May 29, 2017
ENERGY WATCH #1 by Karel Beckman
Power markets of the future: this is where it’s at
May 29, 2017
If you want to get a superb overview of where we stand with the low-carbon transition in the electricity market, what the key bottlenecks are, and how we may get out of them, look no further than this great article by Michael Liebreich, founder and Chairman of Bloomberg New Energy Finance (BNEF), which he published last week. Highly recommended for you all strategic thinkers out there.
I will summarise the article for you, hoping to do justice to the original.
For years, Liebreich notes, “the most common question asked by outsiders of those in the clean energy industry was ‘when will renewable energy be grid-competitive’. Wind and solar needed subsidies in order to compete, and there was legitimate concern that as the sector scaled these would become unaffordable – as indeed they did in Spain, Italy and a number of other European countries”.
Today, however, renewable energy has become in many cases the cheapest option: “Forget grid competitiveness, this is the era of “base-cost renewables”, in which wind and solar are cheaper than any other source, and are therefore the default choice for new capacity.”
So does this mean we can now scrap all the subsidies and let the market do the work? Unfortunately, things ain’t that simple. And we all know why: renewables need to be integrated into the system and their functioning “therefore depends on the presence of other technologies – demand response, power storage, flexible fossil plants or interconnections with neighbouring systems. Someone has to build and run these, and they too must be able to earn their cost of capital.”
And so, writes Liebreich, “we are approaching a twilight zone in which, while large-scale renewable power itself no longer needs subsidies, it seems to need other technologies to be subsidized or offered protected markets in order to enable its continued growth.”
How are we going to solve this problem? At this moment, what is happing is that “we are careering down a path to more and more regulatory interventions. We are not talking about a broad national energy and resource plan: we are talking about demands for a particular mix of supply, particular technologies to keep the grid stable, particular new technologies to be piloted, particular levels of interconnection, particular programs of investment in energy efficiency and particular consumer prices – with guaranteed returns as rewards for compliance and the cost of mistakes borne by users.” No wonder that some, like the Labour Party in the UK, are suggesting simply to nationalise the industry again.
Liebreich astutely notes that the current conundrum provides a fertile ground for opponents of renewables to try to push back the transition. See, for example, the move by the Trump administration to demand a “review” of “critical issues central to protecting the long-term reliability of the electric grid”.
Although Trump’s “review” is clearly an attempt to undermine the renewables revolution, there is a legitimate question behind it: what should the future system look like? It’s a question that is currently widely discussed everywhere in the world, as Liebreich writes: “Everywhere I go, from Australia to Germany, New York to California to China, Brussels to Whitehall via Washington DC, there are two simultaneous discussions going on: the first, a technocratic one, about tweaks and modifications to the current regulatory system; the second, an existential one, about the nature of deep re-regulation required to meet the long-term challenge of the energy trilemma: providing cheap, clean, reliable power in the face of new technologies, new types of user behaviour and the all-encompassing need to address climate change.”
Liebreich admits that in this discussion, no one can claim to have all the answers, but he advances six “design principles” which he believes could form the basis of a future power market design:
- From dark spread and spark spread to firm spread
According to Liebreich, we should stop talking about “the wholesale power market”, because there are multiple markets with different characteristics. “The key to cheap, resilient, clean energy lies in the ability to put together the perfect portfolio of different types of power.”
One of the key issues is “to differentiate adequately between variable and dispatchable power…. what the power system requires is clearly-defined, separate markets for variable power and dispatchable power. Each must deliver price discovery across as much of the forward curve as possible – from a few minutes ahead at the short end, all the way up to 15 years and beyond at the long end. The delta between the variable and firm price is then the “Firm Spread” – the true value of dispatchability at key locations in that particular market – which should be as important for investment decisions as Spark Spread and Dark Spread are in making dispatch decisions.”
