May 22, 2018
ENERGY WATCH #1 by Karel Beckman
Is Europe on the verge of blackouts?
May 22, 2018
Europe is facing power generation capacity shortages and may even risk blackouts without additional use of natural gas, Tor Martin Anfinnsen, senior vice president for marketing and trading at Statoil, said at a conference in Amsterdam on 15 May, according to a report on Bloomberg.
“A severe shortage in generation capacity is expected in the U.K., Germany, and Belgium,”, Anfinsen said. Those countries are phasing out or cutting coal-generation fleet and Germany and Belgium are also turning away from nuclear power, notes Bloomberg.
“If you have a dangerous bend in the road and everyone knows there is a dangerous bend but nothing is done with it unless there is an accident in the road,” Anfinnsen said. “Is that what we will see in Europe in power generation as well? Will we have to see blackouts before you see a change in policies? That remains to be seen but we are getting dangerously close in many markets.”
“It is very difficult to see that there is any other way of fixing that up to 2030 by other means than increasing gas-fired power generation,” Anfinnsen said. “Not only through higher utilization of existing capacity but also adding new gas-based generation.”
But this of course gets us into another problem: a higher dependence on Russia. Bloomberg notes that “Demand for gas was so high during the cold snaps of late winter and on March 1, that it was nearing the limit of supply. If it hadn’t been for high wind generation at the same time that helped meet demand, the situation would have been much different.”
Nor is this problem about to go away. Andree Stracke, Chief Commercial Officer of RWE, said at the same conference that gas is “suddenly competitive again” because EU carbon allowances rose above 14 euros a ton and coal prices are at about $80 a ton.
Phaseout of nuclear power generation and reduction in coal generation will also help “push gas into business,” he said.
More on the problems in the European gas market below.
First let’s ask: how likely are power shortages? Anfinnsen apparently did not give numbers, but his story is confirmed by a recent report from the Germany energy industry association BDEW, which we covered on Energy Post Weekly on 1 May.
The BDEW has calculated that if nothing is done German generation capacity will shrink from 90,000 MW today to 75,300 GW by 2023. According to the regulator, the Bundesnetzagentur, the country needs a peak load of some 81,800 MW in the early 2020s. It has put 6,800 MW of capacity in a special power reserve. In other words, just enough.
But this means that it will not be possible to close any additional coal-fired power stations in the 2020s, the BDEW warned. The problem is that additional closures are needed if Germany is to reach its 2030 climate targets.
The new Merkel government has set up a commission to study the phaseout of coal fired power stations in Germany. It is expected to come with an advice next year, but last week a first strategy paper was produced by this commission, seen by Spiegel Online. This paper seems to indicate that the coal commission “will put the economy first” and the climate second.
As Clean Energy Wire reported, the paper’s first sentence reads: “Federal government policy aims to create full employment and comparable living standards in all of Germany.”
The document acknowledges Germany’s pledge to become “largely greenhouse gas-neutral” by 2050 and confirms the government’s 2030 target of reducing emission by 55 percent compared to 1990. But it says climate action must be “harmonised” with economic development and social considerations. First reported on by Spiegel Online, the paper says growth and employment in affected regions must be supported by a fund to minimise the impact of the coal exit and other structural changes associated with the country’s Climate Action Plan. It says a first report on the economic perspectives of lignite mining regions will be compiled by October and the final recommendations ready by the end of 2018.
Another confirmation of the growing pressures on the power generation capacity comes, indirectly, from a near-blackout that happened in the Netherlands on 30 April. This was not widely reported on outside the country, but according to Dutch media reports a disaster was only narrowly avoided.
Tennet, the Dutch TSO, had to send out an international alarm after it turned out that Dutch energy suppliers had contracted too little capacity. They were caught out by unexpectedly low wind and solar output. Tennet first called on its emergency reserves, but they quickly ran out. The grid operator was only just able to obtain supplies from abroad to make up the deficit.
This anecdote does not prove of course that there is a structural shortage of power in the Netherlands, but it is symptomatic of the way the power market is moving. There is hardly any investment in conventional power production anymore, old plants are being closed, and renewable energy will increasingly have to make up the deficit. But will it?
