNetzA) (27.04.2018): Ergebnisse der zweiten Ausschreibung für Offshore-Windparks – Press Release. Available from: https://www.bundesnetzagentur.de/SharedDocs/Pressemitteilungen/DE/2018/20180427_Offshore.html?nn=265778

[3] Tariffs are quarterly adjusted, mainly due to changes in fuel prices.

[4] NERA, Method or Madness: Insights from Germany’s Record-Breaking Offshore Wind Auction and Its Implications for Future Auctions, 2017, http://www.nera.com/content/dam/nera/publications/2017/PUB_Offshore_EMI_A4_0417.pdf.

EON CEO Johannes Teyssen and Rolf Martin Schmitz, CEO of RWE

There is economic and financial market rationale behind the recent deal between E.ON. and RWE, writes financial energy specialist Gerard Reid. From a strategic perspective, however, the decision will impact customers negatively, and will be bad for the long-term sustainability of both companies, Reid argues. Courtesy Energy and Carbon blog.

It came as a great surprise to me some weeks back that Germany’s biggest utility E.ON reached an “agreement in principle” with its biggest competitor RWE to acquire its grid and retail business Innogy via a wide-ranging “exchange of assets,” including RWE taking over the renewables and other power generation businesses of E.ON.

The result, if the various competition authorities and regulators allow the deal to take place, will be the biggest European grid company and energy retailer in the form of E.ON, with RWE becoming the second biggest power generator in Europe and third biggest owner of renewable assets. In addition, as part of the deal, RWE will keep a minority stake in E.ON which ties the companies together.

The rationale behind

I understand the economic and financial market rationale for the deal but do not agree with the strategic rationale which will end up being bad for the end customer, the German tax payer, the long-term sustainability of both companies and the energy transition we are currently going through.

RWE and E.ON’s shareholders have had a torrid decade with share price falls of 70% over this period. These companies were too late in recognizing, let alone embracing the changes going on in their markets.

I do not believe that a large power generator like RWE can survive without customers

Renewables have to be the best example of this. Germany has installed some 70GW of renewables over the last 10 years, a massive growth opportunity which both companies completely missed, noting that the the combined German renewable portfolio of RWE and E.ON is a mere 400MW.

Then there were failed entries into new markets such as Brazil by E.ON and the ongoing problems that RWE is having in the UK market with its subsidiary N Power; in a nutshell, a litany of management errors and mistakes. In stark contrast, Southern European utilities Enel, EDP and Iberdrola all embraced the changes going on across global power markets which has been reflected in upwards share prices and improvements in profitability in recent years.

It is questionable whether a large retail supplier like E.ON can manage its power price risks without owning/controlling power generation

That all said E.ON and RWE’s management teams have done positive work in recent years in restructuring these businesses. First and foremost, they persuaded the German government to take financial responsibility for nuclear decommissioning, and then E.ON split itself into two parts: E.ON (renewables, grid and customers) and Uniper (conventional power generation and trading) while RWE spun off Innogy (grid, retail and renewables); the view being that investors would give greater value to a less complex non-vertically integrated business.

New business models

The asset exchange between E.ON and RWE is a logical extension of that argument. However, I question the strategic rationale and whether the new business models make any sense at all and whether they will bring sustainable profitability to both businesses.

I do not believe that a large power generator like RWE can survive without customers and if they try to do so they are opening themselves up to the vagaries of the wholesale power markets which could put them in risky situations where they are losing money on their generation. Having customers enables them to offset some of this risk and to lock in some future profits.

Assuming the deal goes ahead, competition is likely to decrease, which of course can only be bad for the customer

On the other side, it is questionable whether a large retail supplier like E.ON can manage its power price risks without owning/controlling power generation. There is of course another alternative and that is that RWE sells its power to E.ON through some long term agreement but if that is the case than it is easy to argue that we are seeing the beginnings of an energy cartel or even a return to the vertically integrated businesses that both E.ON and RWE are trying to move away from…

Whatever way you look at it, assuming the deal goes ahead, competition is likely to decrease, which of course can only be bad for the customer. It is also bad for the employees many of whom are going to lose their jobs in efforts to reduce costs to help justify the “synergies” caused by the deal. And if it is bad for the customer and employment why is it happening then?

It is happening because the German government is concerned about the financial stability of both businesses and with the negative impacts that a potential bankruptcy of one of them could have on the local and regional governments in the Rheinland region that still own a large part of both businesses. And the German government is right to be concerned.

But let’s not forget that the German government has already partly bailed them both out by taking the nuclear liabilities off them. And it has to be asked whether a government taking action to benefit shareholders at the cost of society and particularly customers and employees really does make sense especially when management in both companies has shown themselves incapable of making the necessary changes over the last decade?

Editor’s Note:

Gerard Reid is founding partner of Alexa Capital in London, a leading corporate finance business focused on energy and mobility. He has over two decades of experience in equity research and fund management in the energy area.

This article was first published on Energy and Carbon, a blog hosted by Reid and energy journalist and advisor Gerard Wynn. It is republished here with permission.