The way this would work: “Firm Spread will be very low in any market that has not yet saturated in terms of variable renewables, in other words where there is a lot of existing flexibility at little or no incremental cost… Firm Spread will rise rapidly in markets that are saturating, where there is so much solar and wind that the spot price for variable power is crashing to near-zero or even sub-zero at sunny/windy times, and where restricted operating hours drive the cost of flexible generators up. It can be expected to drop again over time, as technology innovation makes firming cheaper and the premium for firm power is reduced.”
- Toward a demand-led system
The second key design principle of the power market of the future is that “responsibility for matching supply and demand must be, to the greatest extent possible, placed on power retailers. It is they who best know their customers – not generators, not transmission or distribution system operators, and certainly not regulators or policy-makers.”
According to Liebreich, “Any approach that matches supply to a centrally-produced demand forecast will over-procure and result in excessive power prices. A power retailer can secure power in a variety of ways: building local or remote generation, buying it on the markets, signing long-term PPAs, aggregating it from customers or other consumers, investing in demand response capacity or storage, and so on. It is the retailer’s job to make sure that it secures enough to meet the demand of its customers at all times and locations. To do this at the lowest possible cost, it will want to combine a proportion of cheap variable power with more expensive flexible power; how it does so will be a core skill, in the same way that buying is a core skill in every other customer-facing industry in the history of business. The retailer will also have to ensure that it has options on enough spare capacity to meet unexpected demand spikes.”
As for transmission and distribution grid operators, “even if it is they that actually step in to procure power in the event of a spike in demand or shortfall in supply, the costs must end up with the guilty retailer or generator respectively”, notes Liebreich.
- Cleaning up: push fossil fuels out
Even with well-functioning markets, however, the penetration of variable renewables will stagnate at a certain point, notes Liebreich. As supply starts to overtake demand, spot prices will crash to zero. Then you will have “a kind of détente between cheap, clean variable renewable power, which is selling into those parts of the market which it can easily access, and fossil plants that are meeting the rest of the demand”.
At this point, renewables cannot grow any further, “until such time as renewable-power-plus-storage is cheaper than a fossil fuel peaking plant”, but Liebreich does not see this happening for decades.
You cannot “break this détente by applying more renewable energy subsidies”, notes Liebreich. What you need to do then is push fossil fuel capacity out of the market, e.g. through carbon pricing or other methods.
This of course depends on political will: “if there is no political will to use any of these approaches, the toolbox will be pretty much empty and the penetration of variable renewables, no matter how cheap they are, will more or less stall in that 20-40% zone.”
- Transmission and distribution grids
Then, “The regulatory regime of the future must include a mechanism by which this physical delivery system – otherwise known as the transmission and distribution grids – is paid for and made investable.”
The way to do this, according to Liebreich, is “for individual retailers to pay for the transmission and distribution capacity they use to deliver power, end-to-end, from generator to customer, including losses. As things stand, most power systems rely on approximations: costs are smeared in a nontransparent way across power users, and retailers are largely exempt from worrying about such issues as transmission or distribution bottlenecks. This has to change. There has to be a clear incentive to procure power locally and to use transmission links that are not congested.”
This will mean that “all power contracts need to be priced to reflect supply and delivery points, and settlement needs to include reservation and payment for transmission capacities from end to end.”
A complex matter, to be sure, “but this is exactly the sort of challenge for which the blockchain and smart contracts appear to have been designed.”
As variable renewable energy penetrates ever more deeply into power systems, “the value of interconnection with neighbouring systems will increase exponentially”, notes Liebreich.
The “wider the connected area, the less investment will be needed, and the lower the power costs will be for a given level of reliability and emissions.”
Again, it “must be the power retailers who procure imports”, argues Liebreich, with two conditions. “First, importing retailers must pay to use interconnections, in exactly the same way as they pay for domestic transmission capacity … Second, any imported power must be accompanied by a certificate of origin, proving that it complies with any carbon limits.”
- Data ubiquity
Finally, Liebreich notes that this power system of the future can only be delivered “a fully digital system. The sixth and final principle for any future power sector regulatory regime must be to enable the creation, aggregation, storage, analysis, sharing and protection of data on a scale unthinkable today.”