In the U.S. similar problems are emerging. Bloomberg reports that “more than a quarter of U.S. nuclear power plants don’t make enough money to cover their operating costs, raising the threat of more early retirements. Of the 66 nuclear power plants operating in the U.S., 24 are either scheduled to close or probably won’t make money through 2021, according to Nicholas Steckler, an analyst with Bloomberg New Energy Finance. These at-risk sites have total generating capacity of 32.5 gigawatts, more than a quarter of the entire fleet, Steckler wrote in a report Tuesday.”
It would cost about $1.3 billion a year to plug the revenue gaps for these struggling sites, Steckler and co-author Chris Gadomski said in the report. The study follows a similar analysis in March that showed that half of U.S. coal-fired power plant capacity is on shaky ground.
“The industry is increasingly challenged by sluggish power demand, cheap natural gas and the rise of renewable energy — especially in the Midwest where wind power is ascendant”, notes Bloomberg.
Policymakers in the U.S. are beginning to take action to save nuclear power (and in some cases also coal power). “The industry has had success convincing policy makers in New York, Illinois and New Jersey to take steps toward bailing out struggling plants thanks to their emissions-free generation and concerns about job losses. And the U.S. Energy Department is currently weighing a March request from FirstEnergy Corp.’s competitive power unit for government aid to help keep money-losing nuclear and coal-fired power plants online,” notes Bloomberg.
The Atlantic Council Global Energy Center launched a bipartisan “Task Force on US Nuclear Energy Leadership”, to be led Republican Senator Mike Crapo and Democratic Senator Sheldon Whitehouse.
“There is strong bipartisan agreement in Congress that nuclear energy is a reliable, safe, clean and efficient part of our national energy portfolio. This collaborative initiative will drive that message,” said Crapo. “It also builds on legislation Senator Whitehouse and I have advanced lifting barriers to innovation and collaboration in nuclear generation research and development.”
For the Atlantic Council, a bipartisan foreign policy think tank, maintenance of the U.S. nuclear energy industry is also a geopolitical issue. “The Task Force will explore nuclear energy as a key pillar within the energy security, foreign policy, and economic priorities of the United States, and identify challenges and solutions to continued US nuclear power leadership. It will include leading experts from industry, academia, and government to discuss key issues, including sustaining the current nuclear fleet; facilitating research and development in pursuit of innovation; commercialization and exports; and enrichment and fuel cycle issues…”
The Task Force will build on previous work by the Global Energy Center, including the March 2018 Issue Brief, US Nuclear-Power Leadership and the Chinese and Russian Challenge, which argues that “US global leadership and engagement in nuclear power are vital to US national security and foreign policy interests.”
In Europe no comparative efforts are being made to maintain nuclear energy capacity. The EU actually cannot undertake a pro-nuclear policy, because there are too many Member States that are opposed to nuclear.
Some European countries are building new nuclear power plants, notably Finland, Hungary and the UK. The UK has the most ambitious nuclear programme of all countries in Europe. At least on paper. Which of the many planned projects will actually materialize is still uncertain.
Greenpeace-website Unearthed recently published a good overview of where things stand in UK nuclear. First there is Hinkley Point C of course, the 3.2 GW plant that EDF has started construction on and that now does seem to be happening.
After Hinkley first up there’s Moorside – planned near the existing Sellafield site in Cumbria. It was due to be built by the Toshiba-Engie joint venture Nugen, Unearthed notes, “but the project fell apart last year. First Engie made an exit in April and then there was the near-complete collapse of Toshiba’s business, a disaster blamed on the company’s poorly performing nuclear arm Westinghouse.”
Moorside may be rescued by Korean company Kepco, “but it will likely be delivered years later than its planned 2025 start date since Kepco’s reactor design hasn’t yet been cleared by UK authorities.”
Further down the line “there are the two new nuclear projects that are part of the Hinkley package. As per that agreement, EDF is set to build reactors at Sizewell in Suffolk while Chinese firm CGN (EDF’s partner on Hinkley) will lead at the Bradwell site in Essex.”
Last month EDF’s boss Simone Rossi told The Times that “maybe [Sizewell] is not feasible” and “said the company could walk away unless it gets a generous funding deal from the government. Meanwhile controversy over China’s involvement in Bradwell echoes the same tensions that nearly derailed Hinkley in the first place.”
