Mount Piper coal power station in Australia

The blueprint for Australia’s future electricity market released recently by Australia’s chief scientist Alan Finkel pleases some but not all market watchers, writes Fereidoon Sioshansi, publisher of the newsletter EEnergy Informer. For some critics, the real work on climate and energy policy in Australia has still to be done.

Imagine a world without electricity,” those are the starting words of the so-called Finkel Report released in June 2017 amidst much anticipation in Canberra, the capital of Australia. The official name of the report is Independent review into the future security of the National Electricity Market (NEM): Blueprint for the future.

Following last year’s blackout in South Australia, Finkel, Australia’s Chief Scientist plus a panel of 4 other experts, were tasked to propose a blueprint for the future. The panel’s mission was to “recommend enhancements to the National Electricity Market (NEM) to optimize security and reliability, and to do so at lowest cost,” noting that it is being submitted during a public debate about international commitments under the Paris Agreement. Australia’s current government, not unlike the US under President Trump, does not appear wholeheartedly wedded to the global treaty – or equivocates on its commitments.

In the report’s Preface, Finkel says, “If, as I hope, this blueprint is adopted by you, then our NEM should return to being the high-performance servant of our community that it once was.” As an official report to Australia’s Prime Minister Malcolm Turnbull, it says all the right things.

Australia has a once-in a-generation opportunity to reshape our electricity system for the future.” But is this that future?

Finkel and his fellow panelists point out the obvious such as, “Australia’s electricity system is in transition” and that “the rate of transition is rapid.” That much we already know.

The blueprint also makes other obvious points such as stating that the report is focused on 4 key outcomes:

• Increased security;
• Future reliability;
• Rewarding consumers; and
• Lower emissions

Adding, “These outcomes will be underpinned by the 3 pillars of an orderly transition, better system planning and stronger governance. What is there not to like?

The report offers many recommendations, more than most can absorb – from mundane to profound. As everyone recognizes, it is a rather complicated topic. The bulk of the report is covered by spelling out and embellishing these recommendations. It says, “Australia has a once-in a-generation opportunity to reshape our electricity system for the future.” But is this that future?

Much publicity

While it is hard to say how much of its recommendations will be accepted and/or implemented, it is fair to say that the report has already generated much publicity – not all in agreement with the report’s main recommendations.

The Australian’s headline on 14 June 2017 read “Turnbull faces revolt on power.” The Australian Financial Review’s headline on the same date read: “Coalition in revolt over climate fix.” It said: “Finkel has provided a roadmap for energy policy that is determined to set off the freeway of carbon pricing in any form and seek instead the scenic backroads of encouraging renewables without discouraging the burning of coal.”

Another paradoxical aspect of the Australian energy market is that despite massive reserves of natural gas and rising LNG exports, the current infrastructure is inadequate to deliver sufficient gas to domestic markets

Giles Parkinson, the editor of RenewEconomy noted that “Finkel has been focused on trying to find a pathway through the toxic energy politics in Australia, and accommodating the Coalition’s modest climate targets, rather than seizing the moment and outlining what can and should happen, and what Australia would need to do to meet the Paris climate targets.” 

Parkinson goes on to say, “Finkel suggests a wave of market and regulatory reforms, but appears to rely heavily on the Australian Energy Market Commission, whose snail-pace approach to reform and new technologies has driven most players crazy with frustration – apart from the incumbents, of course.”

Another paradoxical aspect of the Australian energy market is that despite massive reserves of natural gas and rising LNG exports, the current infrastructure is inadequate to deliver sufficient gas to domestic markets resulting in supply scarcities and price spikes, which have led to higher retail energy prices.

Adam Smith

Professor Iain MacGill, Joint Director of Centre for Energy and Environmental Markets (CEEM) at University of NSW said, “Finkel had the impossible job navigating between the challenge of affordability, security and environment, and the policy sensitivities of the present Coalition government, in particular its conservative wing.”

“As such, the report is more oriented towards political science than climate science,” adding, “It certainly provides a possible basis for breaking the present climate policy deadlock in Australia with its proposal for a clean energy target …”

In MacGill’s opinion, “Regardless of its limitation, the key work of implementing coherent and effective climate and energy policy still lies before us.”

“Australia’s electricity pricing problems do not lie in the costs of producing electricity…. the charge for transporting electricity and the charge for selling it is much more significant”

Bruce Mountain, Director of Carbon and Energy Markets (CME), writing in the Australian Financial Review (10-11 June 2017) said, “The remit of the Review, and Dr. Finkel’s approach to it, has been to focus on electricity production and in particular greater short-term power system security and a pathway to investment in lower emission generation in the longer term,” adding:

“Necessary and worthwhile as this may be, the main part of Australia’s electricity pricing problems do not lie in the costs of producing electricity. For all but the very biggest electricity users, the charge for transporting electricity and the charge for selling it is much more significant than the charge for its production. It is expansion in these network and retailers’ charges that explains Australia’s precipitate decline from the top to the bottom ranking in international electricity price league tables.  The issue underlying such dismal failure – political economy – remains completely untouched.”

Mountain adds, “Almost 250 years ago Adam Smith exhorted: ‘Consumption is the sole end and purpose of all production and the interest of the producer ought to be attended to only so far as it may be necessary for promoting that of the consumer.’ It is a famous phrase, cited as often as it is ignored.” 

There is certainly a lot to read in the Finkel report, and depending on one’s perspective and vested interests, there is something for most, if not in the whole, then certainly in parts of the blueprint. It remains to be seen how the blueprint’s recommendations will be implemented and when.

And as Parkinson, MacGill and Mountain point out many of Australia’s electricity market ills are political in nature – the most challenging to address. In the meantime, as Finkel warns, next summer’s heat waves, bushfires and storms are not far away. Politicians must act, sooner or later.

Editor’s Note

Fereidoon Sioshansi is a long-time energy consultant and author. He is also editor and publisher of EEnergy Informer, a subscription-based monthly newsletter that has been around for many years. This article was first published in EEnergy Informer and is republished here with permission. 

Sioshansi’s latest book project is Innovation and Disruption at the Grid’s Edge, published in June 2017. It contains articles by two dozen experts on “how distributed energy resources are disrupting the traditional utility business model”, including contributions from:

• Audrey Zibelman, CEO of AEMO and former Chair, New York Public Service Commission
• Michael Picker, President, California Public Utilities Commission
• Paula Conboy, Chair, Australian Energy Regulator, Melbourne, Australia
• Analysts from Poyri, CSIRO, TU Delft, University of Freiburg and many others

BMW Mini plant in Oxford

The UK government is proposing a ban on the sale of new petrol and diesel vehicles by 2040, in a move that echoes a recent announcement in France. Setting this sort of media-friendly target is a positive and welcome response to the challenge of air pollution across UK cities, write Richard Brooks and Jason Begley of Coventry University. But delivering the infrastructure, research and development support and incentives to switch to greener cars will be the hard part. Article courtesy The Conversation.

If conventional vehicle manufactures start getting nervous, then environment secretary Michael Gove may find the road to an electric future needs to be paved with more than good intentions.

Planned well, a ban on sales of conventionally fuelled vehicles could deliver long-term benefits for both air quality and economic investment in post-Brexit UK. There is no question that a switch to alternative-fuelled vehicles would significantly improve air quality in towns and cities. The actual benefit will not be felt for many years, however, given the slow replacement rate for vehicles. Still, it does establish a clear direction of travel for public investment and as battery prices are set to tumble over the next decade, it will be one more reason for businesses to switch to greener vehicles.

BMW has just announced it will build the fully electric Mini at its plant in Oxford

The 2040 target should encourage big electric vehicle manufacturers to invest in the UK. The country is a significant consumer market and has strong production capabilities in green technologies, especially the use of lightweight materials. BMW, for instance, has just announced it will build the fully electric Mini at its plant in Oxford. An even clearer example of policy driving private investment is Chinese carmaker Geely’s investment in a new hybrid model of the London taxi to take advantage of the capital’s new “ultra low emission zone”.

Then there is the question of infrastructure. The UK has 6,535 charging stations, which sounds like a lot. But compare that to Norway, which has slightly more stations for a population less than a tenth the size. The number of charging points will have to rise to the hundreds of thousands.

A big ask

New homes are required to have charging points by 2019, but installation costs £1,000 in existing houses. Subsidies can reduce the cost, but will need to be taken up on a vastly greater scale. And even this won’t help those dependent on on-street parking or multi-story living. A comprehensive infrastructure would certainly cost hundreds of millions. And even if successful, the government faces another headache – lost fuel duty could leave a hole in the budget of between £9 billion and £23 billion by 2030.

Equally important is the need to think about energy supply. The widespread adoption of electric vehicles could put a strain on the grid at a time when fossil fuels are being phased out and a higher share of more volatile renewables is taking over. This means the government will need to think seriously about how excess power is stored during the hot, blustery days that favour solar or wind farms, and how to manage demand from electric vehicles when there is not enough sun or wind.

“Electric vehicles are not simply catching up with conventional vehicles. They are overtaking”

For car manufacturers, 2040 is several production cycles away. This gives them and the government time to think creatively about mass electrification. Roads that charge your car as you drive would need a big initial investment but would make electric cars significantly cheaper and better.

Self-driving cars and the trend towards mobility being a service you buy on demand through firms such as Uber might mean some people eventually don’t need to purchase vehicles at all. But these technologies are still many years away from the mainstream.

This highlights a key point: that a shift to sales of alternative fuelled vehicles will not immediately reduce air pollution and will do nothing to impact on congestion. Only a more comprehensive policy of shifting people to different modes of transport will achieve this, and here the government’s commitment shouldn’t be relied upon.

On an optimistic note, there are good reasons to imagine that a shift to greener vehicles may occur anyway. Pete Harrop, chairman of industry analysts IdTechEx, is bullish, predicting driving ranges of up to 1,000 miles and electric vehicles that can harvest solar electricity and act as batteries to store renewable power. “Electric vehicles are not simply catching up with conventional vehicles,” he told us. “They are overtaking.”

It’s clear which way the wind is blowing. Norway, as market leader, wants to ban sales of new petrol and diesel vehicles by 2025, and the German upper house has debated a 2030 target.

By 2040, internal combustion engines may no longer be able to compete in the market. But whether the UK’s infrastructure is ready for millions more electric vehicles remains to be seen.

Editor’s Note

Richard Brooks is Research Associate at the Centre for Business in Society, Coventry University.

Jason Begley is Research Fellow at the Centre for Business in Society, Coventry University.

This article was first published on The Conversation and is republished here under a Creative Common licence and with permission from the authors.

California’s regulators are sensitized to new realities

The rapid transformation of the electricity sector will make it necessary for utilities to adopt radically new pricing methods, writes Fereidoon Sioshansi, publisher of newsletter EEnergy Informer and editor of a new book, Innovation & Disruption at the Grid’s Edge. According to Sioshansi, existing volumetric tariffs will increasingly be replaced by fixed service fees.

By now the narrative on the rapid transformation of the electricity sector driven by the 3Ds – decentralization, de-carbonization and digitization – is well-known.

Far less, however, is known about how this transformation is going to materialise, and when and who may be the ultimate winners as the incumbents’ traditional business models are disrupted.

Not surprisingly, there are as many predictions on the end game as there are analysts and experts following the developments. As I write in a recently published book titled Innovation & Disruption at the Grid’s Edge, in which a great many expert analyses are brought together: “…innovation and disruption enabled by new technologies – notably information & communication technology (ITC) – are transforming the electric power sector at an unprecedented pace … “

Charging based on volume is outdated and will become unsustainable as a means of covering the cost of the delivery network

One important change, as consumers will evolve into “prosumers” and then “prosumanagers”, is that the definition of electricity service, and more importantly how it is priced, will undoubtedly undergo radical transformation.

Bundled retail tariffs – designed for the one-directional networks of the past century with passive consumers – which are still prevalent nearly everywhere in the world, are clearly outdated.

Volumetric tariffs no longer capture the emerging value proposition offered by the grid – which offers connectivity, balancing services, frequency control, voltage stability and 24/7 reliability most coveted by increasingly sophisticated prosumers or prosumagers rather than delivering a large volume of kWhs.

Mobile phone industry

This suggests that the power sector is on a path not unlike that of the mobile phone industry where most users pay a fixed monthly fee based on a 2-year contract with a network service provider.

While the analogy is not perfect – e.g., currently electrons cannot be delivered without copper wires – it is clear that mobile phone service is increasingly about connectivity and access to the network rather than the volume or frequency of calls.

Subscribers choose a provider on the basis of the ubiquity and reliability of its network access, the strength of the signal, bandwidth and speed.

They are rarely charged anymore on a per-call or per-minute basis.

The regulators, who control all aspects of the business in most markets, are having a difficult time following the rapid technological changes taking place, let along being in a position to lead or encourage innovation

The cost of service is much better reflected, and collected, through a fixed fee almost regardless of the volume of service.

The same goes for garbage collection and many other services where the fixed costs account for the overwhelming percentage of cost of service.

Another reason why electricity service is moving in this direction is the fact that as the proportion of renewable generation on many networks increases, the cost of electrons – the commodity portion of service – is rapidly falling, eventually approaching zero, occasionally going negative. The kWhs are already relatively cheap and getting cheaper over time.

Thus, charging based on volume is outdated and will become unsustainable as a means of covering the cost of the delivery network.

Zero net energy

Moreover, with the advent of zero net energy (ZNE) buildings, the volume of consumption in many places is flat or falling.

The implication is rather clear: tariffs based exclusively or primarily on volumetric consumption are unlikely to deliver sufficient revenues, nor do they make much sense.

Moving towards the inevitable end, however, is not easy for a number of reasons:

• the path and pace forward looks different to different stakeholders who are often competing with conflicting views and perspectives;
• the incumbents don’t like being disrupted and/or becoming irrelevant; and, most important
• the regulators, who control all aspects of the business in most markets, are having a difficult time following the rapid technological changes taking place, let along being in a position to lead or encourage innovation.

This is evident, for example, in the current piecemeal and fragmented treatment of distributed energy resources (DERs) and net energy metering (NEM) in various parts of the US.

The value and/or the cost of DER resources, poorly understood, need to be better monetized and reflected in future tariffs, which must increasingly account for the bi-directional flows of electrons based on time, location and their value or impact to/on the distribution network.

Consider the following examples:

• A solar rooftop panel feeding a huge surplus – in excess of local consumption – to the distribution network on a cool, breezy, sunny day is not adding much value in a place like California, with its famous “Duck Curve”.
• By contrast, an electric vehicleor distributed storagedevice of any shape, form or size, taking unneeded excess electrons from the same circuit, and injecting it back after sunset, is providing a highly valuable service.

Current tariffs and regulations, with a few exceptions, do not fully or even partially recognize, monetize, reward or penalize for the vastly different cost/value of such resources.

Source: EEI

The good news is that regulators in states including California, Hawaii and New York – with the latter’s pioneering Reforming the Energy Vision (REV) – are beginning to address how the changing role of the distribution network will redefine the role of stakeholders, including better clarity on who can do what, when and where and under what types of rules, rewards and investment recovery.

Walk, jog, run

A number of such issues are covered in Innovation & Disruption at the Grid’s Edge.

In the book’s Preface, Michael Picker, President of California Public Utilities Commission (CPUC), says he has “chosen to focus actively at the CPUC on more tangible tasks that can deliver benefits quickly, rather than questioning the fundamental nature of utility business models,” adding “the overarching philosophy I have followed in pursuit of more distributed energy future can be described as ‘Walk, Jog, Run.’”

With so much on his plate, so to speak, the measured approach is understandable.

Picker goes on to say, “The vision we (the CPUC) are pursuing is that, over time, DERs will be able to benefit from ‘stacking’ multiple value streams.”

Stacking, of course, refers to the fact that DERs, depending on when, where and how they feed or withdraw from the network, imply costs or value, often from multiple sources, as the examples of the solar PVs and EVs (above) described.

The key question for the incumbents in the business, retailers, distribution companies, generators and gentailers, is how to survive – and hopefully thrive – in the energy transition

In this context, stacking entails improved monetization of the multiple benefits of DERs while – paradoxically – acknowledging their increased demands on the distribution network – for example, with high concentrations of PVs and/or EVs on certain distribution circuits.

California’s regulators are already sensitized to the new realities of DERs and other innovations and disruptions taking place at the so-called grid’s edge, referring to the intersection of the distribution network and customers’ meter and beyond- or behind-the-meter.

On this, Picker adds: “Targeting DERs to high-value locations also necessitates development of a tool to highlight areas of the distribution grid where DERs can provide location-specific values, such as distribution capacity deferral and voltage support.”

The key question for the incumbents in the business, retailers, distribution companies, generators and gentailers, is how to survive – and hopefully thrive – in the energy transition and the disruptions. With so many moving parts, uncertainties, and pitfalls, it won’t be easy.

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. He can be reached at fpsioshansi@aol.com.

Sioshansi’s latest book project is Innovation and Disruption at the Grid’s Edge, published in June 2017. It contains articles by two dozen experts on “how distributed energy resources are disrupting the traditional utility business model”, including contributions from:

• Audrey Zibelman, CEO of AEMO and former Chair, New York Public Service Commission
• Michael Picker, President, California Public Utilities Commission
• Paula Conboy, Chair, Australian Energy Regulator, Melbourne, Australia
• Analysts from Pöyry, CSIRO, TU Delft, University of Freiburg and many others

The European Commission has proposed to set up Regional Operational Centers (ROCs), which is a welcome step in the further integration of the EU internal electricity market, writes Philip Baker of the Regulatory Assistance Project (RAP). However, according to Baker, the proposal does not go far enough: more regional coordination is needed if consumers are to reap the benefits of market integration.

The regionalisation of Europe’s electricity markets is moving apace. It is estimated that regional day-ahead markets now cover some 85 percent of Europe’s consumers (by demand). Although the introduction and harmonization of regional intra-day markets is developing fast with the implementation of the cross-border intra-day market project (a joint initiative by the European Power Exchanges EPEX SPOT, GME, Nord Pool and OMIE together with the transmission system operators from 12 countries), the first tentative steps are also being made towards coordinated balancing areas that extend beyond national borders.

Crucially, ROCs would also have a decision-making capability in certain limited circumstances, such as regarding the availability of interconnector capacity made available to the market

Regionalisation will have many benefits. Not only will electricity consumers be able to access the cheapest sources of energy, but Europe’s electricity system will operate more efficiently through the pooling of risks, the exploitation of geographic diversity, and a reduced requirement to invest in new capacity.

Regionalisation will also greatly assist the deployment of new intermittent renewables, allowing capacity to be sited in the most favorable areas with energy surpluses and deficits balanced over wider areas. It is estimated that regionalisation has already resulted in savings of some €1.5 to €2.4 billion per year through market coupling, with the potential to reach €12.5 to €40 billion in 2030 if the EU electricity market is operated as a fully integrated market.

Highly interconnected

Yet, regionalisation has so far primarily focused on the market process. To make regionalisation a success and ensure it delivers in full, for example by maximizing the availability of interconnectors, it will have to be extended to system operation.