The implications of this data revolution for the power market are enormous: “Every asset will be sensor-equipped, software controlled and in communication with other assets. The bulk of decisions will be taken by bots and algorithms distributed within the network, the rest by cloud-based big data analytics. Machine learning will be everywhere, and human intervention will have been banished to the design level. We had better get this right!”
The risks of course will be enormous too, Liebreich acknowledges.
Whether or not the electricity system will be able to make such a complex and risky transition as sketched by Liebreich, no one can tell. What is missing for me in his overview is a future of radical decentralisation – at least as an option. But his vision certainly gets down to what the electricity market debate is all about.
ENERGY WATCH #2 by Karel Beckman
Power markets in crisis
May 29, 2017
The relevance of Michael Liebreich’s analysis can be seen in headlines every day about the various “crises” our power markets are finding themselves confronted with.
Australia is a case in point. “Energy market in crisis: we need a plan, and new rules”, write researchers Tony Wood and David Blowers of the Grattan Institute in Australia in a new report. “Increasing prices for electricity have coincided with increasing concerns over whether the grid will break and whether there will be enough generation in future.”
They note that “Governments have responded with an escalating number of reviews and several disconnected and uncoordinated announcements. These may score political points but, in the absence of an integrated, national approach, could also make things worse. The risk is that these pressures will destroy the NEM’s [National Energy Market] capacity to be both an efficient spot market and drive the new investment and divestment decisions that Australia needs for low-cost, reliable and low- emissions electricity.”
If that happens, they write, “political posturing and blame shifting will mean that the NEM will be judged to have failed, when in fact it will have surely been systematically, if unintentionally, destroyed.
Continuing uncertainty, especially a lack of credible climate change policy, could prompt further government interventions in the energy market. Cascading government interventions would likely lead to a regulated, centrally-planned approach where investment risk and costs are transferred to consumers, prices are higher than necessary, security of supply is dependent on imperfect forecasts, and emissions reduction targets may still not be achieved.”
To avoid this doomsday scenario, “First, policy makers need to address immediate concerns. Urgent action is needed to stabilise a physical system with increasing levels of wind and solar. This responsibility rests with the rule-maker and the market operator…. Power generators should be rewarded for being flexible and responding quickly. And more consumers should be offered a financial incentive to reduce their demand at peak times, thereby reducing pressure on the system.”
“Second, governments need to agree on a credible emissions reduction policy that integrates with the NEM. This should be the central result of the Federal Government’s 2017 climate change policy review.”
As Reneweconomy reports, the Australian Energy Market Operator (AEMO) and the Australian Renewable Energy Agency have also issued a plea “for changes to market rules, changes which many in the industry say have been stalled under the current market rule maker. The new AEMO chief executive Audrey Zibelman says Australia used to have low energy prices, but had obviously lost that status. ‘The question is, how do we use the resources we have to get back to that level of affordability?’ she told a parliamentary inquiry in Canberra.”
“The answer was with new technologies like battery storage and demand management, a new set of market rules. ‘What we need is to think how to get these opportunities into the market. We are operating 20th Century power system trying to keep pace with 21st Century change,’ Zibelman said…. In its submission to the parliamentary inquiry into a modern electricity system, AEMO said that Australia’s rule making was not sufficiently forward-looking to meet the needs of the ‘paradigm shifts’ the National Electricity Market was undergoing.”
Incidentally, Reneweconomy also notes that AEMO is receiving “a phenomenal number of applications for new wind and solar projects across Australia, with the number of projects jumping 50 fold in recent months.” The opportunity for the transition is there, in other words – if Australia can fix its integration problem.
In the United States, the same debate is raging across the country. The new U.S. Secretary of Energy Rick Perry has ordered a study “to assess the effect of renewable energy policies on nuclear and coal-fired power plants.”