But the project “everyone’s talking about right now is Hitachi’s Wylfa project, planned for the island of Anglesey in Wales.”
Hitachi “is looking for significant support from the British government, from loan guarantees all the way down to a direct government stake. With construction costs on the project ballooning, they were reportedly spooked by what happened to Toshiba.”
“In addition to a significant strike price (which might be less than what Hinkley got), Hitachi wants the UK taxpayer to alleviate risk from building the project by underwriting up to £20 billion worth of loans.
There have even been reports that Hitachi is demanding that the government take a direct stake in the project and stump up a third of its costs — the firm has reportedly threatened ditch the deal if that doesn’t happen.”
“If it goes forward, that arrangement could mean the entire cost of the project ‘lands on the government’s balance sheet’ even if it only takes a minority stake, according to the Sunday Times.”
The British government is “playing down” the media reports. “And we’re still awaiting news about a possible urgent debate on the matter in parliament.”
Unearthed concludes that “the British government is betting big on new nuclear which is leading to brinkmanship with the companies it’s dealing with, Hitachi in particular.”
This account was confirmed on Friday (18 May) when Reuters reported that “The British government has offered 2 trillion yen ($18 billion)in financial support to a unit of Japan’s Hitachi to build nuclear reactors in Wales,” according to Japanese news agency Kyodo News.
It will be interesting to see how much new nuclear power the UK will be able to develop in the coming years.
One thing is clear: if the world takes climate change seriously (a big if), the threat of power generation shortages is not about to go away. On the contrary: a new study from researchers at the Oxford Martin School at the University of Oxford has warned that a fifth of current global power plant capacity is at risk of becoming stranded assets under a scenario in which the planet reaches its climate goals of halting warming at 1.5 to 2°C above pre-industrial levels, reports Cleantechnica.
Published in the journal Environmental Research Letters, the open access article — Committed emissions from existing and planned power plants and asset stranding required to meet the Paris Agreement — was written by Alexander Pfeiffer, Cameron Hepburn, Adrien Vogt-Schilb, and Ben Caldecott, from the Oxford Martin School at the University of Oxford.
“The researchers explain that future CO2 emissions from coal and gas power plants already in operation will overshoot the target of the Paris Climate Agreement to stabilize temperatures at 1.5 to 2°C above pre-industrial levels by a whopping 60 gigatons of CO2”, notes Cleantechnica.
“Unfortunately, as the authors also point out, over the coming decade the power sector is expected to invest around $7.2 trillion in power plants and grids around the world, which will result in a further 270 gigatons of CO2 emissions, according to the Oxford researchers.”
“Existing power plant stock, if operated until the end of its useful life, would emit around 300 gigatons of CO2, which exceeds the 240 gigatons we can afford if we are to meet our climate goals,” said lead author Alexander Pfeiffer of the Oxford Martin Programme on Integrating Renewable Energy. “Any investment made today in CO2-emitting infrastructure is going to have a considerable effect on humanity’s ability to achieve the ambitions of the Paris climate agreement.”
“In the end, even if the entire pipeline of planned power plants was cancelled, around 20% of the current global capacity of power plants would still become stranded in order to meet the climate goals of the Paris Climate Agreement.”
“Companies and investors need urgently to reassess their investments in fossil-fuel power plants, and government policies need to be strengthened to avoid further carbon lock-in,” Pfeiffer said.
“Specifically, the number of coal plants under construction or in planning in early 2017 (according to the study’s data) were responsible for 77.5% of the total cumulative CO2 emissions. Of the 270.8 gigatons of CO2 (GtCO2) planned over the next decade, 210 GtCO2 is attributed to coal projects — and 162.4 GtCO2 is expected to be built in Asia.”
“To tackle anthropogenic climate change we need to halt the construction of fossil fuel power generation and immediately begin the dismantling of coal-fired power stations,” explained Ben Caldecott, Director of the Oxford Sustainable Finance Programme at the University of Oxford and co-author of the study. “New coal, let alone existing coal, is entirely incompatible with the Paris Climate Change Agreement.”