This is recognized by the Commission’s Clean Energy Package which proposes the introduction of Regional Operational Centers (ROCs) to carry out tasks of regional relevance. The Commission’s proposal for ROCs would build on and enhance the role of the Regional Security Coordinators (RSCs), mandated and formalized into European law through the System Operation Guideline. Like the RSCs, the ROCs will complement the role of Transmission System Operators and perform activities of regional relevance such as allocation of interconnection capacity, risk preparedness, sizing of balancing reserves, and identifying the contribution to be made by external generation resources to national capacity markets.

If Member States and stakeholders are to accept a regional approach to ensuring resource adequacy, reliability, and market efficiency, ROCs will need to be seen as independent and operating in the interests of the region as a whole

While the Commission’s proposals for ROCs are welcome, the proposals could have gone further in promoting a coordinated approach to the operation of Europe’s highly interconnected transmission system, supported by appropriate developments, both in terms of the competences attributed to the ROCs and of governance arrangements. If we are to have truly effective regional electricity markets, then the regionalisation of system operation, governance and competences need to keep in step. At the moment, system operation and governance are failing to keep up with the regionalisation of markets.

Crucially, ROCs would also have a decision-making capability in certain limited circumstances, such as regarding the availability of interconnector capacity made available to the market. This decision-making capability, which transmission system operators (TSOs) could only ignore if system safety is at risk, is vital to ensure a regional dimension to transmission system operation, complementing and supporting the regionalisation of the electricity market.

Regional crises

So what should be done? We recommend a number of approaches that could be taken.

Assign a greater role for ROCs in resource adequacy assessment. The value of assessing resource adequacy on a regional level is recognized by the Commission’s proposals, which require ROCs to carry out short-term adequacy assessments and, if delegated by the European Network of Transmission System Operators for Electricity (ENTSO-E), to participate in preparing seasonal assessments. This regional approach to resource adequacy should be replicated in investment timescales with ROCs having a role in the Europe-wide assessments carried out by ENTSO-E. The availability of regional resource adequacy assessments would complement the Europe-wide assessments and inform the national monitoring carried out by Member States, for example by identifying capacity support to be expected from neighboring systems. 

ROCs best placed to identify and manage regional crises. ROCs will, in time, develop the regional knowledge, expertise, and analytical capability to identify regional crisis scenarios more effectively than either ENTSO-E or individual TSOs. As such, ROCs need a greater role in identifying regional crisis scenarios and in coordinating responses to regional crises when they occur. Where events extend beyond national borders, no Member State or TSO will have the ability to see the whole picture and to identify the most appropriate responses. In contrast, ROCs will have information from across the region and be able to coordinate responses to ensure the best outcome from a regional point of view. Releasing the potential of ROCs to manage regional crises will, however, require them to have a real-time decision-making capability.

Recognize the potential for ROCs to coordinate the real-time operation of market-sensitive assets. While, the near real-time “operational planning” role currently envisaged for the ROCs clearly allows them to influence real time activities, this could ultimately be extended to providing the real-time operational coordination necessary to allow efficient and safe regional market operation. This may be a step too far for Member States to entertain at this stage. However, the benefits of real time coordination will become apparent as confidence builds in ROC capabilities and the focus shifts from implementing market regionalisation to ensuring that those markets operate at maximum efficiency. Nothing in the Clean Energy Package should prevent the potential benefits of regional operational oversight in terms of market efficiency and system safety from being realized. 

The whole process should be transparent and in the public domain, and sanctions should be available to deter TSOs from acting against the interests of the region

Establish ROCs as independent entities with a clear mission to act in the interests of all electricity customers in the region. If Member States and stakeholders are to accept a regional approach to ensuring resource adequacy, reliability, and market efficiency, ROCs will need to be seen as independent and operating in the interests of the region as a whole. It will also be necessary to develop a process for the meaningful participation of stakeholders. This must allow the involvement of stakeholders in defining the rules and methodologies that will underpin the governance of ROCs and in the process of monitoring their activities and performance.

Give ACER a greater supervisory role. Given that ROC activities will extend beyond the reach of individual national regulatory authorities (NRAs), it is appropriate that the Agency for the Cooperation of Energy Regulators (ACER) takes a greater role in monitoring and supervising ROC operations, for example by organizing groupings of regional NRAs. ACER should have a clear role in the establishment of ROCs and in the development of their governance arrangements. In addition, ACER should be empowered to make binding decisions where ROC actions are inconsistent with EU-level objectives, internal energy market rules, or the interests of consumers in the region as a whole.

Introduce a legal mechanism for promoting public scrutiny. TSOs will always need to have the ability to disregard ROC decisions where they can demonstrate compliance would jeopardize the safety of the national system, i.e. if operational security limits cannot be maintained. However, when TSOs decline to implement ROC decisions, a public process is needed to review the appropriateness of the TSO action. The TSO should report the reasons for declining to accept a ROC decision (or recommendation). The ROC concerned should have the opportunity to review and issue an opinion on the TSO justification and, if there is disagreement, ACER could investigate and adjudicate. The whole process should be transparent and in the public domain, and sanctions should be available to deter TSOs from acting against the interests of the region.

Times of stress

The Commission’s proposals to enhance the role of the RSCs and to create ROCs are a welcome move in the right direction. However, more could be done to exploit the potential of ROCs in performing tasks of regional relevance and benefit such as resource adequacy assessment and dealing with crises that extend beyond national borders.

In addition, the Commission’s proposals for regulating ROCs and supervising their activities fall short of what is necessary. If regional electricity markets are to operate effectively and safely, particularly in times of stress, then ROCs need the independence and authority to coordinate national responses in the interests of all regional electricity consumers.

Editor’s Note

The Regulatory Assistance Project (RAP) is a globally operating independent and nonpartisan team of experts. Philip Baker (pbaker@raponline.org) is an energy consultant working with RAP and other clients on power system technical and commercial issues, integrating renewable energy sources, and European electricity market integration.

Paris Autolib EV car sharing system

The success of the clean energy transition will depend to a large extent on the actions of local and regional authorities. Sustainability officers from Paris, Sabine Romon, and Vienna, Bernd Vogl, explain what clean energy goals they have set themselves and how they are planning to achieve them. “The thing to start with is the infrastructure”, says Vogl. “The first task is to work on our public buildings”, says Romon, who warns that Paris’ ban on diesel cars from 2025 on will be strictly maintained.

It is one of the toughest challenges cities face today: how to speed up the adoption of clean energy technologies and innovation to help the climate – and improve their own environment. It involves changing the behaviour of their citizens – never an easy thing to do. “How to do this is the hardest question to start with,” says Bernd Vogl, Head of the Energy Department of the City of Vienna and charged with the management and coordination of the Viennese energy programs.

Sabine Romon, his French counterpart and Chief Smart City Officer at the City of Paris, agrees this is not easy. “Parisians working together on climate: That will be the big part of a new climate plan that Paris will issue next month,” she says.

Bernd Vogl

“We have developed a solar power plant where the people can invest in solar power. That is really a good way to bring topics to the people and give people a chance to invest money in the right way”

Both Romon and Vogl will participate in a panel discussion at the Inno Energy Business Booster 25-26 October in Amsterdam, which will focus on the role of public actors in the energy transition (note: you can register at 50% normal price with code Energypost_TBB here). Although there  is a lot of enthusiasm among the public for clean innovation, there is growing recognition that a ‘final push’ is needed to get people to act on their beliefs. Public actors are important in this process for two reasons: they can take measures to affect public behaviour – and they can set a good example by investing in their own property.

Ambitious goals

The climate plans of the Austrian and French capitals burst with ambition. Vienna (1.8 mln inhabitants) wants it greenhouse gas emissions reduced with 80% in 2050 (from 1990 levels); Paris (2.2 mln) has set itself a target of 75% reductions in 2050 (from 2004 levels).

No ambitious goals without a package of concrete measures to realise them. The report Vienna ahead! outlines the measures Vienna is taking, ranging from e-mobility to innovative re-use of waste heat, while Paris, Intelligent  Durable (download in French) sketches a future city where clean energy technologies, big data and public participation go hand in hand to create a sustainable and resilient city.

“I think the first thing is to start with the infrastructure,” says Vogl. “For example, if you don’t have bikeways, you will not have cycling. So, we have a strong focus on developing infrastructure in the right way. This is also true for the energy sector. We own our energy company and we try to develop together with them solutions in the field of district heating, in the field of renewable energy. And we have developed a solar power plant where the people can invest in solar power. That is really a good way to bring topics to the people and give people a chance to invest money in the right way.”

Sabine Romon

“In collaboration with energy companies, we are collecting data on energy consumption. We want to be aware of what is really needed in the entire system”

“The first task for the city is to work on its public buildings, to give a good example to the public,” adds Romon. “Then it becomes easier to achieve results in the private sector. We created a climate agency that is working with co-owners of private buildings to convince them to renovate their buildings and reduce energy consumption. That is a long-term project, because we cannot force owners. But we have an incentive, because there is an obligation to clean the facades of the buildings. So when they do that, we can ask them to do it in a way that reduces energy consumption. We can also give some funding and advise them to find the best constructors.”

Paris is also trying to help reduce costs for homeowners who want to refurbish their buildings. “In certain areas in Paris we try to identify what buildings will need renovation. And so, if we find one building that is willing to do some renovation work, we look around if we find similar buildings, so they can share and reduce costs by doing the work around the same time. They can reduce costs on equipment like solar panels, heating, window insulation, wall insulation etcetera.”

Big data

Like Paris, Vienna’s city plan is strewn with big building blocks, subdivided into privately owned apartments. According to Vogl, that is a bottleneck in implementing energy efficiency programs. “It is in the building sector where you can reduce a lot of energy use. We have had a large renovation and refurbishment program since 2000, and we have done a lot to reduce energy use. It’s easy in some sectors, like social housing, which is controlled by associations. But if you want to go into sectors where flats are privately owned, it’s very hard to get a decision to invest in measures because every flat owner has to agree.”

So, next to programs focused on individual house owners, both cities resort to measures that include the districts as a whole. Energy management and big data are the key words here, say both Romon and Vogl.

“We have a program to look for hot water beneath Vienna at a depth of 6 kilometers”

One eye-catching project is the so-called Eco-district in the northeastern part of Paris, Clichy-Batignolles, a 54 hectare urban redevelopment project started in 2009 and still under construction. “Buildings in this district are heated with geothermal water,” explains Romon. “As for electricity, a lot of solar panels provide for energy for schools, houses and offices.  We would like to follow the energy consumption in that district to be able to manage all the energy consumption of the district, and not only building by building. Therefore, in collaboration with energy companies, we are collecting data on energy consumption. We want to be aware of what is really needed in the entire system.”

Vogl knows of this project – and views it as a good example of smart city innovation. Vienna also experiments with district heating, he says. “The main topic in my department of city development is to find solutions in the heating sector and the building sector. Our heating system used to depend on oil and coal, then on gas and renewables, and now we have to change to renewables and to waste heat and geothermal heating. We like to force this into our energy mix. We try to find renewable energy for our district heating systems: that is waste heat and geothermal heat to be developed in the next 10 years.  We have a program to look for hot water beneath Vienna at a depth of 6 kilometers. And the other focus is on waste heat, we have a lot of it in the city and we are looking for ways to use this also in our district heating systems.”

Fast charging

Another key issue for Vienna and Paris is smart mobility. This is an area where urban planning and clean technologies meet, say both sustainability officers. For not only is it important to get Viennese and Parisians out of their fuel powered cars, but also into other ways of moving around – walking, (electric) biking, electric car sharing, public transportation and the like.

Paris announced December 2016 that it wil ban all diesel cars from 2025, like other big cities such as Madrid, Athens and Mexico City. A measure that will be strictly maintained, warns Romon: “Those who do not comply with the regulations can be fined.”

In the meantime, Paris is unrolling a vast network of  charging stations for electric cars. Next to the e-car sharing network Autolib with 750 stations spread over the city since 2011, Paris has been developing its Belib-charging system for private electric cars since 2016. This has now 100 loading points. All of this must help reduce CO2-emissions by 20% in 2020.

Vienna has about 500 loading points situated mainly in parking spaces. Both cities foresee a growth of charging points in the years to come, but important adaptations have to be made in the meantime.

Meet with Maroš Šefčovič and Bertrand Piccard at InnoEnergy’s Business Booster event in Amsterdam – and save €350 when you register with Energy Post

Both Romon and Vogl will participate in the InnoEnergy Business Booster 25-26 October in Amsterdam. Dozens of energy startups from across Europe will showcase their innovations and make pitches to attract the interest of investors. An accompanying two-day conference will feature many prominent keynote speakers and panellists, including EU Vice-President Energy Union Maroš Šefčovič and Bertrand Piccard of the Solar Impulse Foundation. We have agreed with organisers InnoEnergy that our readers can join for half price saving you €350. All you need to do is quote our unique code: Energypost_TBB when you register here. We will be there so we hope to see you in Amsterdam soon!

Romon: “These stations are slow or middle charging stations: fast charging is too heavy for the grid. What is needed is management of the grid, so that you can charge your car according to what is available on the grid. I don’t think we want to have a grid that can charge all the e-cars  at the same time, but a more flexible grid to which people will adapt, for example by charging their cars at different moments. So here also we are working with companies like Engie to collect data for this purpose.”

Vienna already worked hard on reducing the number of cars, claims Vogl. The share of cars in Vienna’s total transportation modes went down from 40% in 1993 to 28% in 2014. The hardest part is yet to come, he says, from 27% to 20% in 2025 and 15% in 2030.

“We are starting to invest in the infrastructure of electric cars by now, although for companies it is not yet a very profitable market yet. But the business models of the energy supply will change. Within ten years, we will have a lot of electric cars on the streets, so we must have a plan. We are installing charging stations now, we have an electric bus in our public transport system and we try to develop electric taxis.”

Vogl says that “ten years ago, we had our strategies, but no electric cars. But the car industry is changing rapidly towards electric models, and I am optimistic this will change the transportation system in the city completely. For example: if you change the cars of Vienna completely to electricity, we will reduce our CO2 emissions by more than 50%.”

Editor’s Note

Some changes were made to this article on 16 October 2017.

German Green Party Congress 2017 in Berlin

While a government is being formed in Berlin, which will have important implications for the future of the Energiewende, author and scholar Professor John Mathews of Macquarie University in Australia, looks back on what Germany has achieved so far with its unique energy policy and concludes that it has been a spectacular success, whatever its detractors may say. But he also has some advice to offer: the German government, he writes, should be promoting the building of a European supergrid, and actively invest in storage and electric car charging infrastructure. Courtesy Global Green Shift.

The German government has been promoting renewables ever since the passage of the Renewable Energy Law in the year 2000. In 2010 the ‘grand coalition’ government led by Dr Merkel strengthened the promotion of renewables through raising the level of feed-in tariffs payable to producers. Then the Merkel government announced, in 2011, after the Japanese Fukushima nuclear disaster, that nuclear power would be definitively phased out within a decade, by 2022. These several actions constitute the core of the ‘energy transformation’. Germany is the most advanced industrial country to attempt such a thoroughgoing transformation of its energy sector, and its results carry global implications.

The Energiewende has been subjected to relentless attack ever since its inception, both within and outside Germany. The gist of the criticism is that the German energy transformation has achieved too little, and at too high a price. Both assertions are easily rebutted by looking at the evidence – which is what I do in this fresh post to the www.globalgreenshift.org blog.

The story of the Energiewende can be told with reference to two original charts, one showing the electric energy generated in Germany over the past decade and a half (from 2000, the year of the Erneuerbare Energien Gesetz, or EEG) and the other showing changes in electric generating capacity over the past decade. (My thanks to Ms Carol Huang for her assistance in producing these charts.)

Figure 1. German changes in electric energy generation, 2000-2016

Chart 1 reveals that total annual generation of electricity in Germany has barely shifted over the past decade and a half; it was just under 500 terawatt-hours (500 TWh or 500 billion kWh) in the year 2000 and just over 500 TWh in 2016. But within that (more or less) constant total the changes in structure of the electric power system have been striking. Three major changes can be identified as part of the public policy in Germany driving the Energiewende – the promotion of renewables; the phase out of nuclear; and the shift to gas within the fossil fuels.

First there is the promotion of renewables, that began in earnest with the passage of the Renewable Energy Law (EEG) in 2000 and the introduction of the German innovation of feed-in tariffs. These provided an incentive to local producers of renewables, who under the law would be paid a certain price for renewable energy and would be guaranteed access to the grid to sell it. (There was a phased reduction or de-escalation of the feed-in tariff over time, but lawmakers were unable to keep up with the dramatic cost reductions achieved by renewables – particularly solar.)

Chart 1 reveals that renewables should generate more power than coal by the year 2020, crossing over at about 200 TWh per year

How well this has worked is abundantly clear from the chart. Renewable power generation was around 35 TWh in the year 2000 (much of this due to hydro). It was already picking up in 2003, when it was at a level of 43 TWh (comparable at the time to the level of electricity generated from gas) and rising to 181 TWh in 2016. The headline result is that renewables as a proportion of electricity generated have risen from 5% in 2000 to 34% in 2015/16 – a green shift of nearly 30% in a decade and a half. (The 2016 total fell back a little from 34% to 33% but the 2017 total so far appears to be resurging.)  In just the last 10 years the green shift has seen the proportion of renewable power increase from 16% in 2007 to 34% in 2016 – an 18% shift to green in just a decade. This is an epic result for a system as large as the German – and is far and away (in my view) the greatest achievement of the Energiewende.

Second there is the phase-out of nuclear. Already by the year 2002 there was a government commitment to phase out nuclear – with a deadline set initially at the year 2022, i.e. within 20 years. The reduction in electric energy generated from nuclear sources began around 2006, when it started a decline that has been relentless right up until the present. Over the decade from 2006 to 2016, nuclear generation has declined from 159 TWh in 2006 to 80 TWh in 2016 – or a drop of 79 TWh, falling far short of the increase in power generated by renewables.

The proportion of power generated from nuclear over the same period declined from 12.5% in 2006 down to 5.5% in 2016 – or a 7% decline in a decade. So the expansion in renewables over the past 10 years has more than compensated for the decline in nuclear power. Renewables have grown from 68 TWh in 2006 to 181 TWh in 2016 – or growth of 113 TWh, compared with the decrement of 79 TWh for nuclear. The widespread fear that German renewables would not be able to substitute for nuclear has proven to be unfounded.

Third there has been a moderate reduction in the burning of coal – which was on the way down in the early years of the Energiewende, but then staged a recovery, with coal enjoying a local peak in consumption by power generators in 2013 and it is only now resuming its downward trend. At the same time gas saw a decline as coal consumption bulged, but gas is now increasing again, particularly since 2015, which is only to be expected. It is the continued dependence on coal which has been the least successful aspect of the Energiewende, and the one which is most in need of sustained policy attention in Germany.