For most observers, this “study” must be viewed as an attempt by the Trump administration to thwart the expansion of renewable energy. But researchers from the University of Texas have taken the Administration up on its question. They have written a fascinating article showing that we already have the answer. Ironically, it can be found in Texas, where under Perry’s governorship an advanced market design has been developed to integrate the State’s large amounts of renewable energy.
The researchers describe in detail how the Texas market design works and where it leads to: “a combination of wind and solar with fast-ramping natural gas, smart market designs and integrated load control systems will lead to a cleaner, cheaper, more reliable grid.”
In Europe, Germany is at the heart of the electricity market transition crisis, caught as it is between Energiewende and coal power interests.
According to the latest figures from AG Energiebilanzen – an institute that “evaluates and assesses the existing statistics from all sectors of the energy industry from a scientific perspective, regularly prepares an energy balance on behalf of the Federal Republic of Germany every year, and makes this energy balance available to the public” – German gas use rose in the first quarter by 1%, coal use by 2.6% and brown coal (lignite) use by 0.4%. And this despite a decline in primary energy consumption of 1.4%.
The main reason for the increase in coal and gas use, according to Energibilanzen, was “to compensate for the fluctuating power delivery from solar and wind and the decline in nuclear power”.
These statistics show up the key weaknesses of the Energiewende and the problem that Germany is up against.
Revealingly, Germany sided with a number of East European countries recently in an attempt to block stiffer EU pollution limits on coal and lignite power, as Gerard Wynn reports on his Energy and Carbon blog.
Wynn notes that “Germany’s annual carbon emissions are unchanged since 2009, after steady reductions the previous two decades. And the country’s lignite consumption has been flat for more than decade. Official estimates show consumption in 2015 was 1.6 million terajoules, the same as in 2005. Meanwhile, the country spends €10-11 billion annually on solar power.”
Germany sided with Poland, Czech Republic, Slovakia, Hungary, Romania, Bulgaria and Finland recently in opposing tougher SOx and NOx limits for power plants. In the end, writes Wynn, the “new limits – called the revised BREF (“best available techniques reference document”) – were still approved, by a wafer-thin EU majority”:
Nonetheless, EU rules are having an effect. Enel for example recently announced the closure of two coal-fired power plants operated by its subsidiary Endesa in Spain. Enel’s CEO Francesco Starace said recently at the company’s shareholders meeting that “within 10-15 years Enel will no longer have any coal power plants”.
In a recent report, IEEFA (Institute for Energy Economics and Financial Analysis), which analyses the impact of the BREF rules on Europe’s coal-power plants, identifies 108 plants that are “low-hanging fruit” in terms of emission reductions.
NGO Can Europe announced last week that Vattenfall is closing its small 188 MW Klingenberg lignite plant in Berlin. The plant will not be replaced by another coal plant, as was originally planned, but by a gas-fired CHP plant.
In November 2016, the then newly elected Berlin-state coalition government pledged to become coal-free by 2030, although CAN and other groups say that Berlin needs a significantly earlier phase-out date. The city will have three coal power plants left after Klingenberg closes.
The closure of Klingenberg marks the 12th coal plant in Europe to come offline since January 2016, according to CAN.
One key element for the future of Europe’s power market (which comes under Michael Liebreich’s point 3, above: “policymakers need to push out fossil fuels”) is the EU Emission Trading System (ETS). There Despite planned reforms, there is no sign yet that the faltering ETS will be “fixed” any time soon.
Reuters reported last week that “participants in Europe’s carbon market, including utilities, trading houses and banks” have lowered their expectations for carbon prices in the period 2021-2030. “Average carbon prices are likely to be almost 9 percent lower than forecast last year, a survey of 135 companies published by the International Emissions Trading Association (IETA) on Wednesday showed.”
“Once again IETA members have highlighted the yawning gap between current prices and what’s needed to achieve the Paris objectives,” Jonathan Grant, a director at PwC which carried out the survey, said in a statement.
Respondents anticipate an average EU carbon price of €16.28 per ton in the fourth phase of the ETS, which runs from 2021 to 2030, some €1.55 below expectations made for the phase last year.