“The analysis shows we are already in a serious dilemma,” added Professor Cameron Hepburn, Director of the Economics of Sustainability Programme at the University of Oxford and co-author of the study. “We must choose between scrapping functioning equipment, capturing the carbon pollution, deploying expensive negative emissions technologies, or abandoning agreed climate goals. Adding new coal makes navigating between the devil and the deep blue sea even harder. ”
Even if, however, we begin deploying significant levels of carbon capture storage and negative emissions technologies, the authors explain that we will still be stranding significant levels of assets, and that building more fossil fuel power plants over the next decade will only increase that number.
“Emissions are going to have to decrease rapidly if climate targets are to be met,” Pfeiffer added. “But the current substantial plans for new fossil-fuel powered generators suggests the risk of asset stranding isn’t being sufficiently considered. This is likely to prove extremely costly in the long-run, to both the industry and its investors.”
ENERGY WATCH #2 by Karel Beckman
The emerging trend of hybrid systems: renewables are coming of age (and other ways to combat power shortages)
May 22, 2018
It’s not that nothing can be done to combat looming power shortages. In fact, as the study from the University of Oxford makes clear, it is inevitable that we need to develop alternatives for conventional power plants if we are to make progress on climate targets.
One of the alternatives with significant potential is offshore wind , which is already growing rapidly in Europe. The U.S. is about to follow the European example, according to an article on the Conversation, in which Matthew Lackner and Erin Baker of the University of Massachusetts Amherst describe “Why the offshore wind industry is about to take off”.
They note that there are only five wind turbines operating in U.S. waters today. “But that will likely soon change, partly because of states with ambitious offshore wind targets.”
The biggest momentum, they write, is coming from market forces, which have improved. “The cost of generating electricity through wind off the coast of Europe, the one region where the industry has gained critical mass, has decreased sharply.”
The authors note that “in 2010, electricity generated through offshore wind off the European coastline cost around 17 cents per kilowatt hour, more than twice what utilities were paying for power derived from burning gas and coal. The price fell to around 13 cents by 2017. But when Germany and the Netherlands recently awarded some of the first unsubsidized offshore wind contracts, bids had fallen to as little as 6 cents.”
In the U.S, “the Trump administration (!) is approving new leases for offshore wind development. And the industry is gaining state-level support, especially in an East Coast corridor that runs as far south as North Carolina.” Massachusetts aims to install at least 1,600 megawatts of offshore wind, New York 2,400 megawatts, New Jersey 3,500-megawatt by 2030.
Maryland, Virginia, Rhode Island, North Carolina and Delaware are also moving forward, with federally approved leases to develop offshore windfarms. “The 600,000 jobs the Energy Department predicts that onshore and offshore wind energy will create by 2050 help explain their interest”, the authors note.
Hawaii also “plans to rely heavily on offshore wind as part of its goal of getting all its power from renewable sources by 2045”, but like states on the West Coast, it “has not gotten federal approval yet for any leases”.
Nevertheless, despite all these plans, the U.S. Energy Department projects that 86 GW of offshore wind will be installed by 2050, which is a sizable amount, but still only 7% of the capacity of today’s grid and “only 4% of the vast potential” offered by offshore wind, the authors note. The two researchers believe that the actual amount of offshore wind that will be built in the U.S. could well be bigger than that.
In Australia – which has a very climate-conservative government – it is private companies that are taking the lead in securing alternative supplies of energy.
“Renewable energy production from Australian businesses has more than doubled over the last two years, and nearly half are making the switch to wind and/or solar to take control over their electricity bills and to help reduce emissions”, writes Giles Parkinson on Reneweconomy.com.
A new survey from the Climate Council says the massive shift to wind and solar is happening because electricity bills are soaring and wind and solar and storage offer an affordable and reliable solution, writes Parkinson.
Many companies “are looking for those technologies to provide the bulk of their power needs, and they are also looking at storage and electric vehicles.”
“This report shows that the rising cost of energy is the number one concern for Australian businesses over the next decade,” says the Climate Council’s Greg Bourne, a former chair of the Australian Renewable Energy Agency.
“The role of corporations is expected to be one of the key factors in the future of large-scale and distributed renewable energy projects over the coming decade, particularly if the federal government fails to lift its emissions reduction targets for 2030”, notes Parkinson.
“Right now, the government is seeking to lock in a 26 per cent cut in electricity emissions from 2005 levels by 2030, through its National Energy Guarantee. But most independent analysis say this target will be largely met by the renewable energy target by 2020 – meaning little incentive for further construction in the following 10 years.”