Why the German NGOs are not shouting these results from the rooftops is a mystery – they are truly extraordinary results, demonstrating a determination and ambition that is unique in the developed world

If present trends are allowed to continue, the shift in proportion of renewables (18% over the past 10 years), will result in a further such shift over the next 10 years, i.e. to reach a 36% shift over 20 years. Germany would be well on the way towards eliminating coal as a source of power. Chart 1 reveals that renewables should generate more power than coal by the year 2020, crossing over at about 200 TWh per year.

Quite remarkable

When we turn to capacity shifts, as shown in Chart 2, the situation is even more dramatic. Taking our span as the decade from 2008 to 2017, we see that power capacity drawing on renewable sources has increased from just under 40 GW in 2008 to just over 100 GW in 2017 – or more than 60 GW in the decade. Over the same period the capacity that is nuclear powered has declined from 20 GW in 2008 to just 11 GW in 2017 – meaning that there is little nuclear capacity left in the German system to eliminate.

The green shift in capacity is quite remarkable – with renewables rising as a proportion of electric capacity from 30% in 2008 to 52% in 2016 (and even higher if we count the interim 2017 results). That’s a 22% green shift in capacity in just a decade – compared with an 18% shift in terms of electric power generated. Why the German NGOs are not shouting these results from the rooftops is a mystery – they are truly extraordinary results, demonstrating a determination and ambition that is unique in the developed world.

The driver of all this is of course costs, which have declined precipitately over the past decade while the Energiewende has been in full swing. Costs of solar PV have fallen by 60% since 2009 – at least in California, according to the NREL (National Renewable Energy Laboratory).

The US NREL has tracked the costs of generating solar PV since 2009. In that year (Q1) the cost of residential rooftop solar PV was 7.1 cents per kW, compared with 2.93 cents in Q1 2016 – a drop of 60% over 7 years. (US Solar Photovoltaic system cost benchmark Q1 2016, at: https://www.nrel.gov/docs/fy16osti/67142.pdf)

Does it matter that the green shift in terms of capacity does not correspond to the green shift in terms of power generated? No it doesn’t. It makes sense that the shift in terms of capacity would exceed the shift in terms of electricity generated because nuclear and coal fired power stations tend to have a higher utilization rate than renewables.

The real achievement of the Energiewende is that it has transformed the German energy system in just a decade and a half, ensuring that it is a rising industry, taking over from coal and residual fossil fuels as well as nuclear. The shift is reflected in terms of employment; in terms of investment; in terms of reduced burden on balance of payments for fossil fuel imports; and in terms of engagement with the energy industries of the future (rather than sticking with the energy systems of the past, as the US is doing under Donald Trump). In this sense Germany is emerging as the world’s only serious competitor for China, which is leading the way into the new 21st century energy industry.

Carbon emissions have indeed not fallen by all that much, but that is due to continuing use of fossil fuels in transport and industry

The real losers of the Energiewende have been the big coal-burning and nuclear-power companies, led by the grid giants RWE and E.ON, which enjoyed virtually guaranteed profits for decades. But the last decade of success of the Energiewende has upset these cosy arrangements. The share prices of both RWE and E.ON have plunged, and both companies have been forced to restructure.

In 2016 E.ON took the initiative and split itself into two, with E.ON retaining the renewables and grid parts of the business and a new vehicle, Uniper, taking over the fossil fuels and nuclear operations. Then in 2017 it was the turn of RWE, where a new vehicle, Innogy SE, was created for the renewables activities. Already, by March 2017, the market capitalization of Innogy stood at 18.9 billion Euros (US$20 billion), which was more than double the value of its parent RWE.

Critical chorus

The Energiewende has attracted a critical chorus – from the Financial Times (the ‘absurdity of German energy policy’), The Economist (“It’s not easy being green”), Forbes (‘What is so revolutionary about Germany’s Energiewende?’), Forbes again (‘Germany’s green energy policy disaster”), Fortune (‘Germany’s high-priced energy revolution’) et al.[1]

Some of the criticisms are simply laments at the fading fortunes of the primary power generators, RWE and E.ON. This was the case with the Forbes article ‘Germany’s green energy policy disaster’ (January 2017) which simply listed the ways in which the shares and net worth of shareholders in RWE and E.ON were being disadvantaged by the Energiewende – without ever asking whether the companies had been too slow to see the coming changes, and been less than enthusiastic in embracing renewables.[2]

The gist of the main criticisms is that the Energiewende has achieved modest results at a very high price. The criticisms are that it has not reduced carbon emissions by all that much; it has been too expensive; and coal burning remains on a massive scale.

Well – carbon emissions have indeed not fallen by all that much, but that is due to continuing use of fossil fuels in transport and industry. These too need to be cleaned up – but you cannot blame the Energiewende with its focus on electric power generation for that outcome.

Yes, it has been expensive because Germany has been paying generous FiTs for renewable energy supplied to the grid. There was no alternative in the year 2000 when these payments started in earnest. But since then costs of solar PV and wind power have plummeted and so the German government has been able to reduce the FiTs paid accordingly – and in 2016 actually went all the way and introduced public auctions as a way of setting the future FiTs to be paid.

A focus on greening cities, rather than just single sectors taken one at a time, is called for

So the German Energiewende has been expensive because Germany was a first mover and introduced FiTs when solar and wind power was still costing much more than fossil fuels. But now the renewables cost less, and their costs are continuing to fall – so other countries don’t need FiTs, and can actually introduce their own energy transformations without any public subsidies at all.

In fact Germany itself could abandon payment of fresh FiTs for new installations of renewables and allow them to ride the downward cost curve associated with the global learning curve – now that they have been established. And that would enable Germany to confront head-on the issue of legacy subsidies still being paid for fossil fuel supplies – to move to a market-based system across the board.

The fact that coal burning is still at a high level in Germany is the one source of criticism of the Energiewende that really counts. And that is where a carbon tax that would force the pace of a switch to electric vehicles in transport and away from coal in energy-intensive industry (like steel and cement) – if a carbon tax could be made politically acceptable in Germany.

Entrepreneurial forces

The real result of the Energiewende so far (and it is a work in progress) has been its transformation of the German energy sector, and the unleashing of fresh entrepreneurial forces that usher in the new and drive out the old.[3] This is the very essence of Schumpeterian competition, where the new destroys the old, sweeping it away in a gale of ‘creative destruction’. Just focusing on whether there have been sufficient reductions in carbon emissions (unlikely unless the energy transformation were allowed to encompass transport and industry as well as power generation) clearly falls short as a lens through which to view the Energiewende. Its very breadth and ambition is what marks it out as the only real competitor worldwide for what China is accomplishing in the renewable energy space.

A European Supergrid would provide the infrastructure needed for market exchange of renewable power, which would curb the recent price increases being inflicted on individual countries by fossil fuel dinosaurs

But the costs are still high, and need to be brought down if the energy transformation is to retain its political support in Germany. The Minister of Energy and Industry, Sigmar Gabriel, who is the current driver of the Energiewende, has stated openly that Germans have reached ‘the limit of what we can ask of our economy’ – meaning that costs have to be reined in.[4] And the most obvious way to rein in costs is to change the pricing structures of the electric power grid, allowing new players to enter and offer services that supply renewable power at low marginal cost – without maintaining large fossil-fuelled plants that remain unused for most of the time. These are political challenges that need to be met in the political arena.

Decisive role

What then needs to be done? Claudia Kemfert, a prominent German energy economist, wrote a Commentary for Nature in September where she called for action around three priorities to be tackled by the incoming government after the September 24 elections.[5]

First is to phase out coal, whose elimination from the German energy system is long overdue. Professor Kemfert is surely correct on this point. I have indicated above that Germany could safely eliminate fresh feed-in tariffs now in support of renewables, given that their costs have fallen so dramatically – and at the same time eliminate lingering subsidies paid on fossil fuels. Kemfert quotes a figure of $57 billion paid in subsidies to fossil fuels – far outranking the remaining subsidies paid to renewables via the feed-in tariffs. The German Greens would make a smart choice if they demanded an end to the fossil fuel subsidies in return for dropping fresh subsidies paid to renewable via feed-in tariffs. (Of course there are payments to be made to renewable energy providers under the 20-contracts entered into, which cannot be broken.)

Germany could play a much more decisive role in promoting the coming shift to electric transport, by emulating (and improving on) the Chinese efforts to create a vibrant 21st century electric vehicle ecosystem

Second, the Energiewende could be better integrated with wider concerns over the need for a shift to electric vehicles and energy efficiency, in both buildings and industry. A focus on greening cities, rather than just single sectors taken one at a time, is called for – and here one can only agree, emphatically.

Third, there should be more government investment in R&D (Kemfert quotes data revealing how low Germany’s contribution on this point is) as back-up to Germany’s successful focus on promoting solar and wind power. Kemfert cites the need for much more R&D on energy storage as the emerging sector. Again, no quarrel with that.

I would add to these priorities three more issues calling for attention. The first is the necessity for Germany to lead in building a trans-European Supergrid that is equipped with smart meters and other IT devices to enable it to accommodate fluctuating renewable energy supplies. Germany was one of the proponents of the future-oriented Desertec project, linking producers of solar power in the deserts of North Africa with an upgraded European grid – but that project has failed for lack of support from German industry. Here is where government funds could sensibly be spent to revive the idea. And a European Supergrid would provide the infrastructure needed for market exchange of renewable power – buying and selling – which would curb the recent price increases being inflicted on individual countries by fossil fuel dinosaurs.

Second Germany could meet Chinese competition in the emerging clean energy sector by direct intervention in the German economy, emulating the Chinese practice that has propelled China to world leadership so quickly. A good place to start would be in energy storage, where technological directions and technological competition is still fluid (via standards, patents and public infrastructure development – such as charging stations for electric vehicles).

Third, Germany could play a much more decisive role in promoting the coming shift to electric transport, by emulating (and improving on) the Chinese efforts to create a vibrant 21st century electric vehicle ecosystem. The first step is to ban the sale of new gasoline and diesel-powered vehicles – which France and the UK have already done with respect to a deadline year of 2040. But China has taken a decisive step here, announcing its clear intention to move to outlaw sales of new internal- and external-combustion engine vehicles by a date yet to be announced – shaking the global automotive industry.

The incoming German government election could look to making a similar announcement – to kickstart the serious development of a new clean vehicle industry in Germany.

Acknowledgment: The efforts of Ms Carol Huang in preparing the charts and assisting with the research for the article are gratefully acknowledged.

Editor’s Note

This article was first published on John Mathews’ new blog Global Green Shift and is republished here with permission.

[1]  Financial Times editorial, ‘The absurdity of German energy policy’, November 26, 2014, at: https://www.ft.com/content/01e65008-74a6-11e4-b30b-00144feabdc0; ‘It’s not easy being green’, The Economist, August 11, 2016, at: https://www.economist.com/news/europe/21704819-even-new-reforms-doubts-remain-about-germanys-energy-transition-its-not-easy-being-green; William Pentland, What is so revolutionary about Germany’s Energiewende? Forbes, December 7, 2015, at: https://www.forbes.com/sites/williampentland/2015/12/07/what-is-so-revolutionary-about-germanys-energiewende/#40b018945160;  and Jeffrey Ball, Germany’s high-priced energy revolution, Fortune, March 14, 2017, at: http://fortune.com/2017/03/14/germany-renewable-clean-energy-solar/.

[2] Panos Mourdoukoutas, Germany’s green energy policy disaster, Forbes, January 22, 2017, at: https://www.forbes.com/sites/panosmourdoukoutas/2017/01/22/germanys-green-energy-policy-disaster/#61c1973071b7

[3]  This is the perspective of the excellent historical treatment of the Energiewende as a product of democratization provided by Arne Jungjohann and Craig Morris in their book Energy Democracy: Germany’s Energiewende to Renewables (2016), now complemented by a website ‘Energy Transition: The global energiewende’ at: https://energytransition.org/

[4]  Jeffrey Michel, Can Germany survive the Energiewende?, Energy Post, March 13, 2014, at: http://energypost.eu/energiewende-doomed/

[5]  Claudia Kemfert 2017. Germany must go back to its low-carbon future, Nature, 549, 26-27 (7 September 2017), at: https://www.nature.com/news/germany-must-go-back-to-its-low-carbon-future-1.22555

German utilities claim that they are becoming consumer-centred, service-based organisations, but research from Oliver Wyman shows that in actual fact their market share in the digitalized retail market is very small, writes energy economist Marius Buchmann of Jacobs University in Bremen. But they may still deliver on their promise: they are ready to launch digital attackers. Article courtesy of Buchmann’s blog Enerquire.

Utilities around the globe are currently adapting their business model to the 3 Ds “Decentralization, Decarbonization and Digitalization”. Especially in the medium and long run it seems to be the consensus that utilities need to change their asset-based business model towards a service-based model.

We have discussed in an earlier post (see here for details) a range of potential business models for utilities from a pure asset-focus to digital service companies. Most prominently, the two German utilities E.on and RWE split their core business units into two different companies: an asset-based and a service-based part (though in both cases the service-based part is backed up by regulated income from network ownership and operation, for more details on the strategies of E.on, Innogy and RWE take a look here). Other utilities around the globe are acting similarly or are currently in the process to develop a service-based approach.

Two areas in the service-based area seem to become very important now, at least for the private household sector: smart home assets & applications (enabled by the Internet of Things – IoT) and digital products that are based on data rather than assets.

Utilities do not have a dominant position in the smart home market (yet?)

The smart home market is highly competitive and nearly all utilities as well as big players from other industries like Google, Apple and Ikea have entered the market as well. Though the utilities have the advantage that they already have their customer base and different existing contact channels, they are still struggling to gain a foothold in the smart home market.

Figure 1: How users in the US adopt their smart home devices (McKinsey, 2016)

Figure 1 shows that those households in the US that already use smart home applications for utility management (thermostat, lightning etc.) prefer to buy these devices directly and not very often choose to buy such devices from the utilities.

Even though the data from McKinsey (2016) shows that utilities cover about 15-20% of the relevant market, utilities do not have a dominant position in this market. Even contractors or cable companies reach similar market shares at around 12-15%, despite the fact that they do not have the utilities’ energy expertise.

I do not have the similar data on the German market available, but the experience from the US might serve as a good estimate, even though the German market is less mature than the smart home market in the US.

Utilities struggle with digitalization – especially in retail

Similar to the smart home market, utilities are struggling to make use of digitalization in the customer segment. Last week, I met with Dr. Thomas Fritz who is a Partner at Oliver Wyman consulting group and who presented to me the Digitalization Index German Utilities developed by Oliver Wyman.

The index aims to indicate how German utilities are performing with respect to digitalization. Figure 2 gives an overview of the different parts of the electricity supply chain and how each segment performs with respect to digitalization.

Importantly, Oliver Wyman used a best-in class approach, meaning that the full score of 100 represents an available digital solution in the market, not the theoretical potential (Oliver Wyman, 2017).

Figure 2: Digitizing electricity in Germany – survey results by Oliver Wyman (2017)

Though the index is only indicative and the degree of digitalization differs between the individual utilities in Germany, the results for the B2B and B2C retail sector are quite disillusioning. Both segments score the lowest of all segments of the electricity sector with respect to digitalization.

If we take into account that the network segment reached the highest score in this index, and if we also take into account that the distribution grids in Germany (at least on the low-voltage level) are a black box where even the DSOs do not have much data available, then the low score of the retail sector becomes even more astonishing!

Leaving aside the question whether the index gives a realistic picture (and I think it is a quite good estimate of the current situation) the relation between the different results in the different segments tells us that the retail sector on average has not yet picked up the potential of digital processes and services.

This finding by Oliver Wyman (2017) contradicts large parts of the current public discussions about the future business case of utilities in Germany. As we have already discussed in these posts here and here the larger utilities in Germany shifted their core business model from an asset-based towards a service-based model. At the heart of service-based business models sits the retail business. But according to Oliver Wyman (2017) it is this retail sector that has not yet adapted many digital processes or products, even though they are available on the market.

So, the claims of utilities that they are becoming consumer-centric service-based companies seems to be, at least for the digital part of this segment, a future goal, not the status quo. This is even more surprising as there are already plenty of digital products in the market that could be used by the retailers. German companies like Beegy, in.power and Digital Energy Solutions (part of the BMW Group) already provide new services and products for private as well as commercial/industrial consumers that are completely digital, e.g. in the realm of energy management, forecasting, community flats etc. These products are the current benchmark for retailers in Germany.

Digital attackers enter the German energy sector – a new way to accelerate the digitalization of retail business?

Some utilities have already responded to the challenges arising from digitalization in the different segments of their business. Similar to other sectors, e.g. finance, different utilities are currently setting up and launching their digital attacker subsidiaries.

Basically, the idea is to set up new companies that are entirely based on digital processes and provide digital services and that operate independently from the utilities’ core units. This greenfield approach allows the utilities to develop, test and optimize digital processes and services much faster than this would be possible within the utility itself, whose operations are based on complex structures (IT as well as managerial) that slow down the innovation process.

Developing and launching a digital attacker for the retail business takes less than a year and provides utilities with the chance to reach (or at least get closer to) a degree of innovation that is normally only found at the start-up level.

Whether this approach based on digital attackers will enhance the overall diffusion of digital processes and services in the energy sector remains to be seen. Still, it seems to us that the digital attacker approach is a good step forward to facilitate innovation especially in the digital realm in the German utility sector.

Starting in a few months we should see that several of these digital attackers will enter the German energy market. Then, we will have to wait till the end of 2018 to see first results of this new approach to tackle digitalization. We will report on the different digital attackers here on enerquire as soon as they officially start business.

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.

Zaporozhskaya nuclear power station in Ukraine

Poland can’t continue to rely on coal, because it’s dirty, inefficient and increasingly has to be imported from Russia. But is there an alternative? Yes, there is, writes Mike Parr of consultancy PWR: Poland could import excess nuclear power from Ukraine. In fact, the interconnections for this have been in place for years. But Polish politicians have not taken action.

The need for countries to have coherent energy policies that extend beyond election cycles is uncontroversial. Sadly, many EU member states have energy policies with the directional consistency of a weather vane. The following example comes from Poland but other large member states are not much better. Think of France, which has just gone back on a promise to reduce nuclear power, or Spain, which abruptly slammed solar subsidies, or Germany, which has greenhouse gas targets it ignores in favour of the coal industry.

Poland has long been seen, by the rest of Europe as failing to taking action on CO2 emissions. One of the biggest emitters is the mostly-coal-burning power sector. (See this map for a real-time view on how bad it looks.)

Energoatom would like to complete two power units at the Khmelnitsky Nuclear Power Plant which would further increase the possibilities of electricity exports to Poland and Hungary

The Polish “love” of coal is driven by three desires, a desire for energy independence, a desire to maintain employment (coal mines) and a desire to win elections, the latter two points being firmly linked in the mind of the current PiS-run government. As in many fairy stories, the desires have no hope of being realised.

Coal subsidies

Energy independence: in 2016, Poland imported 10 million tonnes of hard coal (12% of consumption), mostly from Russia. This may well increase. Poland has viable reserves of hard coal that will last 20 years and lignite for 30 years, at current rates of consumption.

Employment in coal mines is linked to coal subsidies. Complaints by various Green parties on this issue were ignored by all parties (Hi Mr Tusk – yours as well) for years.