This is far less than the €40 that respondents said last year is needed to help incentivise investments to help the bloc meet goals set under the Paris Agreement.
ENERGY WATCH #3 by Karel Beckman
Paris Agreement: this is where it’s at
May 29, 2017
While the Trump administration is still pondering whether or not to stay in “Paris” or not (and the other 6 of the G7 countries clearly reaffirmed their commitment to the Paris Agreement), you may wonder where the Paris process currently stands.
In the first half of May, diplomats from around the world gathered in Bonn for talks which take place every year midway between two sessions of the annual Conference of the Parties (COP). The website Carbon Brief has a detailed report on the “key outcomes” of this session.
What is at stake is agreement on a “rulebook” on how to implement the Paris Agreement (“who should do what, by when, how and with what financial support”), which must be finalized at COP24 in 2018. The 24th Conference of the Parties will be held – for the third time – in Poland. COP23, in November 2017, will also be held in Europe, in Bonn, where the headquarters of the UNFCCC (the U.N. organisation responsible for the climate agreement) are located.
According to Carbon Brief, discussions in Bonn went ahead relatively smoothly, despite U.S. resistance. The talks were “marked by a determination to make progress”.
Negotiators agreed on “a series of stepping stones towards COP23”. “Under each topic, parties are invited to submit their views during September 2017. These views will be collected together in another series of papers, with the aim of setting out options for draft text on the rulebook, as well as areas of agreement and disagreement.”
Negotiators will then reconvene at a series of roundtable workshops, held in early November in advance of COP23 in Bonn. “In keeping with the tradition of UN climate talks”, writes Carbon Brief, “negotiations operate under a set of jargon-filled titles and descriptions. The rulebook negotiating track is called the Ad-hoc Working Group on the Paris Agreement, or APA.
The work of the APA continues according to an agreed agenda, with working groups for each agenda item.”
These include: “agenda item 3” on the contents of and accounting for nationally determined contributions (NDCs); “agenda item 4” on how parties should communicate their adaptation efforts; “agenda item 5” on how parties will transparently report on action they take and on support they give to others; “agenda item 6” on a global stock-take in 2023, where collective progress towards the Paris targets will be checked; and “agenda item 7” on how compliance with the Paris Agreement will be monitored. Agenda item 8 covers other business, including the Adaptation Fund.
One key issue of disagreement, notes Carbon Brief, “is the scope of the process and what progress will be assessed against – for instance how do you measure global progress towards the adaptation goal of the Paris Agreement.”
“Even for [the] mitigation long-term target, there will be different understandings, let alone other areas,” Naoyuki Yamagishi, a climate and energy leader with WWF Japan, tells Carbon Brief.
However, Yamagishi – who has been involved in the process for 14 years – says he “wouldn’t be so easily disappointed”. He says: “It would have been, of course, great if we already had an agreed headings and subheading of the global stocktake part of the rulebook. However, if you listen to the discussion in the informal meetings during the session, you could see that issues to be resolved are getting clearer and [there was] some level of convergence, which I would describe slow but important progress.”
Another process established by the Paris Agreement was the “enhanced transparency framework”, which aims to “build mutual trust and confidence and to promote effective implementation” by formalising the ways countries report and review their own progress, as well as the support they have provided to others.
This framework is scheduled to be completed by the end of COP24 in 2018, meaning a draft text is needed by this year’s COP23 in November to ensure there is enough time for negotiations over it to take place.
A key topic of negotiation is the promise of developed countries made in 2009 to jointly “mobilise” $100bn per year by 2020 to help developing countries mitigate and adapt to climate change. The Paris Agreement reaffirmed the importance of this climate finance promise. Negotiations on this section of the Paris rulebook, taking place under the transparency heading, are focused on how to account for and track the climate finance that countries have given or received.
A related area of contention is the future of the Adaptation Fund, a (relatively small) pot of money created in 2001 as part of the Kyoto Protocol, which provides grants to vulnerable countries to adapt to the impacts of climate change.