However, in June 2017, the Polish Supreme Audit Office produced a report showing that the coal sector had received subsidies of €15.4 billion between 2007 – 2015. This is roughly €17,000 per year per coal miner. This may seem a reasonable price to pay to win elections (Mr Tusk thought so, ditto the PiS party), quite what the non-coal-mining part of Polish society thinks is unknown.

Given the above, it is not surprising that Polish energy minister, Krzysztof Tchórzewski recently announced that Poland would build only one more large-scale coal-fired station.

Hot and cold

In the case of non-coal generation, Polish governments of all stripes have talked about nuclear and blown hot and cold about renewables (there is a creditable 6GW of wind currently operational). The installed Polish generation base is 36GW. The Polish TSO (Polish Power Grid) estimates that between 2013–2020 about 6600MW of this capacity (mostly old large fossil stations) will be retired with more retirements in the 2020 – 2030 period. Something needs to be done, fast.

The Polish TSO will have known about the link, Polish politicians then as now were under pressure to reduce emissions. And yet for more than 5 years, nothing happened

Enter the Ukraine and its nuclear power fleet. There is roughly 14GW of operational nuclear stations in Ukraine. There is significant nuclear capacity available for export, the “willing seller” being Ukraine’s nuclear operator Energoatom.

However, electricity exports are conditional on the existence of adequate cross border links and for the power stations generating and networks carrying the power aligning with ENTSO-E network codes.

It just so happens …

Falling firmly into the category of “and it just so happens” is a 2000MW un-utilised power line which, believe it or not, runs, from Khmelnitska (Ukraine) to Rzeszów (Poland).  The line (operating at 750kV) needs renovation. There is also a line which runs from Zakhidnoukrainska (Ukraine) to Albertirsa (Hungary). This is in operating condition but may need some renovation.

The good news continues: there is a project called “Energy Bridge” between Ukraine and the EU which will renovate cross border connections and align some nuclear stations and parts of Ukraine’s network with ENTSO-E codes. The pilot project aims to start the export of 1550MW of power by 2019 and has the potential to grow to 2550MW. The “willing seller”, Energoatom has a willing buyer in the Polish energy company Polenergia.

From a Ukrainian point of view, the revenues from electricity exports will be used for the worthy goals of infrastructure development both on the generation and network side. Energoatom would also like to complete two power units at the Khmelnitsky Nuclear Power Plant which would further increase the possibilities of electricity exports to Poland and Hungary.

The costs of all this “good news” falls firmly into the category of “peanuts”. Rearranging Ukraine power networks for export plus the renovation of cross border networks has a budget price of €55 million, which is “bargain basement” for 1550MW of low-carbon electricity.

This project will, by no means, solve all of Poland’s capacity problems, but it is a very good start and has scale. Which begs the question: are the leaders of PiS beating a path to ENTSO-E, Energoatom/Polenergia and the EU with the offer “how can we help to speed-up this wonderful project”?  and “are there any others like this”? (Some flying pigs have just gone past the office window).

Just in time

In 2012, PWR was asked to look at the prospect for HVDC in Europe. Our report was mostly positive. In a side note we remarked that if Ukraine had spare (nuclear) generation capacity there existed large-scale un-used cross-border links (one of which was HVDC) which could provide high-carbon countries such as Poland with low-carbon electricity, possibly at negligible cost.

The Polish TSO will have known about the link, Polish politicians then as now were under pressure to reduce emissions. And yet for more than 5 years, nothing happened.

What other relatively low-cost projects could help reduce power sector CO2 emissions in the EU? It is unlikely that the Ukraine – Poland “Energy Bridge” is the only one

“Just-in-time” works great for factories making widgets, but is hopeless as a planning approach with respect to energy infrastructure. Nevertheless, time after time, EU member states use “just in time” and “the weather vane” as their preferred policy approaches to “keeping the lights on” for EU citizens.

This example raises a final question: what other relatively low-cost projects could help reduce power sector CO2 emissions in the EU? It is unlikely that the Ukraine – Poland “Energy Bridge”, which has received relatively little publicity or recognition, is the only one.

What else is out there? It is a question Euro politicos could usefully address. They love the word “smart” with respect to the energy sector, perhaps it’s time they themselves acted that way.

Editor’s Note

Mike Parr is Director of energy consultancy PWR which undertakes research in the area of climate change and renewables for clients which include a G7 country and global corporations. See his author archive on Energy Post.

Australia can meet its 2030 greenhouse emissions target at zero net cost, according to a new analysis of a range of options for the National Electricity Market, write Andrew Blakers, Bin Lu and Matthew Stocks of Australian National University. Courtesy The Conversation.

Our modelling shows that renewable energy can help hit Australia’s emissions reduction target of 26-28% below 2005 levels by 2030 effectively for free. This is because the cost of electricity from new-build wind and solar will be cheaper than replacing old fossil fuel generators with new ones.

Currently, Australia is installing about 3 gigawatts (GW) per year of wind and solar photovoltaics (PV). This is fast enough to exceed 50% renewables in the electricity grid by 2030. It’s also fast enough to meet Australia’s entire carbon reduction target, as agreed at the 2015 Paris climate summit.

Encouragingly, the rapidly declining cost of wind and solar PV electricity means that the net cost of meeting the Paris target is roughly zero. This is because electricity from new-build wind and PV will be cheaper than from new-build coal generators; cheaper than existing gas generators; and indeed cheaper than the average wholesale price in the entire National Electricity Market, which is currently A$70-100 per megawatt-hour.

Cheapest option

Electricity from new-build wind in Australia currently costs around A$60 per MWh, while PV power costs about A$70 per MWh.

During the 2020s these prices are likely to fall still further – to below A$50 per MWh, judging by the lower-priced contracts being signed around the world, such as in Abu Dhabi, Mexico, India and Chile.

In our research, published today, we modelled the all-in cost of electricity under three different scenarios:

• Renewables: replacement of enough old coal generators by renewables to meet Australia’s Paris climate target
• Gas: premature retirement of most existing coal plant and replacement by new gas generators to meet the Paris target. Note that gas is uncompetitive at current prices, and this scenario would require a large increase in gas use, pushing up prices still further.
• Status quo: replacement of retiring coal generators with supercritical coal. Note that this scenario fails to meet the Paris target by a wide margin, despite having a similar cost to the renewables scenario described above, even though our modelling uses a low coal power station price.

The chart below shows the all-in cost of electricity in the 2020s under each of the three scenarios, and for three different gas prices: lower, higher, or the same as the current A$8 per gigajoule. As you can see, electricity would cost roughly the same under the renewables scenario as it would under the status quo, regardless of what happens to gas prices.

Balancing a renewable energy grid

The cost of renewables includes both the cost of energy and the cost of balancing the grid to maintain reliability. This balancing act involves using energy storage, stronger interstate high-voltage power lines, and the cost of renewable energy “spillage” on windy, sunny days when the energy stores are full.

The current cost of hourly balancing of the National Electricity Market (NEM) is low because the renewable energy fraction is small. It remains low (less than A$7 per MWh) until the renewable energy fraction rises above three-quarters.

The renewable energy fraction in 2020 will be about one-quarter, which leaves plenty of room for growth before balancing costs become significant.

The proposed Snowy 2.0 pumped hydro project would have a power generation capacity of 2GW and energy storage of 350GWh. This could provide half of the new storage capacity required to balance the NEM up to a renewable energy fraction of two-thirds.

The new storage needed over and above Snowy 2.0 is 2GW of power with 12GWh of storage (enough to provide six hours of demand). This could come from a mix of pumped hydro, batteries and demand management.

Stability and reliability

Most of Australia’s fossil fuel generators will reach the end of their technical lifetimes within 20 years. In our “renewables” scenario detailed above, five coal-fired power stations would be retired early, by an average of five years. In contrast, meeting the Paris targets by substituting gas for coal requires 10 coal stations to close early, by an average of 11 years.

Under the renewables scenario, the grid will still be highly reliable. That’s because it will have a diverse mix of generators: PV (26GW), wind (24GW), coal (9GW), gas (5GW), pumped hydro storage (5GW) and existing hydro and bioenergy (8GW). Many of these assets can be used in ways that help to deliver other services that are vital for grid stability, such as spinning reserve and voltage management.

Because a renewable electricity system comprises thousands of small generators spread over a million square kilometres, sudden shocks to the electricity system from generator failure, such as occur regularly with ageing large coal generators, are unlikely.

Neither does cloudy or calm weather cause shocks, because weather is predictable and a given weather system can take several days to move over the Australian continent. Strengthened interstate interconnections (part of the cost of balancing) reduce the impact of transmission failure, which was the prime cause of the 2016 South Australian blackout.

Since 2015, Australia has tripled the annual deployment rate of new wind and PV generation capacity. Continuing at this rate until 2030 will let us meet our entire Paris carbon target in the electricity sector, all while replacing retiring coal generators, maintaining high grid stability, and stabilising electricity prices.

Editor’s Note

Andrew Blakers is Professor of Engineering, Bin Lu is Ph.D. candidate and Matthew Stocks is Research Fellow, all at Australian National University.

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

Rampion wind farm seen from Brighton photo John HikerBiker

Just six years ago, more than 40% of Britain’s electricity was generated by burning coal. Today, that figure is just 7%. Yet if the story of 2016 was the dramatic demise of coal and its replacement by natural gas, then 2017 was most definitely about the growth of wind power, write Grant Wilson and Iain Staffell. Courtesy The Conversation.

Wind provided 15% of electricity in Britain last year (Northern Ireland shares an electricity system with the Republic and is calculated separately), up from 10% in 2016. This increase, a result of both more wind farms coming online and a windier year, helped further reduce coal use and also put a stop to the rise in natural gas generation.

Great Britain’s annual electrical energy mix 2017. Author calculations from data sources: National Grid and Elexon

In October 2017, the combination of wind, solar and hydro generated a quarter of Britain’s electricity over the entire month, a new record helped by ex-hurricane Ophelia and storm Brian.

Great Britain’s annual electrical energy mix 2017 per month (note: nuclear and gas not shown) Author calculations from data sources: National Grid and Elexon

Since that record month, large new offshore wind farms have started to come online. Dudgeon began generating off the Norfolk coast, as did Rampion, which can be seen from Brighton town centre.

In all, Britain’s wind output increased by 14 terawatt hours between 2016 and 2017 – enough to power 4.5m homes. To give a sense of scale, this increase alone is more than the expected annual output from one of the two new nuclear reactors being built at Hinkley Point C.

If there is to be a nuclear renaissance, or if fossil fuels with carbon capture and storage are to become a reality, these industries will have to adjust to the new economic reality of renewable energy

Not only is offshore wind growing fast, it is also getting much cheaper. When the latest round of government auctions for low-carbon electricitywere awarded last year, two of the winning bids from offshore wind developers had a “strike price” of £57.50 per megawatt hour (MWh). This is considerably cheaper than the equivalent contract for Hinkley Point of £92.50/MWh (in 2012 prices).

Although these wind farms won’t be built for another five years, this puts competitive pressure on other forms of low-carbon electricity. If there is to be a nuclear renaissance, or if fossil fuels with carbon capture and storage are to become a reality, these industries will have to adjust to the new economic reality of renewable energy.

Britain is using less electricity

Overall demand for electricity also continued its 12-year downward trend. More of the electricity “embedded” in the products and servicesused in the UK is now imported rather than produced at home, and energy efficiency measures mean the country can do more with less. This meant Britain in 2017 used about as much electricity as it did way back in 1987 – despite the considerable population growth.

At some point this trend will reverse though, as electric vehicles and heat pumps become more common and electricity partly replaces liquid fuels for transport and natural gas for heating respectively. One major challenge this brings is how to accommodate greater seasonal and daily variation in the electricity system, without resorting to the benefits of fossil fuels, which can be pretty cheaply stored until required.

Electricity generated in Britain is now the cleanest it’s ever been. Coal and natural gas together produced less than half of the total generated. Britain’s electricity was completely “coal free” for 613 hours last year, up from 200 hours in 2016. This position would be wholly unthinkable in many countries including Germany, India, China and the US, which still rely heavily on coal generation throughout the year.

Great Britain’s annual electrical energy mix – fossil fuels drop below 50% for first time. Author calculations from data sources: National Grid and Elexon

However, the low level of coal generation over 2017 masks its continued importance in providing capacity during hours of peak demand. During the top 10% hours of highest electrical demand, coal provided a sixth of Britain’s electricity. When it matters most, coal is relied on more than nuclear, and more than the combined output from wind + solar + hydro. Additional energy storage could help wind and solar meet more of this peak demand with greater certainty.

The low level of coal generation over 2017 masks its continued importance in providing capacity during hours of peak demand

Looking forward to 2018, we would be surprised if wind generation dropped much from its current levels. Last year wasn’t even particularly windy compared to the longer-term average, and more capacity will be coming online. Equally, it would be surprising if solar and hydro combined produced significantly less than they did last year.

It is therefore inevitable that another significant milestone will be reached this year. At some point, for several hours, wind, solar and hydro will together, for the first time, provide more than half of Britain’s electricity generation. This goes to show just how much a major power system can be reworked within a decade.

Authors’ Note

The data used in this article is based on the Energy Charts and Electric Insightswebsites, which allow readers to visualise and explore data on generation and consumption from Elexon and National Grid. Data from other analyses (such as BEIS or DUKES) will differ due to their methodology, particularly by including combined heat and power, and other on-site generation which is not monitored by National Grid and Elexon. Our estimated carbon emissions are based on Iain Staffell’s research published in Energy Policy, and account for foreign emissions due to electricity imports and biomass fuel processing. 

Editor’s Note

Grant Wilson (@DrIAGWilson) is Teaching and Research Fellow, Chemical and Biological Engineering at the University of Sheffield.

Iain Staffell is Lecturer in Sustainable Energy at Imperial College London.

This article was first published on The Conversation and is republished here with permission from the authors and under a Creative Commons licence of the publisher.

Leaders at Belt and Road forum, May 2017

China’s Belt and Road Initiative, the broad infrastructure and market-building initiative of the world’s second-largest economy, has a different feel than trade agreements initiated in the West – and it could have major implications for the future of energy across many parts of the world, writes Sonia Aggarwal, Vice President of think tank Energy Innovation, and Director of America’s Power Plan.

That’s partly because unimpeded trade and financial integration are just two of five pillars of China’s ambitious plan for international collaboration.  The other pillars are policy coordination, infrastructure connectivity, and people-to-people bonds.  And in this program, the Chinese central government has issued guidance on promoting “Green Belt and Road,” to highlight how to incorporate the principles of resource efficiency and environmental awareness into the whole program, touting the need to “develop global energy interconnection and achieve green and low-carbon development.”

The question is: Are the environmental protections real?

China will have a substantial impact beyond its own borders as it decides how to allocate the $900 billion in foreign infrastructure spending President Xi suggested would be available for the program

The Belt and Road Initiative is intended to span 68 countries on four continents, reaching more than 60% of the world’s total population, one-third of global GDP, and a quarter of all goods the world moves.

At a forum held last May in China for nations involved in the Belt and Road Initiative, heads of state of countries representing more than 40% of global emissions showed up, making clear just how important the Belt and Road program is. China will have a substantial impact beyond its own borders as it decides how to allocate the $900 billion in foreign infrastructure spending President Xi suggested would be available for the program.

The Silk Road Economic Belt and the 21st Century Maritime Silk Road, collectively known as the Belt and Road initiative. (via Xinhua)

China’s Belt and Road initiative will Influence global carbon trajectory

Global energy demand is expected to rise 30% between 2017 and 2040, but Southeast Asia, one of the focus regions in the Belt and Road effort, is looking at growth in energy demand of nearly 70% over the next 25 years.  This growth will require an enormous investment in new infrastructure, and while domestic policies in Southeast Asian nations will be paramount, Belt and Road will undoubtedly influence whether new power plants in Southeast Asia and other high-growth regions are coal or clean.

Outside its own borders today, China is involved in more than a hundred coal-fired power plant projects in active planning or construction phases.  Coal plant planning and construction timelines are long, and Western countries were supporting coal projects in many of these countries well before Chinese involvement, so at least some of the large number of coal plants in the pipeline can be explained by inertia in the system.

Belt and Road related coal projects declined last year, but the data does not show a clear trend.  The coal slow-down could be sustained even if China’s infrastructure investments continue apace, as the result of many factors, not the least of which is the fact renewables have been beating coal on cost alone, but also a strengthening connection between the green promises and the actions of the Belt and Road Initiative.

Forecast change in primary energy demand from 2016 to 2040. © OECD/IEA 2017 World Energy Outlook, IEA Publishing

Last year as coal investment slowed, China also issued nearly $25 billion worth of green bonds for infrastructure investments (in the context of $188.8 billion in outward foreign direct investment).  The proceeds of those bonds are being used for clean energy, clean transport, resource conservation and recycling, pollution prevention and control, and energy efficiency, in approximately equal shares (17-21% each).  A smaller share (8%) of proceeds are going to ecological protection and climate change adaptation.

Regional grid could provide energy to China’s neighbors

China intends to spend more than $360 billion through 2020 on domestic solar and wind power, but given the current policy and market framework in China, energy from these new resources is often crowded out on the grid by coal-fired generation, despite being less expensive on a marginal cost basis.

Due to domestic policy and market advancements, the Chinese grid is already getting better at maximizing energy from renewable resources, but this could be further helped by building out transmission lines within China as well as better integrating with neighboring regions.

And if excess power generation persists on China’s grid, it could be exported to neighboring regions to meet growing energy demand.  Certainly, using the Belt and Road-related overseas investments to build clean power plants rather than coal would help solidify China’s leadership in the global energy industry of the future.

Just as the U.S. looks to be forfeiting its seat at the negotiating table for international trade deals, China is stepping into the lead, going beyond the old-fashioned trade agreement to emphasize infrastructure and better energy connectivity over much of the globe

“China has become the principal market for renewable energy worldwide,” said International Renewable Energy Agency Director-General Adnan Amin during the recent Belt and Road Forum for International Cooperation. “The [Belt and Road] Initiative can not only help to interconnect electricity grids and deploy more renewable energy, but it can also expand electricity markets to countries with extremely high renewable energy potential, including those in Central Asia. China has the technology and the resources, and it can help to achieve these goals by building partnerships and cooperation.”

These recent developments are promising—though by no means dispositive—for the green future of the Belt and Road Initiative.  Just as the United States looks to be forfeiting its seat at the negotiating table for international trade deals, China is stepping into the lead, going beyond the old-fashioned trade agreement to emphasize infrastructure and better energy connectivity over much of the globe.

If China’s Belt and Road Initiative is truly green, it will have a global benefit.  Watch this space.

Editor’s Note

Sonia Aggarwal is Vice President of Energy Innovation, and Director of America’s Power Plan. This article was first published on Forbes.com and is republished here with permission.

For more information on this topic see also this article by Lili Pike on ChinaDialogue.

China’s spectacular expansion of its solar power capacity is mostly based on utility-scale solar, but distributed solar is also taking off, write Max Dupuy and Wang Xuan, two China experts from the globally operating Regulatory Assistance Project (RAP). According to Dupuy and Xuan, this trend may be expected to continue, as the Chinese government is creating new business and regulatory models to stimulate distributed solar PV and other decentralised sources. They explain how the new measures are likely to shake up the Chinese renewable energy market.

Investment in solar photovoltaic (PV) generation is surging in China, and, although utility-scale solar continues to dominate, distributed solar is also growing rapidly. The country is estimated to have added 54 GW of solar in 2017, and distributed solar accounts for about one-third of that capacity.

Now, policymakers appear to be emphasizing continued growth in distributed solar. Recently, the National Development and Reform Commission (NDRC) and National Energy Administration (NEA) kicked off an effort to create new business models for distributed solar PV and other distributed resources. These new business models are geared toward new investments in solar PV on local distribution networks, financed and implemented by third parties or, in some cases, new, privately owned distribution companies.

After a history of being largely free from direct regulatory oversight of finances, all grid companies—state-owned and private—will be subject to a form of what in other countries is called revenue regulation

This comes against the backdrop of China’s power sector reform, now nearly three years old, which has included a gradual effort to unbundle retail and distribution business from the large grid companies to varying degrees across provinces. In some provinces, retailers now compete for customers. Meanwhile, new distribution companies—open, for the first time, to private investors—have been established in certain parts of the country (so far, mostly in a limited number of industrial parks).

After a history of being largely free from direct regulatory oversight of finances, all grid companies—state-owned and private—will be subject to a form of what in other countries is called revenue regulation. That is, allowed revenue will be determined for a multi-year period based on allowed expenses and allowed return on approved assets.

Meanwhile, at the wholesale level, reform has included significant and ongoing expansion of the direct trading policy, under which an increasing number of thermal generators are no longer allocated guaranteed annual operating hours at an administered price, but instead must compete to sign annual or monthly contracts with end users or retailers.

A broad outline for “marketization” of distributed generation

On October 31, the two government agencies jointly announced a new initiative for Market-oriented Distributed Power Generation. The document calls for the creation of platforms that will facilitate electricity trading between distributed generation projects and end users across a local electricity distribution network, starting with large-scale pilots in yet-to-be decided locations.

The new document gives an overview of the new thinking, with many details left to be decided. The basic features are described below.

The document allows for very large projects that would, in other countries, be considered “utility scale.” More specifically, the document permits projects of up to 50 MW on 110 kV lines and up to 20 MW on 35 kV lines. For comparison, recent examples of solar PV arrays on “big box” retail stores, which are increasingly seen in parts of the United States, are in the neighborhood of 1 MW.

Distributed generators will be responsible for paying a so-called grid fee, which will only reflect distribution network costs, not transmission network costs

Meanwhile, 110 kV lines would typically be considered part of the transmission network. In China’s pilots, any relatively large (above 10 MW) distributed projects might be sited on converted agricultural land bordering industrial sites or cities, or situated on unoccupied land within industrial parks—and so perhaps can be thought of as a kind of “community” distributed model, but sized to fit China’s large industrial parks.

The pilots are clearly intended to support smaller-sized distributed resources as well.

• Under what the document calls the “first market trading model,” distributed generators will be able to sign contracts, on a competitive basis, with eligible end users within the scope of a local distribution network. It appears that these contracts may be monthly or annual in length. Eligibility will, at least at first, be limited to large industrial or commercial customers.
• As an alternative “second model of market trading,” the distribution grid companies may negotiate to purchase energy from distributed generators and contract to sell the energy to large end users.
• The document also mentions a “third model,” under which distributed generators sell energy to the distribution company at an on-grid price set by administrators. This third model is more or less the status quo for “community,” or not-behind-the-meter, distributed generators in China.

Under each model, distributed solar and wind generators would continue to receive per-kWh subsidies from the National Renewable Energy Development Fund (National Fund), although these would be reduced from current levels by 10 to 20 percent.

Distributed generators will be responsible for paying a so-called grid fee, which will only reflect distribution network costs, not transmission network costs. (This calculation of a separate distribution fee is a matter of contention, in part because regulators are still grappling with assessing and approving these costs under the new regulatory regime for grid company revenues.)

The document also mentions that distributed generation owners will be “encouraged to install storage to increase flexibility and reliability,” but provides no further detail on this topic.

Will the new approach stimulate growth of distributed energy?

Industry observers in China are welcoming this new initiative, and expect it will bring new opportunities for distributed generation investments to serve industrial and commercial customers. It appears that there may be an eager flock of third-party operators who are confident that they can organize financing and siting of the type of distributed solar PV projects envisaged in the new document.

These distributed solar PV generators are expected to be able to compete against large thermal generators, given that the solar PV generators 1) will only pay the distribution network grid fee, which will be considerably smaller than the overall transmission and distribution fee, and 2) will still collect the solar subsidy from the National Fund. One area of concern, however, may be slow (or incomplete) payouts from the depleted National Fund, which has been an issue affecting utility-scale renewable energy investments in recent years.

Newly minted (or prospective) private distribution network owners—although more limited in number—also appear to be interested in investing in distributed generation

The competitive first market trading model may attract particularly lively participation—and strong new investment in distributed generation—in parts of the country where industrial customers have not been allowed to contract directly with large generators and where administratively-set industrial electricity prices remain high.

In contrast, in places where end users are able to directly contract with large generators, prices are already quite low because of widespread generation overcapacity—although the distributed generators may still have a good business case if the relevant grid fee is sufficiently favorable and the subsidies are paid out reliably.

In addition, newly minted (or prospective) private distribution network owners—although more limited in number—also appear to be interested in investing in distributed generation. This is, in part, underpinned by the new revenue regulation regime. Expansion of distributed resources potentially reduces the growth of kWh sold by (or flowing through) a given distribution network.

To the extent that the distribution company’s revenue is based on these kWh sales, then the distribution company may be disinclined to support new distributed resources. However, the new revenue regulation regime (which, in China, is more commonly known as “transmission and distribution price reform”) should break this link between kWh sales and revenue, at least for the regulatory period (typically three years). One wrinkle is that this new revenue regulation regime is still being rolled out across the country, and it may be some time before it is evenly and adequately implemented.

Looking forward

As these pilots come online, there will be opportunities to refine and develop the new approach to distributed resources. Topics for consideration will include:

• How should policymakers refine compensation for distributed resources to promote the right resources in the right locations?
• How should this new policy be integrated with transmission and distribution network planning?
• Should more differentiated approaches be designed to address the wide scope of project sizes envisaged in the new document?
• How should the new distribution markets be coordinated with the wholesale markets under development in China?
• What is the best way to support the financial viability of the National Fund from which subsidies are paid?

Policymakers in other parts of the world are also struggling to design methods and mechanisms to rationally support distributed generation, and there will be much to be gained from ongoing international discussions on these issues. 

Editor’s Note

The Regulatory Assistance Project (RAP) is a globally operating independent and nonpartisan team of experts dedicated to accelerating the transition to a clean, reliable and efficient energy future.

This article was first published on the blog of RAP and is republished here with permission.

Max Dupuy is a Senior Associate at RAP. Wang Xuan is a Consultant at RAP’s China Team.

Network tariffs are an important part of energy costs for consumers, yet, surprisingly, the way these fees are established in Germany is completely opaque, writes Andreas Jahn, Berlin-based Senior Associate at global energy policy advisors Regulatory Assistance Project (RAP). According to Jahn, it is unclear how network operators and the regulator calculate costs and how they are allocated to customers. He calls on the German government—and on the EU— to demand more transparency on network tariffs.

“Putting consumers at the heart of the energy market” is how the European Commission, the European Council, and the European Parliament characterize the reform of the European energy market. The pan-European electricity market is already saving consumers billions in costs by connecting national markets.

Yet these savings could still be increased substantially. An important part of consumers’ energy costs are the network costs, which have been growing steadily in recent years across the EU. Since they are regulated, they are not subject to competition. Consumers have no choice in the matter. What you would expect, then, is that they would be established in a transparent manner, so consumers and taxpayers are able to see how they are calculated and allocated.

Neither customers nor retailers are provided with reliable information about the costs of the various networks or the total grid costs for Germany

In Germany, however, this is not the case at all.

Every year in October, all four German transmission system operators and almost 900 distribution network operators publish price sheets that show the network fees for the upcoming year. Based on these published prices, consumers can calculate whether their network charges will change, and the energy retailers can start calculating tariffs for their customers.

However, beyond these bare prices, there is very little information available. Neither customers nor retailers are provided with reliable information about the costs of the various networks or the total grid costs for Germany. Not even the regulator has access to this aggregate number. And this is despite the fact that Germany has had a revenue regulation system in place since 2005, which has been revised twice and reinforced with a performance regulation mechanism.

Asking questions

Curious about this lack of transparency, RAP collected data from various sources and started asking questions. In cooperation with Agora Energiewende, we published a paper (in German) exploring the results and shedding light on this often-overlooked issue.

We found that in 2018, the costs for the transmission system will increase by more than €600 million to a total of approximately €5.8 billion. That is only for transmission; distribution costs raise the total to some €24 billion, but this is only a rough estimate.

There are several justifiable reasons for this increase, such as the need to contract reserves and higher redispatch costs to operate the network in the absence of locational marginal pricing. However, we are at a loss as to exactly where these costs are incurred or how they are allocated to networks and, ultimately, to customers. It is unclear why some customer groups face higher network charges than others.

For example, the increase in network costs from German transmission system operator amprion is only borne by the customers connected to the low-voltage distribution networks, not by the industrial customers who are connected at the transmission level.

It is unclear why some customer groups face higher network charges than others

Nor is the public ever informed about how the regulator has assessed cost increases (tariffs are based on a cost-plus system). This ongoing gap in transparency has led to what can be described as “regulatory capture” of the regulator by the network operators.

A study commissioned by the German regulator comparing the regulatory procedures for establishing network regulation and network fees in the United Kingdom, the United States, the Netherlands, Austria, and Italy found that nearly all of the countries (except Italy) demonstrated a more transparent process than Germany. The monitoring report that the regulator (the Bundesnetzagentur) published about its own activities, addresses the international comparison of transparency only marginally—on one single page out of 500. The Bundesnetzagentur regards revenue regulation as a confidential issue relevant to “network competition.”

Long-term benefits

Unfortunately, the German Supreme Court ruled in the fall of 2017, as the result of a court case brought by “green” energy retailer LichtBlick, that the policy to keep control of grid revenues out of the public domain is in line with national law.

This means that lawmakers will  have to take action to enforce more transparency.

If the Energy Union is to successfully offer consumers the benefits of a common market, the first step must be cost transparency for all Europeans. The data and decisions must be disclosed by all parties involved. This requires implementing strong regulations and empowering institutions at the European level, such as the Agency for the Cooperation of Energy Regulators (ACER), to implement transparent network tariffs or even demand them from Member States.

Achieving transparency is not an impossible task. Germany has already improved clarity around other energy-related fields in recent years. More than 1.6 million solar photovoltaic installations financed by support schemes are listed on a public webpage, and regulators introduced a platform to strengthen transparency on the wholesale electricity market. Progress has been made in regulation, by leveraging cartel law to increase transparency without impeding the market or its actors.

In the absence of publicly available data, it is impossible to determine the extent to which increases in network tariffs are actually justified

As for the degree of transparency required, decision-makers must conduct stakeholder processes that identify the interests of the parties and make decisions based on the regulatory framework of the pan-European and national power markets. Only then can market reforms deliver their full value.

Increases in the price of electricity are mostly attributed to increases in regulated charges, which cannot be influenced by market processes. Yet in the absence of publicly available data, it is impossible to determine the extent to which these increases are actually justified. Even if we know the underlying grid costs, we cannot determine whether the costs are being shared between different consumer groups in an equitable manner.

This lack of transparency undermines public confidence in the energy transition. Now that the German Supreme Court has reinforced the confidentiality of regulated network data and decisions, it’s up to the German federal government to catch up with European transparency standards for network regulation. This would not only demonstrate respect for the longstanding public support for the German Energiewende, but would also secure long-term benefits for all European customers in shared markets.

Editor’s Note

The Regulatory Assistance Project (RAP) is a globally operating independent and nonpartisan team of experts dedicated to accelerating the transition to a clean, reliable and efficient energy future.

As a senior associate in Berlin, Andreas Jahn (@Andr_Jahn) focuses on issues relating to the German “Energiewende”, or energy transition, helping develop and advance regulatory options for a carbon-neutral power sector, including demand-side resources and tariff design. He also supports RAP’s work throughout Europe. He has extensive experience with power markets and regulation, as well as knowledge of the German national political arena.

Bitcoin mining facility in Ordos Inner Mongolia (photo Bloomberg)

There is widespread concern over the high energy use of Bitcoin mining. But blockchains can be highly energy-efficient, writes Sam Hartnett of the Energy Web Foundation, a joint initiative of Rocky Mountain Institute and Grid Singularity who have partnered with Shell, Statoil, Engie, and other energy companies to accelerate adoption of blockchain technology in the energy sector. According to Hartnett,  blockchain technology will help accelerate grid decarbonization – not exacerbate current challenges.

Digital cryptocurrency Bitcoin experienced a dramatic rise in popularity and value in 2017. Deployment of blockchain technology, which underpins Bitcoin and numerous other digital currencies, is poised for similar growth across multiple sectors.

However, the environmental impacts of Bitcoin—especially its high energy consumption—have come under scrutiny as the network’s use has increased. There is widespread concern that continued growth of blockchain-based currencies like Bitcoin will undermine global efforts to reduce carbon emissions and threaten grid stability.

This is unfortunate, because there is every reason to believe that blockchain technology could actually accelerate—not hinder—environmental and energy goals.

Blockchains of course are not limited to digital currencies. Nor are all blockchains created equal. There are many ways to design, govern, and operate a network; these decisions influence energy intensity. At Energy Web Foundation (EWF), we’re building an energy-efficient blockchain to support applications that unlock new opportunities for renewable energy and distributed energy resources. In other words, we’re developing an energy-lean blockchain specifically for the energy industry that can also accelerate grid decarbonization. 

With Bitcoin’s growing popularity comes with growing energy use

Bitcoin mining—the process by which computers in the Bitcoin network validate transactions, create new Bitcoins, and earn a reward payment – is a computational burden that requires high-powered, and increasingly specialized hardware. Bitcoin’s fast-growing energy use is a byproduct of how the network validates and adds blocks to the chain.

Estimates of Bitcoin’s total electricity consumption vary between roughly 1 TWh and 44 TWh per year, depending on methodology; the former is enough to power roughly 90,000 U.S. homes for a year, the latter is larger than the annual electricity use of Denmark. Today a single Bitcoin transaction consumes as much electricity as an average American home does each week. And that’s just Bitcoin.

A blockchain (such as the Bitcoin network) keeps track of transactions between parties; details of each transaction are added to the distributed ledger (i.e., the “chain” of blockchain) in encrypted blocks of data. For each block of transactions, a massive global network of computers race to solve an encrypted, complex equation that can only be solved through trial-and-error. The “winner” (i.e., the computer that solves the problem first and is subsequently confirmed correct by the network) earns a Bitcoin reward, hence the “mining.” The more computing power you have, the more likely you are to win bitcoins by solving the equations.

As Bitcoin’s value increases, there is greater incentive for miners to add computing resources in order to beat their competition. By design, the greater the total computing power of the network, the more difficult the equation becomes. The result is a reinforcing feedback loop with the potential for runaway energy consumption. 

Not all networks are created equal

Bitcoin’s consensus protocol—the mechanism by which the computers in the network validate and agree upon transactions—is called “proof-of-work” (PoW). It is so named because miners work hard (i.e., devote real-world resources like computers and energy) to solve an equation and prove it to the rest of the network. Though inherently energy-intensive, PoW sets an extremely high bar for validating blocks and makes it exceedingly difficult to manipulate the blockchain.

Yet PoW is only one way to validate transactions, and at least two alternatives hold promise for blockchain applications with a lighter energy footprint:

• Proof-of-Stake (PoS): Under a PoS system, there are no races for validating blocks; there are no miners. Instead, network participants own a share of the system’s digital currency and are selected to validate blocks in proportion to their share. This proportional stake—and the risk of losing this “deposit”—disincentivizes malicious actors. Since there isn’t computing competition among all participants to solve an encryption problem (as in a PoW network) PoS blockchains use a fraction of the energy.

• Proof-of-Authority (PoA): PoA systems rely on a trusted set of authorities to create and validate blocks. PoA blockchains could be private or public but in either case there is a reduced number of validators (albeit optimal in number and diversity to ensure decentralized system democracy), with reduced computational power required and reduced opportunities for system attacks. Authorities are compensated for their block-validation role through standard, nominal transaction fees not tied to the nature or value of the transactions themselves. To ensure good governance, there are rules that regulate how authorities join the network and how transactions are validated, and these rules are currently in development since PoA only became available this year starting with the Kovan testnet. Such PoA networks are well-suited to regulated industries where entities responsible for maintaining the network (authorities) need to be known, rather than remain anonymous as in mining-based chains like Bitcoin and Ethereum. And since only approved authorities are the ones validating the blockchain, there is no competition amongst authorities to race each other, which means less power consumption than PoW blockchains.

Energy Web Foundation – A new blockchain for the energy sector

EWF is building a public, open-source blockchain-based platform designed to host decentralized applications that support distributed and renewable energy-focused business models and products. Meeting this objective requires a highly scalable network with a robust governance structure that doesn’t require massive computational, hence energy resources.

EWF is currently designing a PoA consensus mechanism for its network, with EWF affiliates—energy companies who have partnered with EWF—serving as authorities. This validating system addresses both the technical and regulatory challenges associated with implementing a blockchain in the energy sector. The PoA consensus mechanism allows EWF’s network to maintain a light energy footprint. Authority nodes can run on simple hardware and initial data indicates that typical demand for an authority node is approximately 78 watts – on par with a common incandescent lightbulb. With 20 authority nodes currently on the EWF network, the upper boundary total energy demand is approximately 1.5 kW – roughly equivalent to a microwave.

Since energy use will increase linearly as the EWF network grows, with 1,000 authority nodes expected energy demand will be less than 80 kW – enough to power about 10 US homes. The actual number is likely to be even lower, since improvements in hardware efficiency or the use of shared servers will reduce the energy burden of a given authority node.

In addition to limiting energy consumption, the PoA consensus mechanism will improve performance and buttress security, addressing potential regulatory concerns (e.g., regulators will know who the actual authorities are and will be consulted when designing relevant protocols and applications). The network will enable applications ranging from a more effective facilitation of certificates of origin for renewables to improved grid access and management.

The reader might wonder, doesn’t this put the energy companies that function as authorities in a privileged position? There are several reasons why this is not the case. First, the authorities include major energy companies as well as startups – all have a vested interest in the success of the network and are thus incentivized to maintain its integrity. Secondly, eventually we aim to have 1000 or more authorities that are geographically and organizationally diverse.