Another issue on the agenda in Bonn was Article 6 of the Paris Agreement, which covers market mechanisms, and could provide a route to the creation of global carbon markets. However, despite devoting significant time to discussions, progress was slow. David Hone, chief climate adviser to Shell, an expert on this topic, told Carbon Brief: “[Views] range from a reincarnation of the CDM [UN Clean Development Mechanism, which supported carbon offsets for use under the Kyoto Protocol] through to a large scale mechanism to help countries develop carbon pricing. It will likely have to incorporate a broad spectrum of approaches, with perhaps more emphasis on projects in the near term and operation on a much larger scale in the medium to longer term.”
Jonathan Grant, a director at PWC told Carbon Brief: “Countries are still in brainstorming mode – the draft outputs from the carbon markets discussions are simply long lists of issues.”
For those readers who follow the big macro-economic energy lines, Carbon Brief also had an interesting report recently on the implications of Donald Trump’s budget for climate change and energy activities. Carbon Brief is a UK-based website that has significant resources thanks to funding from the European Climate Foundation.
ENERGY WATCH #4 by Karel Beckman
Electric Vehicles: “cost parity in 2018”
May 29, 2017
Analysts at UBS conclude in a new report that the “total cost of consumer ownership [of electric cars] can reach parity with combustion engines from 2018.” (The news was widely reported in the media, e.g. in the Financial Times and Daily Telegraph, although we were unable to find the original report.)
UBS apparently has an “evidence lab” that does some truly original research: the analysts tore apart a Chevy Bolt to see how it is put together. After deconstructing what they called “the world’s first mass-market EV, with a range of more than 200 miles,” UBS called the electric car the “most disruptive car category since the Model T Ford.”
The UBS team found that the powertrain for the Bolt was $4,600 cheaper to produce than originally thought, “with much cost reduction potential left.”
Note that the comparison is for total costs of ownership, including maintenance, cost of fuel, insurance, and so on, not the purchase price.
At this moment, GM is losing money on every Bolt they sell, UBS said. “We estimate that GM loses $7,400 in earnings before interest and tax on every Bolt sold today, mainly due to a lack of scale.”
They also believe Tesla will lose $2,800 on entry-level versions of its soon to be introduced Model 3 but think customers will opt for extra cost options that will raise the average selling price to $41,000 — $6,000 more than the base price. Tesla will be able to break even at that price, they believe.
Overall, the UBS analysts believe automakers will start earning a profit of about 5% on electric cars by 2023 as the switch over from conventional cars to electrics gathers momentum. “Once total cost of ownership parity is reached, mass-brand EVs should also turn profitable.”
Its findings led UBS to issue a warning for companies that make replacement parts, since electric car drivetrains are more reliable than those that feature internal combustion engines. A gasoline engine has over 1,000 moving parts, an electric motor has 3.
Add in the increasingly complex automatic transmissions in use today and there are a lot of things that require fixing as a conventional car ages. “Our detailed analysis of moving and wearing parts has shown that the highly lucrative spare parts business should shrink by 60% in the end-game of a 100% EV world, which is decades away,” UBS said.
UBS also said that it expects Europe to lead the rest of the world in adoption of electric vehicles. Whether that is true or not, Europe is starting to build its own battery “gigafactories”, Bloomberg reports – although perhaps gigafactories is a bit exaggerated.
Bloomberg refers to Daimler’s €500 million plant 130 kilometres south of Berlin that was inaugurated by Chancellor Merkel recently and that will produce lithium-ion storage units for cars and homes. This would be the biggest factory yet in Europe, according to Bloomberg, although still quite small compared to the $5 billion gigafactory Tesla built in Nevada with Panasonic. For now, Asian producers like LG and Samsung are the largest battery producers in the world. Tesla is aiming to build four more gigafactories, including one in the state of New York.
In Sweden startup NorthVolt has plans to build a €4 billion battery factory, which should be ready in 2023.