In addition, EWF is also implementing a governance system that will not only disincentivize malicious behaviour but will also include protocols for removing authorities that misbehave. We encourage all affiliates, as well as the public at large, to utilize the EWF chain to support new applications and businesses.

Efficient by design

It is difficult to predict how Bitcoin and other digital currency mining will impact energy usage. If Bitcoin’s price continues to soar and more miners join the pool, some of the more dire warnings could come true. Conversely, an act of regulation, an innovative competitor, new computing technologies, or some other event could make Bitcoin mining more efficient, less appealing, or obsolete.

But no matter what happens in the broader blockchain space, the nature of the EWF network ensures that it will be less energy intensive, faster, and even more secure even as it grows. EWF’s blockchain will unlock new opportunities in the energy transition, not exacerbate current problems.

Editor’s Note

Sam Hartnett is an associate at Rocky Mountain Institute and member of the Energy Web Foundation team, where he works with major energy companies to develop blockchain applications for demand response, electric vehicles, and peer-to-peer markets.

This article was first published on the website of Energy Web Foundation and is republished here, in a slightly edited form, with permission.

Chapelcross nuclear power plant in Scotland was decommissioned in 2007.

Nuclear power is in crisis ‒ as even the most strident nuclear enthusiasts acknowledge ‒ and it is likely that a new era is fast emerging, writes Jim Green, editor of the Nuclear Monitor newsletter. After a growth spurt from the 1960s to the ’90s, then 20 years of stagnation, the Era of Nuclear Decommissioning is upon us. Article courtesy Nuclear Monitor.

Last year was supposed to be a good year for nuclear power ‒ the peak of a mini-renaissance resulting from a large number of reactor construction starts in the three years before the Fukushima disaster. The World Nuclear Association (WNA) anticipated 19 reactor grid connections (start-ups) in 2017 but in fact there were only four start-ups (Chasnupp-4 in Pakistan; Fuqing-4, Yangjiang-4 and Tianwan-3 in China).

The four start-ups were outnumbered by five permanent shut-downs (Kori-1 in South Korea; Oskashamn-1 in Sweden; Gundremmingen-B in Germany; Ohi 1 and 2 in Japan).

The WNA’s estimate for reactor start-ups in 2017 was hopelessly wrong but, for what it’s worth, here are the Association’s projections for start-ups in the coming years:

2018‒19: 30
2020‒21: 12
2022‒23: 9
2024‒25: 2

Thus ‒ notwithstanding the low number of start-ups in 2017 ‒ the mini-renaissance that gathered steam in the three years before the Fukushima disaster probably has two or three years to run. Beyond that, it’s near-impossible to see start-ups outpacing closures.

New nuclear capacity of 3.3 gigawatts (GW) in 2017 was outweighed by lost capacity of 4.6 GW. Over the past 20 years, there has been modest growth (12.6%, 44 GW) in global nuclear power capacity if reactors currently in long-term outage are included. However, including those reactors ‒ in particular idle reactors in Japan, many of which will never restart ‒ in the count of ‘operable’ or ‘operational’ or ‘operating’ reactors is, as former WNA executive Steve Kidd states, “misleading” and “clearly ridiculous”.

There would need to be an average of 10 reactor start-ups (10 GW) per year just to maintain current capacity. The industry will have to run hard just to stand still

The World Nuclear Industry Status Report (WNISR) excludes reactors in long-term outage ‒ defined as reactors that produced zero power in the previous calendar year and in the first half of the current calendar year ‒ from its count of operating reactors. Thirty-six reactors are currently in long-term outage, 31 of them in Japan.

Excluding reactors in long-term outage, the number of reactors has declined by 29 over the past 20 years, while capacity has grown by a negligible 1.4% (5 GW). Over the past decade, the reactor count is down by 34 and capacity is down by 9.5% (19 GW).

The industry faces severe problems, not least the ageing of the global reactor fleet. The average age of the reactor fleet continues to rise, and by mid-2017 stood at 29.3 years; over half have operated for 31 years or more.

The International Energy Agency expects a “wave of retirements of ageing nuclear reactors” and an “unprecedented rate of decommissioning” ‒ almost 200 reactor shut-downs between 2014 and 2040. The International Atomic Energy Agency anticipates 320 GW of retirements by 2050 ‒ in other words, there would need to be an average of 10 reactor start-ups (10 GW) per year just to maintain current capacity. The industry will have to run hard just to stand still.

Renewables (24.5% of global generation) generate more than twice as much electricity as nuclear power (<10.5%) and the gap is growing rapidly

Assuming the mini-renaissance doesn’t continue to flop (as it did in 2017), an average of 10 or so start-ups from 2015‒2020 is possible (there were 24 start-ups from 2015‒17). But to maintain that level, the number of construction starts would need to increase sharply and there is no likelihood of that eventuating ‒ there have only been seven construction starts in the past two years combined.

The number of reactors under construction is slowly dropping. Using WNA figures, 71 reactors were under construction in January 2014 compared to 58 in January 2018. According to WNISR figures, the number is down from 67 to 52 over the same period. That trend seems certain to continue because of a sharp drop in reactor construction starts: 38 from 2008‒2010 compared to 39 in the seven years from 2011‒2017.

Nuclear power accounted for 10.5% of global electricity generation in 2016 (presumably a little less now), well down from the historic peak of 17.5% in 1996.

Renewables (24.5% of global generation) generate more than twice as much electricity as nuclear power (<10.5%) and the gap is growing rapidly. The International Energy Agency  predicts renewable energy capacity growth of 43% (920 GW) from 2017 to 2022. Overall, the share of renewables in power generation will reach 30% in 2022 according to the IEA. By then, nuclear’s share will be around 10% and renewables will be out-generating nuclear by a factor of three.

A disastrous year for the nuclear industry

Last year was “all in all a disastrous year” for the nuclear power industry according to Energy Post Weekly editor Karel Beckman. Nuclear lobbyists issued any number of warnings about nuclear power’s “rapidly accelerating crisis“, a “crisis that threatens the death of nuclear energy in the West“, “the crisis that the nuclear industry is presently facing in developed countries“, the “ashes of today’s dying industry”, and noting that “the industry is on life support in the United States and other developed economies“.

Lobbyists engaged each other in heated arguments over possible solutions to nuclear power’s crisis ‒ in a nutshell, some favour industry consolidation while others think innovation is essential, all of them think that taxpayer subsidies need to be massively increased, and none of them are interested in the tedious work of building public support by strengthening nuclear safety and regulatory standards, strengthening the safeguards system, etc.

One indication of the industry’s desperation has been the recent willingness of industry bodies (such as the US Nuclear Energy Institute) and supporters (such as former US energy secretary Ernest Moniz) to openly acknowledge the connections between nuclear power and weapons, and using those connections as an argument for increased taxpayer subsidies for nuclear power and the broader ‘civil’ nuclear fuel cycle. The power/weapons connections are also evident with Saudi Arabia’s plan to introduce nuclear power and the regime’s pursuit of a weapons capability.

There were no commercial reactor construction starts in China in 2017 (though work began on one demonstration fast neutron reactor) and only two in 2016

The biggest disaster for the nuclear industry in 2017 was the bankruptcy filing of Westinghouse ‒ which also came close to bankrupting its parent company Toshiba ‒ and the decision to abandon two partially-built reactors in South Carolina after the expenditure of at least US$9 billion. As of January 2018, both Westinghouse and Toshiba are still undergoing slow and painful restructuring processes, and both companies are firmly committed to exiting the reactor construction business (but not the nuclear industry altogether).

Another alarming development for the nuclear industry was the slow-down in China. China Nuclear Engineering Corp, the country’s leading nuclear construction firm, noted in early 2017 that the “Chinese nuclear industry has stepped into a declining cycle” because the “State Council approved very few new-build projects in the past years”.

There were no commercial reactor construction starts in China in 2017 (though work began on one demonstration fast neutron reactor) and only two in 2016. The pace will pick up but it seems less and less likely that growth in China will make up for the decline in the rest of the world.

The Era of Nuclear Decommissioning will be characterised by escalating battles (and escalating sticker shock) over lifespan extensions, decommissioning and nuclear waste management

The legislated plan to reduce France’s reliance on nuclear from 75% of electricity generation to 50% by 2025 seems unlikely to be realised but the government is resolved to steadily reduce reliance on nuclear in favour of renewables. French environment minister Nicolas Hulot said in November 2017 that the 50% figure will be reached between 2030 and 2035. France’s nuclear industry is in its “worst situation ever”, a former EDF director said in November 2016, and the situation has worsened since then.

There were plenty of other serious problems for nuclear power around the world in 2017:

• Swiss voters supported a nuclear phase-out referendum.
• South Korea’s new government will halt plans to build new nuclear power plants (though construction of two partially-built reactors will proceed, and South Korea will still bid for reactor projects overseas).
• Taiwan’s Cabinet reiterated the government’s resolve to phase out nuclear power by 2025 though a long battle
• Japan’s nuclear industry has been decimated ‒ just five reactors are operating (less than one-tenth of the pre-Fukushima fleet) and 14 reactors have been permanently shut-down since the Fukushima disaster (including the six Fukushima Daiichi reactors).
• India’s nuclear industry keeps promising the world and delivering very little ‒ nuclear capacity is just 6.2 GW. In May 2017, India’s Cabinet approved a plan to build 10 indigenous pressurised heavy water reactors, but most have been in the pipeline for years and it’s anyone’s guess how many (if any) will actually be built.
• The UK’s nuclear power program faces “something of a crisis” according to an industry lobbyist. The reactor fleet is ageing but only two new reactors are under construction. The estimated cost of the two Hinkley Point reactors, including finance, is A$40 billion.
• All of Germany’s reactors will be closed by the end of 2022 and all of Belgium’s will be closed by the end of 2025.
• Russia’s Rosatom began construction of the first nuclear power reactor in Bangladesh, signed agreements to build Egypt’s first power reactors, and is set to begin work on Turkey’s first reactors ‒ but Rosatom deputy general director Vyacheslav Pershukov said in June 2017 that the possibilities for building new large reactors abroad are almost exhausted. He said Rosatom expects to be able to find customers for new reactors until 2020‒2025 but “it will be hard to continue.”
• A High Court judgement in South Africa in April 2017 ruled that much of the country’s nuclear new-build program is without legal foundation, and there is little likelihood that the program will be revived given that it is shrouded in corruption scandals and President Jacob Zuma’s hold on power is weakening.

The only nuclear industry that is booming is decommissioning ‒ the World Nuclear Association anticipates US$111 billion worth of decommissioning projects to 2035.

The Era of Nuclear Decommissioning

The ageing of the global reactor fleet isn’t yet a crisis for the industry, but it is heading that way. In many countries with nuclear power, the prospects for new reactors are dim and rear-guard battles are being fought to extend the lifespans of ageing reactors that are approaching or past their design date.

Perhaps the best characterisation of the global nuclear industry is that a new era is approaching ‒ the Era of Nuclear Decommissioning ‒ following on from its growth spurt from the 1960s to the ’90s then 20 years of stagnation.

The Era of Nuclear Decommissioning will entail:

• A slow decline in the number of operating reactors.
• An increasingly unreliable and accident-prone reactor fleet as ageing sets in.
• Countless battles over lifespan extensions for ageing reactors.
• An internationalisation of anti-nuclear opposition as neighbouring countries object to the continued operation of ageing reactors (international opposition to Belgium’s ageing reactors is a case in point ‒ and there are numerous other examples).
• Battles over and problems with decommissioning projects (e.g. the UK government’s £100+ million settlement over a botched decommissioning tendering process).
• Battles over taxpayer bailout proposals for companies and utilities that haven’t set aside adequate funds for decommissioning and nuclear waste management and disposal. (According to Nuclear Energy Insider, European nuclear utilities face “significant and urgent challenges” with over a third of the continent’s nuclear plants to be shut down by 2025, and utilities facing a €118 billion shortfall in decommissioning and waste management funds.)
• Battles over proposals to impose nuclear waste repositories and stores on unwilling or divided communities.

The Era of Nuclear Decommissioning will be characterised by escalating battles (and escalating sticker shock) over lifespan extensions, decommissioning and nuclear waste management. In those circumstances, it will become even more difficult than it currently is for the industry to pursue new reactor projects. A feedback loop could take hold and then the nuclear industry will be well and truly in crisis ‒ if it isn’t already.

Editor’s Note

Dr Jim Green is the editor of the Nuclear Monitor newsletter, where a longer version of this article was originally published.

Las Vegas: city’s municipal power runs on renewable energy

Rapid cost declines made renewable energy the United States’ cheapest available source of new electricity, without subsidies, in 2017, writes Silvio Marcacci of think tank Energy Innovation. In many parts of the U.S., building new wind is cheaper than running existing coal, while nuclear and natural gas aren’t far behind, notes Marcacci. As renewable energy costs continue their relentless decline, they keep pushing fossil fuels further from profitability – and neither trend is slowing down.

This dynamic is apparent in the decade spanning 2008-2017, where nearly all retired U.S. power plants were fossil fuel generation, and was capped by utilities announcing 27 coal plant closures totaling 22 gigawatts (GW) of capacity in 2017. The U.S. Energy Information Administration (EIA) forecasts coal closures will continue through 2020, potentially setting an all-time annual record in 2018.

U.S. utility-scale electric generation capacity retirements 2008-2020

Despite Trump Administration actions to improve fossil fuel economics and reduce renewable energy competitiveness, updated levelized cost of energy (LCOE) data and new renewable energy projects show clean energy continues beating fossil fuels on economics, at a faster pace and in more locations than ever before. So just how low can renewable prices go?

Levelized Cost of Electricity plummets for wind and solar

The 2017 edition of Lazard’s annual Levelized Cost of Electricity (LCOE) study, released in December, shows renewable energy continues to decline (dramatically, in the case of utility-scale solar photovoltaics) in cost. LCOE accurately compares the economics of different generation technologies by measuring the total cost of first building a power plant, then operating it over its assumed lifetime. Think of it as evenly comparing apples to oranges.

Unsubsidized LCOE comparison for different electricity generation technologies

Unsubsidized onshore wind and utility-scale solar are both cheaper than new coal in many parts of the U.S., and are cost-competitive with combined-cycle natural gas on a levelized cost basis. In the words of Tom Sanzillo, Director of Finance for the Institute for Energy Economics and Financial Analysis, “clean energy is now cheap energy.”

Lazard reports the mean subsidized LCOE for utility-scale solar fell 72% from $178 per megawatt-hour (MWh) in 2009 to $50/MWh in 2017, while the mean LCOE for wind energy fell 47% from $85/MWh to $45/MWh over the same time span. These declines outstripped the cost trends for natural gas-combined cycle (down 27%), coal (down 8%), and nuclear (up 20%) from 2009 to 2017.

Selected historical mean LCOE values for electricity generation technologies

As technology costs fall, wind and solar installations rise

The changing cost dynamic between renewable energy and fossil fuel is spurring coal closures along with new wind and solar installations. As the weighted LCOE for utility-scale solar fell from more than $350/MWh in 2009 to less than $50/MWh in 2017, cumulative installations rose from 1 GW in 2009 to more than 30 GW cumulative installed capacity in the third quarter of 2017.

Utility-scale solar installations rise as LCOE falls

Onshore wind is even cheaper and more widespread than utility-scale solar, declining from around $135/MWh and around 35 GW installed capacity in 2009 to less than $45/MWh and more than 85 GW installed capacity in 2017.

Onshore wind installations rise as LCOE falls

These numbers are translating into record-low prices for new renewable energy generation. In December 2017, GTM Research’s Colin Smith flagged a 15-year power purchase agreement (PPA) signed by Austin, Texas between $23.50-$27.25/MWh for a 150-megawatt (MW) solar project, as the lowest U.S. utility solar photovoltaic deal. In early January, Xcel Energy announced that developers responded to their RFP for new generation capacity (to help replace two coal-fired power plants) with median bids for new wind at $18.10/MWh, wind and solar at $19.90/MWh, and wind and solar with battery storage at $30.60/MWh. And while not located in the U.S., the Canadian province of Alberta awarded 600 MW of unsubsidized new wind contracts in December 2017 at a median price of $29.60/MWh.

Lazard emphasizes wind and solar LCOE vary greatly by region – these technologies are cheapest in the windiest and sunniest locations – but the net result of fast-falling costs is already showing up through the changing U.S. power mix: EIA’s December 2017 Monthly Energy Review reported renewables replaced coal and gas in 2017.

Total U.S. electricity generation fell 2.6% and total electric use declined 3% in 2017 compared to 2016, while coal and nuclear generation each declined 1.5% while natural gas generation fell 11% By comparison, utility-scale solar generation rose 51% and wind generation rose 11% in 2017 compared to 2016.

See the trend?

Renewable energy costs forecast to keep falling while fossil fuel costs hold steady

Unfortunately for fossil fuel advocates, renewable energy is expected to keep getting cheaper and adding more capacity while coal, nuclear, and natural gas costs are forecast to remain stagnant and lose ground in the overall power mix.

The National Renewable Energy Laboratory’s (NREL) Annual Technology Baseline 2017 considers recently installed and anticipated near-term projects to forecast onshore wind’s most likely mid-range LCOE will fall from $39/MWh in 2020 to $28/MWh in 2050. Similarly, NREL forecasts utility-scale solar’s most likely mid-range LCOE will decline from $51/MWh in 2020 to $37/MWh in 2050.

Projected LCOE for different U.S. power generation technologies 2020-2050

By comparison, NREL forecasts the LCOE of fossil fuel generation will hold steady or even increase. ATB 2017 predicts the most likely mid-range LCOE for natural gas combined-cycle plants will rise from $43/MWh in 2020 to $51/MWh in 2050, coal’s most likely mid-range LCOE will hold steady from $71/MWh in 2020 $68/MWh in 2050, and nuclear’s most likely mid-range LCOE will stagnate between $79/MWh in 2020 to $78/MWh in 2050.

As a result, installed U.S. renewable energy generation could double between now and 2020 , according to the Federal Energy Regulatory Commission’s (FERC) most recent Energy Infrastructure Update. 116 GW of proposed utility-scale solar and wind net additions could come online by December 2020, roughly twice the current total installed generation capacity of 115.5 GW. Wind would add 72.5 GW (with only 68 MW of retirements) while utility-scale solar would add 43.5 GW new capacity (with just 2 MW of retirements).

Meanwhile, coal could see an 18.7 GW net decline (6.6% of current capacity) and nuclear could see 2.3 GW less generation (2.2% of current capacity). Natural gas would keep pace with renewables, with 92.5 GW potential capacity additions and 10.8 GW in potential retirements, for a net capacity gain of 81.7 GW.

When other renewables like hydropower and geothermal are added in, renewable energy could make up 26.5% of total U.S. generation capacity in 2020, up from 19.9% today – with solar and wind composing 16.7% of total capacity. FERC does not count distributed solar (i.e. rooftop solar) generation in this tally, meaning solar’s total generation could be much higher.

Even the Trump Administration’s newly imposed 30% import tariff on solar panels won’t materially slow this transition. According to GTM Research, the tariffs will only raise solar prices between 10-12 cents per watt, roughly a 10% increase. Since panels are less than a third of utility-scale solar installation costs and the tariff declines over time, GTM Research predicts the U.S. market could slow around 11% through 2022. One Chinese solar company has even predicted U.S. solar module prices would still be lower at the end of 2018 than in 2017.

Three ways to tap the cheapest generation options

U.S. grid operators are already integrating higher wind and solar energy penetrations without risking reliability, but fully capitalizing on cheaper renewable energy relies on regulators and utilities collaborating on three important policy actions.

First, ensure wholesale market design properly values grid flexibility and supports the renewables transition by accurately valuing distributed generation. Second, expand strategies to help utilities retire unprofitable older generation while dedicating funds to retrain workers and assist communities affected by closures. Third, align the financial incentives of utilities with the outcomes consumers want, to deliver value through performance-based regulation.

By focusing on policies that work with changing U.S. energy economics, utilities can improve their bottom line and avoid risky investments, while regulators reduce consumer costs and accelerate the clean energy transition.

Editor’s Note

Silvio Marcacci is Communications Director at the San Francisc0-based think tank Energy Innovation, where he leads all public relations and communications efforts.

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

ABB’s Longmeadow microgrid in Johannesburg, South Africa

Energy experts at Navigant Research are convinced that micro-grids are moving from a niche novelty to mainstream, writes Fereidoon Sioshansi, publisher of newsletter EEnergy Informer. They forecast cumulative micro-grid investments of over $100 billion over the next decade, much of it in North America and Asia. Europe is lagging behind, but Finland may represent a growth market. Sioshansi takes a closer look at what microgrids are and how they are poised to shake up the electricity sector.

The first challenge with micro-grids is to decide on a definition. Not unlike smart grid, it means different things to different people. A recent analysis performed for the California Energy Commission (CEC), for example, identified 17 definitions attributed to a variety of organizations including International Council on Large Electric Systems, or CIGRE, using its French acronym. Other terms such as mini-grid, nano-grid and virtual power plants (VPPs) are also commonly used.

Virtually all mostly refer to the ability to optimize and aggregate distributed energy resources (DER) in one form or fashion.

Acknowledging the definitional issue, Peter Asmus, an expert on the topic at Navigant, suggests using one from the US Department of Energy (DOE), recently modified to include off-grid remote systems, which have historically dominated the global micro-grid market. It says, “A microgrid is a group of interconnected loads and distributed energy resources within clearly defined electrical boundaries that acts as a single controllable entity with respect to the grid. A microgrid can connect and disconnect from the grid to enable it to operate in both grid-connected or island mode. A remote microgrid is a variation of a microgrid that operates in islanded conditions.”

The key feature of a microgrid, according to Asmus, is the ability to island or disconnect from a larger grid when there is an outage or when it is economically advantageous to do so. 

Definition aside, where are microgrids being deployed and why? According to the 13^th edition of Microgrid Deployment Tracker published by Navigant Research in Dec 2017, over 20 GW of projects or portfolios of projects have been identified worldwide.

At present, no central agency or organization accurately and comprehensively tracks microgrids – hence one cannot be sure how many are operating, under development or proposed worldwide. Though incomplete, the Tracker is the most comprehensive tally of microgrids by region and segment available.

According to Navigant Research, Asia Pacific leads, followed by North America. The former tends to be mostly remote, off-grid systems, whereas the latter – particularly those in the US – tend to be connected to a utility grid.

The North American market, according to Asmus, is the most interesting region over the last 5 years due to recent extreme weather conditions leading to major power outages. This has resulted in increased interest – and funding – to maintain vital services during emergencies. In some cases, the micro-grids can in fact enhance the resilience of the macro-grid, to which they are usually connected.

Connecticut was the first state to pass a law promoting microgrids in 2011. Since then Maryland, Massachusetts, New Jersey, New York and others have enacted programs, as has California, which recently issued an RFP [request for proposal, a type of tender, editor] with $44 million funding to develop low-carbon microgrids. With recent storms knocking out power in Texas, Florida and Puerto Rico, other states are likely to follow.

Most such programs are focused on community and utility distribution microgrid projects, which face the most challenging regulatory barriers. Asmus, however, believes that the commercial and industrial (C&I) segment is poised for major growth. The primary reason is the declining cost of key enabling technologies, such as solar PVs, wind, energy storage systems (ESS) and the proliferation of new and creative business models that are increasingly able to monetize more of the value of such systems and capture them.

The most vexing conundrum facing microgrid development, according to Asmus, is financing – unsurprisingly. Among the promising C&I business models is Schneider Electric’s microgrids-as-a-service offering. By taking on the risk for performance and removing the upfront capital investment, the vendor can make the value proposition more attractive. Variations on this theme, including a combination of DERs (distributed energy resources) plus intelligent distributed ESS are beginning to gain traction among C&I customers.

Some proponents of Micro-grids argue that the best way to grow the market is not only to allow, but encourage utilities to invest in

s such systems just as they do with other infrastructure: by putting those costs into customer rates. Some utilities have been successful in this effort, among them the pioneering San Diego Gas & Electric Co. (SDG&E) project in Borrego Springs utility distribution microgrid. Others, however, have confronted regulatory skepticism and rejection, including Baltimore Gas & Electric Co. (BG&E), Commonwealth Edison Co. (ComEd) and others.

For their part, the regulators, many of whom do not understand, let alone appreciate the full value of micro-grids, are reluctant to allow utility rate-basing of microgrids until and unless they can be assured of the cost effectiveness of the schemes – and assurance that the benefits are widely shared among all customers, not just a select few.

The key question for regulators, according to Asmus, is to be sure that the dollars invested in microgrids provide system-wide benefits that justify the expense. How long before that critical milestone is reached is anybody’s guess.

In the meantime, Asmus believes that the private sector will lead the market, but he is optimistic that utility, and more importantly regulatory acceptance of micro-grids, will occur within the next 3 years.

This is among the reasons that Navigant Research is forecasting cumulative micro-grid investments of over $100 billion over the next decade. It is convinced that micro-grids are moving from a niche novelty to mainstream. Many others concur. Whether we call these micro-grids or by another name may not matter as much as the emerging consensus that much more is likely to happen on the customer end of the business. Regulators can encourage and facilitate the transition process by providing better clarity and regulatory support.

Is Finland Europe’s Best Hope for Microgrids?

While Europe is considered a global leader in moving toward a low carbon energy future, the tightly regulated EU markets have several features that severely limit the development of microgrids, writes Peter Asmus, energy expert at Navigant Research on Navigant’s blog on 7 December 2017:

• “The focus in Europe has been on large-scale renewable energy development such as offshore wind, which requires massive investment in transmission infrastructure.
• Deployment of distributed energy resources such as rooftop solar PV has primarily been based on feed-in tariffs, a business model precluding the key defining feature of a microgrid—the ability to seal off resources from the larger grid via islanding.
• EU markets are tightly interwoven and methods to address the variability of renewables such as wind and solar lean toward cross-border trading, not localized microgrids.”

As the Navigant Research’s Microgrid Deployment Tracker demonstrates, Europe represents only some 9% of the global microgrid market. The vast majority of microgrids deployed in Europe are on islands in the Mediterranean, the Canary Islands off the coast of Spain, or projects such as Bornholm or the Faroe Islands of Denmark, notes Asmus.

According to Asmus, “a unique confluence of factors make Finland the best opportunity for microgrids in Europe. Finland is not only the global leader on smart meter deployments, with 99% of its 3.5 million customers having access to this technology, but it also has a deregulated wholesale and retail market that features 83 distribution system operators (DSOs), with the largest distribution networks composed of 200,000 customers.”

“Unlike its neighbors Sweden and Norway, Finland lacks massive hydroelectric resources. What hydro it has tends to be run-of-the-river systems, and some of the smaller scale systems are microgrid-friendly. Most importantly, Finland is a country that does not fully share the stellar reliability associated with the EU grid. During blackouts in 2011 and 2012, as many as 570,000 customers lost power for an extended period of time. This outage raised the issue of the vulnerability of the Finland grid to winter storms due to overhead lines running through the country’s deeply forested regions that can sag from snow.”

Asmus notes that “in a quick response to these power outages, new regulations have been put in place that limit power outages to 6 hours annually for urban residents and 36 hours for rural customers by 2028. In a policy that would likely scare utilities in the US, DSOs are required to compensate customers for power outages. If a power outage lasts longer than 12 hours, the DSO must pay the customer 10% of its annual distribution fee, and compensation goes up gradually to a maximum of 200% with interruptions longer than 288 hours.”

The first option of most DSOs to respond to these new regulations is to place distribution lines underground. However, writes Asmus, “that can be expensive, especially given the low density of some DSO customer bases. According to research performed by Lappeeranta University of Technology (LUT), the lowest cost option for 10%‒40% of the medium voltage branch lines would be low voltage direct current microgrids. One such LVDC microgrid project, developed by LUT in collaboration with DSO Suur-Savon Sähkö, was developed in 2012, incorporating solar PV and batteries. Though only one other microgrid currently is operating, Finland represents an ideal market for utility distribution microgrids.”

For more information see also www.peterasmus.com

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 February 2018 edition of EEnergy Informer and is republished here with permission. 

His latest book project is Innovation and Disruption at the Grid’s Edge, published in June 2017. It contains articles by two dozen experts on “how distributed energy resources are disrupting the traditional utility business model”/

Forget the latest Tesla announcement, writes John Massey. What is more important for the future of electric cars is how we will solve the challenge of charging them. Massey, an independent energy analyst and trainer, discusses the four main challenges of EV charging and concludes that the outcome of the process will depend on the interplay between electricity supply options, market operations, grid costs, policy choices and consumer behaviour (both rational and irrational).

Forget the latest Tesla announcement, the fanciest new concepts, or the scramble of traditional automakers to add electric drivetrains to their product mix. Yes, electric vehicles (EVs) will get cheaper, better and more diverse: that’s just inevitable technology progress.

What you should be focusing on is charging them up. The most challenging and disruptive changes lie within the electricity system. Here I’ll give just a brief flavour of the issues, divided into four sections as follows:

• The Electricity Mix
• Distribution Networks
• Fast Charging
• Autonomous Vehicles

My aim is to get you thinking, so I’ll be raising far more questions than I answer!

I’m certainly not raising these questions because I’m pessimistic of solving them – quite the opposite. But it’s only by asking them that we can start to develop solutions and identify new business opportunities which will take us in the right direction.

The electricity mix and price signals

At a macro level, the overall increase in electricity demand due to EVs is likely to be just a few %, often less than 10%. On the one hand that doesn’t sound a lot. Nevertheless it’s still a significant chunk of new power generation capacity (or an increased utilisation of existing capacity). At the very least it could reverse the trend of decreasing electricity use seen in markets like here in the UK.

More significant than average changes in demand, will be when these changes occur – and how they fit with changing supply.

For example, in cool northern climates demand is already greatest in the winter. The additional demand from EVs may be enhanced in the winter too, as a result of their reduced efficiencies in cold weather: meaning more charging is needed to achieve the same mileage.

One UK analysis concluded that in a town with a population of 6,800, just 900 EVs entering the system could lead to brownouts

The UK is one market where the removal of coal is a carbon policy priority. It’s one that has been progressing well: coal has been disappearing from the electricity mix at a rapid rate in recent years. In 2017 however, during the top 10% hours of highest electrical demand, coal provided a sixth of Britain’s electricity. Those peak demand hours occur during early evening cold winter evenings – just when many people are arriving home and in temperatures where EVs are operating least efficiently. So when the coal is gone (as is government policy), what will replace both that missing supply and the additional requirement as EVs push demand up?

The rise of EVs adds extra emphasis to a question of dependable supply capacity that existed anyway.

On the other hand, in summer there is likely to be excess energy available in the middle of a sunny day, due to large solar capacity. Will EVs be able to soak up that excess? That would be great, because prices, at least at a wholesale market level, will be low. Adding EV demand could avoid both these prices going negative and the curtailment of clean energy. Cheap charging would be good for consumers and increased demand would boost the value of solar energy. But does the middle of a sunny summer day coincide with when people want to be charging? If it doesn’t, will prices – when at the retail level – prove low enough to shift their behaviour?

There will also be times of plentiful or excess energy due to wind, but since these are much more variable, it’s impossible to model the impact based on any regular schedule. Price-taking here would need to be a much more ad-hoc, automated response.

Of course the volatility of prices in a system depends strongly on the flexibility of the system itself. Extremes, whether high or low (even negative) are symptoms of inflexibility. Excesses of energy may prove more attractive to store elsewhere (in stationary energy storage systems) or to export, or to utilise through other demand response mechanisms (refrigeration, heating and more). Indeed as EV fleets expand, their aggregated charging response will itself likely become an important source of macro system flexibility, smoothing out the very price signals that initially guided it.

Fast-charging could be key in overcoming anxieties around range. If you know you’ll be able to stop for just a short time, then leave with a battery full enough to get you where you are going, that’s one major inhibitor of EV uptake gone

It’s worth noting that where volatility is high and hence changes in tariff could prove attractive, concerns have already arisen around “changeover points”: for example multiple cars all starting to charge the moment a tariff change signal occurs. Systems do already exist to mitigate this though, delaying or spreading charging initiations to avoid unwanted local spikes in power draw from the distribution grid. (We’ll focus on those nasty spikes in the next section).

At larger penetration of EVs though, how far can charging delays be pushed, without consumers missing out on tariff benefits or fretting over their state of charge?

Distribution networks and demand diversity

If everyone on your street decided to switch on their electric oven at the same time, a fuse at the local substation would likely go “pop”. Everyone would find themselves in the dark (with those electric oven owners limited to eating salad).

In other words, grid capacity is already sized around demand diversity, rather than scaled to accommodate synchronised maximum demands. This approach keeps costs down by avoiding sizing infrastructure to meet very, very unlikely scenarios. It isn’t aggregated energy that matters here, it’s power demand at any specific moment in time.

One key problem with the idea that EVs will automatically take advantage of low prices driven by excess solar or wind energy is that this could decrease demand diversity (if they all choose to start charging at the same time). And EVs, especially future ones with faster chargers, are bigger draws on power than electric ovens!

One UK analysis concluded that in a town with a population of 6,800, just 900 EVs entering the system could lead to brownouts (through a drop in the voltage of supply). At a more local level, a pilot project showed problems when just five 3.5 kW chargers were connected to a network cluster (with 134 dwellings) and charged at the same time. That project concluded that 32% of UK low voltage circuits (312,000 in total) would require reinforcing if 40% – 70% of customers had EV’s with 3.5 kW chargers (i.e. very slow ones, with 7kW now becoming the norm). That was estimated as a present-day cost of around £2.5bn. Ouch. Luckily pilots aren’t just about identifying problems, they’re about solving them too. This same one tested a system to avoid much of that reinforcement cost by managing charging when local grid capacity started to be strained.

In the absence of diversity, managed charging is thus essential in addressing the potential conflict between cheap energy supply and expensive grid upgrades. It shouldn’t just be driven by least-cost wholesale electricity, starting the process as soon as this is available. It should account for grid constraints and distribution costs too. It’s also worth noting that managed charging itself imposes some costs, such as installation and maintenance of the required communication infrastructure.

In practice, distribution network upgrades won’t be a nationwide issue, certainly not at the start of the EV growth story. Some localities – wealthier urban streets – will have greater concentrations of EVs and/or greater concentrations of larger EVs (attached to higher-power chargers).

This raises interesting policy and socioeconomic questions.

Should the costs of local grid upgrades be spread across other electricity consumers, those elsewhere and even without EVs, in order to enable drivers to access to cheap electricity? Or should demand charges (based on each consumer’s peak power requirement) become a much more significant element of domestic electricity bills?

Should electricity charges, whether based on demand or on energy consumption, become differentiated down to the local level through new “nodal marginal pricing” regimes. These take account of specific congestion conditions within the grid, with high prices discouraging consumption where congestion is high. Such pricing schemes exist at the wholesale market level in a number of electricity markets around the world, but not yet at the distribution level.

National Grid have suggested it might be better to build a few thousand super-fast charging forecourts of >3 MW capacity rather than undertake a large scale rebuild of the domestic electricity infrastructure

Is a better solution to avoid charging EVs directly from the grid; charging stationary storage systems instead. That could be done when it makes most sense in terms of grid capacity and/or energy cost, spreading a low power draw through the day. Then EVs could charge from this stationary storage, at a faster rate, when it makes most sense for a consumer’s own mobility needs. What are the economic and aggregated energy implications of that approach, given that each extra storage roundtrip involves energy losses?

If the solution is to be a combination of several or all of these options, which combination will be both comprehensible and acceptable to consumers, while efficient in terms of reducing grid reinforcement costs? Are these goals even all deliverable at the same time?

Fast chargers and “filling stations”

The last section focused on home-based charging – and it certainly seems reasonable to assume that, unless unable to, most EV owners would like to have a charger at home. Nevertheless, distribution constraints mean that unless they are prepared to pay for the privilege of higher power, this charger will likely remain slow.

Yet there is clearly lots of interest in fast charging, with ever-increasing sets of headline numbers around how powerful these will be (350kW being the highest I’ve seen thus far).

Fast-charging could be key in overcoming anxieties around range. If you know you’ll be able to stop for just a short time, then leave with a battery full enough to get you where you are going, that’s one major inhibitor of EV uptake gone. It doesn’t matter that most people might have 90-95% of their journeys within the range of EVs – that other 5% can still give cause for concern. Not so, if one quick stop solves that rare problem.

In the UK, around 40% of car owners live in homes where installation of a charger remains problematic (for example shared residences or those without off-street parking). For them, the need to visit a “filling station” may be a necessity rather than a nicety. It remains to be seen whether these public or privately-operated chargepoints will be in similar locations as now (as Shell, for one, hopes) or elsewhere – supermarkets, car parks and so on.

Utilisation and demand diversity will prove key to identifying the grid requirements, the costs and hence the business cases in any eventual outcome.

Fast charging may flatten aggregate demand curves (i.e. a macro system impact), but increase local capacity issues (through short-but-high peaks at specific locations). Bear in mind that ten 350 kW chargers would require an infrastructure capable of handling 3.5 MW. In current fossil-fuel forecourts, 20 pumps are not uncommon: that would require 7 MW of infrastructure support in a single spot. Proposed solutions to very high demand chargepoints range from siting them close to high-speed electrified rail lines, to utilising stationary battery storage too (as suggested for domestic charging in the last section).

However connected, fast and super-fast chargers will compete for charging revenue with slow and domestically-sited charging demand. Opinions vary on which will predominate.

National Grid have suggested it might be better to build a few thousand super-fast charging forecourts of >3 MW capacity rather than undertake a large scale rebuild of the domestic electricity infrastructure. As they put it: “it may well be that the charging from home option may not be in the long term interest of the consumers even with smart chargers.”

That approach conflicts with one which links domestic charging and a consumer’s own electricity supply: charging their car from their own PV rooftop, perhaps with stationary storage too. That’s an attractive, “in control” concept for many consumers. It also removes some other concerns they may have. Would relying on a fast charging station mean queues at peak times? Would every “pump” be interoperable with every car?

Current opinion appears to favour relatively slow home-charging as the dominant mode, while recognising rapid charging networks will certainly be required. They may be used relatively infrequently, as emergency, “unplanned” charging options or on rarer long journeys – and will likely be priced as such. At a recent conference in London, National Grid suggested that as few as 50 ultra-rapid chargepoints in key locations could solve range anxiety issues here in the UK; and at relatively minor cost.

Beyond “slow” and “fast” charging, there’s wireless charging. Who’s to say we’ll need to plug in at all: maybe one day the battery charge will be topped up at every parking spot? Or a little bit added every time we pause, at a junction or traffic light? If that seems like science-fiction, be aware that the technology already does exist.

Fully-autonomous EVs

The impact of fully-autonomous EVs is one which promises to be significant at all levels within the electricity system, both macro and local.

One key question concerns overall energy use. Will AEVs increase or decrease driven miles? There are a lot of variables that feed into answering that question.

How many AEVs will simply replace private vehicle ownership on a one-to-one basis? How many will be shared AEVs (SAEVs), whereby a single car replaces several privately owned ones, through car sharing or “Mobility as a Service” (MaaS) schemes? In either case, will the AEV experience prove so pleasant that more journeys are made, perhaps even reducing demand for public (mass) transport? Or will route-sharing and efficiency algorithms, plus other SAEV fleet management software get people from place to place with less overall driven miles?

There is some evidence that ridesharing may increase usage: one study concluded that, between 2013 and 2016, ridesharing services increased miles driven in New York City by 600 million.

From an individual charging and network perspective, the requirements and changes created by AEVs are highly uncertain. Nevertheless, we can theorise some impacts.

Some analysts suggest shared fleets will favour centralised super-charger locations, cost-optimised for fleet-owners by locating close to substations and away from congested grid nodes

It is likely that SAEVs and MaaS businesses in particular will depend on access to fast charging: after all, time spent charging a battery is time not spent charging customers. The latter is an opportunity cost, which will certainly exceed the electricity charging costs.

On the other hand, a shared vehicle fleet will be smaller than an individually-owned one. That probably mean fewer chargers overall will be needed, to service fewer cars; though these cars will need to charge up more often.

Some analysts suggest shared fleets will favour centralised super-charger locations, cost-optimised for fleet-owners by locating close to substations and away from congested grid nodes. On the other hand ride-sharing is likely to be particularly attractive as a business within densely populated areas, where utilisation rates are high but centralised charging sites may be limited.

Location and timing issues will be interlinked. Perhaps peaks will occur before and after each commute period? But where will these occur? For the morning commute, an “after” peak might take place at central city locations close to which cars have converged. But where will the AVs have charged up prior to rush hour? Will they spend the night at suburban charging centres, or themselves first commute out of the city in order to bring people back in?

New behavioural patterns of mobility create big implications for the electricity grid. Will new behaviours drive grid changes or will grid constraints limit behavioural change? The answer is probably just a question of the timeframe we choose to consider.

Confused? I hope so!

If you thought the most interesting issues in the transition to electric vehicles lay in the progression of the vehicles themselves, then hopefully I’ve changed your mind.

Instead I encourage you to look far more closely at how all those batteries will be charged, both from a macro (energy mix) perspective and from a local grid network one too.

How many chargers will we need, where will they be and who will operate them?

The road to answering such questions will be winding and awash with intersections and route choices. It will involve business models which may make sense in the short-term but prove to be dead-ends in the long-run. It will depend on the interplay between electricity supply options, market operations, grid costs, policy choices and consumer behaviour (both rational and irrational).

It will be an exciting journey!

Editor’s Note

Dr John Massey (john@greycellsenergy.com) is Managing Director of Grey Cells Energy Ltd. and an independent energy business analyst and trainer.

This article was first published on his blog Grey Cells Energy and is republished here with permission.

The European Council’s proposals on the internal energy market fundamentally weaken the framework that is needed to deliver an integrated market that will benefit European energy consumers, write Philip Baker and Christos Kolokathis from the global energy policy advisors Regulatory Assistance Project (RAP). They may even legalise practices that are currently – and should remain – illegal. The authors call on European policymakers to support the European Commission’s proposals in the Clean Energy Package.

Europe can deliver enormous benefits to its electricity consumers by accelerating progress toward an integrated internal energy market. There are three key pathways for unlocking this potential, all involving a more regional approach to operating Europe’s electricity grid. These are: increasing the interconnector capacity made available to the markets and taking a more collective or regional approach to both assessing resource adequacy and energy balancing.

The European Commission’s Clean Energy for All legislative package (CE4All), published on 30 November 2016, represents significant progress in the right direction. The Commission’s proposals are now being negotiated by the European Parliament and the European Council (the Member States). The outcome of this process will make or break progress on the EU’s energy market integration for the next decade. Unfortunately, counter-proposals made by the European Member States  threaten to halt progress – or even reverse it.

Market integration lowers costs

Regionalisation will have many benefits—allowing customers to access the cheapest sources of energy, pooling risk and exploiting geographic diversity, and reducing the need for new generation capacity. Estimates by Booz & Co and others suggest that the increase in social welfare of fully integrating Europe’s electricity markets, some of which have already been achieved through market coupling, could lie in the range of €16 to 43 billion per year by 2030.

Member States need to take appropriate account of potential support from neighbouring systems when assessing security of supply

The magnitude of future savings depends on the extent to which Europe’s generation portfolio can be optimised and the necessary interconnector capacity developed. As shown by the chart below, the bulk of these savings will be accrued by harmonising and lowering wholesale energy prices, with smaller but still significant savings arising from a more regional approach to resource adequacy and balancing.

While investment in new capacity will be required, there is considerable potential to increase the utilisation of existing interconnector capacity.

Analysis by the Agency for the Cooperation of Energy Regulators (ACER) shows, as depicted below, that only around one-third of the realistically available cross-border capacity is currently offered to the market in the Core —excluding the Central Western—region, which covers the majority of continental Europe.

In some instances, the capacities offered are even lower. For example, Germany limits imports from the Netherlands to some 12 percent of available interconnector capacity, while the Netherlands manages to allow 83 percent for flows in the opposite direction.

Aggregated tradable interconnector capacity compared with benchmark. ACER/CEER 2017

The low level of interconnection capacity made available to the wholesale markets results, to a large extent, from the practice of reducing congestion within national borders by limiting cross-border flows.

Despite the fact that Article 16 of Regulation EC 714/2009 prohibits “moving internal congestion to the borders,” ACER’s analysis shows that the practice is widespread. This is all the more remarkable given that the practice is analogous to imposing a cap on cross-border trade in goods in order to protect the interests of a particular Member State—a practice that would not be tolerated in any other area of the European Single Market.

Council’s proposal reverses progress on interconnector usage

In Article 14 of the Regulation on electricity markets, the Commission proposes to address this situation by stipulating that re-dispatch and counter-trading (i.e., adjusting generation schedules to manage internal congestion) should be used to maximise cross-border capacity, provided that it is economically beneficial to do so “at a Union level.”

However, the Council has proposed that the increase in interconnection capacity offered to the market should be allowed to follow a linear progression, starting at the level of capacity offered at the point of enactment and rising to 75 percent of available capacity after four years, or by 2025.

It is also interesting to note that, of the Member States that assume zero or little interconnector contribution, five are implementing or planning to implement capacity mechanisms

This represents a significant retreat from the current legal position, which is that interconnector capacity offered to the market should be maximised and should not be reduced by “moving internal congestion to the borders” – subject to grid security not being compromised.  In addition, the proposal seems entirely arbitrary and could encourage Member States who currently limit interconnector capacity to delay taking action, thus ensuring they have a low baseline for the proposed linear progression.

The Commission’s original proposal should therefore be supported and the Council’s counter-proposal rejected.

It is also important to rigorously enforce existing legislation that prohibits moving congestion to the borders. If a Member State seeks to be derogated from this requirement, it should be required to demonstrate that the costs exceed the regional benefits or that security would be compromised.

This legislation should protect the interests of Europe’s electricity consumers as a whole, rather than those of any individual Member State.

Regional assessment of resource adequacy necessary

While some Member States are forecasting capacity deficits in the years ahead, others are forecasting surpluses. Taking Europe as a whole, most Member States are situated in regions with a healthy resource adequacy situation. Aggregating these surpluses and deficits over appropriately defined regions will reduce the overall need for investment in new resources. At the same time, it will allow supply reliability to be maintained at a lower cost than would be the case if Member States continue with a “self-sufficiency” approach.

While responsibility for security of supply remains a matter for individual Member States, this responsibility needs to be squared with the benefits to those same Member States and their consumers from a more collective approach to resource adequacy assessment in order to realise the potential savings in investment costs. Member States therefore need to take appropriate account of potential support from neighbouring systems when assessing security of supply.

To some extent this already happens. However ACER’s 2017 Market Monitoring Report exposes the wide disparity in the extent to which interconnection contribution is taken into account. ACER’s analysis shows that, out of 21 Member States surveyed, 10 did not take any account of interconnection contribution to resource adequacy. Of the remainder, the extent to which interconnector contribution was taken into account varied widely.

It is also interesting to note that, of the Member States that assume zero or little interconnector contribution, five are implementing or planning to implement capacity mechanisms. This begs the question: would those mechanisms be necessary if proper account was taken of potential interconnection contribution?

Clean Energy for All package mixed on shift to regional resource adequacy

The failure of Member States to fully take into account interconnector contribution to resource adequacy risks unnecessary investment in generation capacity—costs that will be borne by electricity consumers.

Furthermore, the wide disparity in the level of contribution assumed underlines the need for a common methodology and a coordinated approach to analysis across the internal energy market. The Commission’s CE4All package recognizes the need for a coordinated approach, with Article 18 of the recast Regulation proposing that Member States monitor capacity requirements based on the European-wide assessment carried out by the European Network of Transmission System Operators, ENTSO-E.

In addition, Article 22 proposes that non-domestic generation capacity should be allowed to participate in capacity mechanisms and that the Regional Operational Centers (ROCs) should have a meaningful role in deciding on the level of participation.

The Council is resisting a more regional approach and has proposed that transmission system operators (TSOs) continue to be responsible for balancing requirements

The Commission’s proposals for a coordinated approach should be supported. The introduction of a European, or preferably a regional, resource adequacy assessment would allow capacity surpluses and deficits to be aggregated on a regional basis, raising the value of existing resources and reducing the need for investment in new resources.

By contrast, the Council’s watered-down proposal would allow Member States to continue to assess capacity requirements on a national basis, albeit “taking note” of any European assessment and opinion issued by ACER. The Council’s proposal therefore risks failure to deliver the benefits that a more coordinated resource assessment could bring.

Regional electricity balancing most effective approach

The need to minimise imbalance costs will assume increasing importance as the deployment of wind and solar continue and balancing energy over wider areas will allow geographic and technical diversity to be exploited, reducing balancing volumes.

While analysis suggests that the potential savings in balancing costs will be relatively modest compared with savings from market integration and a coordinated resource adequacy assessment, the savings to be achieved by balancing across wider areas are still significant at about €3 billion per year by 2030.

There has been relatively little progress in coordinating national balancing activities in Europe to date. In fact, analysis shows that imbalance price differentials are far greater than in the day-ahead and intra-day markets. These price differentials are significant for a number of reasons. Imbalance prices ultimately provide a cap or collar on day-ahead and intra-day prices and will therefore impact the extent to which these prices can be harmonised across Europe. Furthermore, unnecessarily high imbalance prices, i.e., where prices are inflated due to a lack of competition or liquidity, represent a barrier to market entry—particularly for small entities and for intermittent renewable resources, which cannot easily respond close to real time. 

Difference in upwards balancing energy price and day-ahead energy price, 2016 ACER/CEER 2017.

The Commission’s Clean Energy for All package

Article 5 of the Commission’s recast Regulation on energy markets proposes that balancing and reserve capacity should be calculated and procured on a regional basis. In addition, Article 34 requires that ROCs should have a meaningful role in these activities. This is eminently sensible and necessary if the benefits of balancing over wider areas are to be realised, and the Commission’s proposal to regionalise these activities should be supported.

The Council’s position, at best, waters down the Commission’s proposal and perpetuates the status quo. At worst, it represents a large step backward

Unfortunately however, the Council is resisting a more regional approach and has proposed that transmission system operators (TSOs) continue to be responsible for balancing requirements, although noting that this “may be facilitated on a regional level.” Exactly what this means is unclear.

However, what is clear is that unless reserve and balancing capacity requirements are assessed at a regional level and procured via a regional platform as proposed by the Commission, the potential cost savings associated with energy balancing and the integration of renewable resources will not be realised. The Council’s position, that balancing remains a TSO responsibility, with ROCs having no meaningful role and unable to apply their regional focus and expertice, risks placing these savings out of reach.

Don’t lose sight of the forest for the trees

When considering specific issues related to power market and system operation, it is easy to lose sight of the overall benefits to consumers that regionalisation and market integration can deliver.

We must be aware of those benefits and recognize the fundamental importance of regionalisation and market integration in the cost-effective, reliable transition to a decarbonized power sector. The Council’s position, at best, waters down the Commission’s proposal and perpetuates the status quo. At worst, it represents a large step backward.

Editor’s Note

Philip Baker is Senior Advisor at the Regulatory Assistance Project. Christos Kolokathis is an Associate at the Regulatory Assistance Project. 

The Regulatory Assistance Project (RAP) is an independent, non-partisan, globally operating non-governmental organization dedicated to accelerating the transition to a clean, reliable, and efficient energy future.

Energy storage can help grids use more wind and solar power, but it does not always reduce carbon emissions, write Naga Srujana Goteti, Eric Hittinger and Eric Williams of the University of Rochester. In some cases, adding storage actually even increases carbon emissions. This happens when consumption is shifted to periods when coal power is used more. Article courtesy The Conversation.

Carbon-free energy: Is the answer blowing in the wind? Perhaps, but the wind doesn’t always blow, nor does the sun always shine. The energy generated by wind and solar power is intermittent, meaning that the generated electricity goes up and down according to the weather.

But the output from the electricity grid must be controllable to match the second-by-second changing demand from consumers. So the intermittency of wind and solar power is an operational challenge for the electricity system.

Energy storage is a widely acknowledged solution to the problem of intermittent renewables. The idea is that storage charges up when the wind is blowing, or the sun is shining, then discharges later when the energy is needed. Storage for the grid can be a chemical battery like those we use in electronic devices, but it can also take the form of pumping water up a hill to a reservoir and generating electricity when letting it flow back down, or storing and discharging compressed air in an underground cavern.

Motivated by a view that storage is a “green” technology, governments are increasingly promoting utility-scale and distributed energy storage. For example, in November 2017, New York Gov. Andrew Cuomo signed a bill mandating targets for storage adoption by 2030. Other states with similar policies are Oregon, Massachusetts, California and Maryland. Companies like Tesla also have been branding storage systems as clean technologies.

But do large storage systems lower emissions in our current grids? In a recent study, we found this isn’t necessarily the case – a reflection of how complex the electricity system can be.

The role of coal

Because storage can enable renewables to meet changing demand, we often assume the technology is inherently green – that is, by adding storage and renewables to the grid, we reduce greenhouse gas emissions. It’s similar to noticing that computers can provide education and productivity benefits, and then assuming that everything a person does on a computer is educational or productive. For both energy storage and computers, it depends on how you use it.

In the Midwest, we found that adding a storage capacity of 3 gigawatts, enough power to supply roughly 500,000 U.S. homes, raises carbon emissions an equivalent of adding 6,700 cars per year to the road.

In our analysis, we found that adding storage can, for some grids, increase carbon emissions. While counterintuitive at first glance, this result makes sense when one considers how electricity grids are operated. Broadly speaking, the entire U.S. grid is operated as a set of regional sub-grids that cover the U.S. like a patchwork quilt.

Energy storage has no smokestack emissions like coal or natural gas power plants. But new storage affects the operation of other power plants on the grid, resulting in an increase or a decrease in carbon emissions depending on the type of power plants supplying electricity for that region.

In most cases, storage systems in the U.S. operate to maximize profit. To do this, storage “buys low and sells high.” Electricity is typically cheap at night when demand is low, and more expensive in the daytime, especially when people are getting home from work and turning on a bunch of appliances. So storage system operators tend to buy at night and sell during the day. The net effect of storage on emissions thus depends on what kind of generators are used to meet new demand at night versus the day.

In grids with a lot of coal power – Midwestern, Western and Southern states rely heavily on coal – the coal plants are typically used to meet small changes in demand at night. Natural gas plants tend to work during the day to meet peak demand. In these electricity grids, storage tends to charge up with coal power at night, displacing natural gas power during the day.

Coal power is a dirtier source of electricity than natural gas, with about twice the carbon emissions for every unit of electricity produced. Therefore, in places where new storage means more coal and less natural gas generation, storage will increase total carbon emissions from the grid.

In the Midwest, we found that adding a storage capacity of 3 gigawatts, enough power to supply roughly 500,000 U.S. homes, raises carbon emissions an equivalent of adding 6,700 cars per year to the road. And as more storage is added, the carbon emissions increase.

While a national carbon tax does not look likely in the near future, there are others paths to ensuring green outcomes from storage

On the other hand, we found that in New York, a state with very little coal power, adding storage reduces carbon emissions. The Midwest is currently the dirtiest electricity grid in the U.S., and New York is one of the cleanest, so other regions would fall somewhere in between.

Not always easy being green

So, how can grid planners achieve the promise of a happy marriage between storage and renewables, assuming that they have to live in the same house with crusty old Uncle Coal?

One possibility is that, even with storage operating to maximize profit, adding enough wind and solar to the grid could counteract the effect of coal. With enough excess renewable energy, storage in any form – batteries or water reservoirs, for example – would preferentially use solar and wind because they are the cheapest sources when the supply of power exceeds the demand. Storage would still be shifting coal power from night to day, but enabling renewables more would be enough to make up for the extra emissions.

Storage will always help us to use more of our low-cost electricity sources. The question is whether that is coal, nuclear or renewables

We studied this and found that for the Midwest grid there is a turning point when wind and solar reach about 18 percent of total generating capacity: At that point, adding storage starts to decrease rather than increase emissions. The current adoption level is 10 percent, so it would take some time before storage in the Midwest reduces emissions.

Another option is to change how storage is operated. With a modest price on carbon, for example, the cost of different generators would shift so that storage charges less often from coal plants, reducing emissions even in the coal-heavy Midwest grid.

While a national carbon tax does not look likely in the near future, there are others paths to ensuring green outcomes from storage. For example, states can put in place policies that encourage more use of zero-carbon resources instead of coal.

Regardless, storage will always help us to use more of our low-cost electricity sources. The question is whether that is coal, nuclear or renewables.

Editor’s note

Eric Williams is Assocatiote Professor of Sustainability at Rochester Institute of Technology. Eric Hittinger is Assistant Professor of Public Policy at the same institute. Naga Srujana Goteti is a PhD Student in Energy and Sustainability at the same institute. This article was first published on The Conversation and is republished here with permission from the authors and publisher.