“That leaves only state-based targets such as Victoria, Queensland, and the Northern Territory, and the underlying push from households and businesses turning to renewables and storage to address their electricity bills.”
A total of 46,000 Australian businesses have already installed solar energy, and this has mostly been in relatively small-scale rooftop arrays, although the pace of this uptake has accelerated dramatically in the last 12-18 months, as the graph below illustrates.
According to the Clean Energy Regulator, the amount of rooftop solar installed by businesses (arrays of up to 1MW) will increase fivefold in 2018 to around 100MW.
“The other more recent phenomenon is the decision by very large businesses and energy users to turn to large-scale wind and solar projects to lower their bills in response to the doubling of electricity prices and soaring gas bills”, notes Parkinson. “One-third of businesses said they were considering using renewables as their main source of energy in the next 18 months – that’s a big development from businesses putting on small amounts of rooftop solar to support their green messaging.”
And there are even larger things afoot. The next renewable energy revolution is about to break out. It’s called: hybrid systems.
To some extent you could say that up to now renewable energy has not really been regarded as a fully mature option as yet, neither by the utilities nor by policymakers and analysts. You could say that solar and wind are still looked upon as the young cousins of the family. Full of life, to be sure, enthusiastic, showing great potential – but not with the same wisdom and experience of the grown-ups.
That’s of course because they don’t supply a full-fledged 24/7 power solution. For all their great work, they are still only complementary. Conventional power generation is often described a bit denigratingly as “back-up”, but where would the family be without the back-up of the patriarchs that hold the purse strings?
However, all this is about to change. The cousins are about to take charge and push their elders into the nursing home for good. The reason is the advance of hybrid systems that combine various forms of renewable energy with storage capacity.
In an important article on the renewable energy news website Recharge – Why hybrids are key to renewables’ future – editor Darius Snieckes describes the trend that is emerging across the power sector globally: the development of ‘hybrid’ renewables systems that provide some combination of wind, solar, geothermal and battery storage and that are able to deliver power permanently without backup.
And there is another trend that goes with this: the companies that deliver these systems are more and more turning into suppliers of full-scale energy solutions rather than simple power producers.
“The flagship next-generation projects being developed by companies such as Enel, Vestas, Siemens and GE may be pilots, but the prospects are huge”, notes Snieckes. “Analyst group Wood Mackenzie forecasts as much as 35GW of renewables-plus-storage installations being built by the end of 2021 alone, driven by the promise of ‘ resource complementarity’, greater plant efficiency and the tantalising economics of being better able to ‘match production to consumption or remuneration’.”
One example is Italian renewables giant Enel Green Power (EGP), “which has been exploring hybridisation for more than five years, via projects including the 91MW Fontes wind/solar plant in Brazil, the 35MW Stillwater geothermal/CSP/PV development in the US and, most recently, the 48MW Cerro Pabellón project in Chile, which knits together a geothermal installation with PV panels, a 132kWh lithium-ion (Li-ion) battery and a 450kWh hydrogen storage system.”
“The idea was born from financial considerations for us. How do we use the components of a power plant and its infrastructure that is not used all the time — renewable energy production is variable, of course — better?” Fabrizio Bizzarri, head of solar innovation at EGP, tells Recharge. “So, with PV, for example, for example, doing better than 25% availability, or with wind, 50%. By putting the two together on Fontes, we achieved a much higher availability, around 80%. This means we can much better match production with load over a 24-hour period.”
“The increased delivery of power during peak hours enables a more load-following production profile,” Bizzari notes. “At the same time, sharing existing process and generation equipment, as well as infrastructure, enables cost-savings per unit of energy produced and delivered.”
Another “early-mover in the hybrid space has been Danish turbine maker Vestas, which is in the throes of a strategic reinvention from a pure-play wind OEM into what chief executive Anders Runevad calls a ‘sustainable energy solutions’ company.”
In 2012 Vestas already built the 12MW Lem Kær wind/battery pilot project in Denmark and the Louzes hybrid plant in Greece, which combines 24MW of wind with 1MW of PV.
But, writes Snieckes, it is Vestas’ 60.2MW Kennedy Energy Park phase 1 development in Australia — the world’s first utility-scale wind, solar and battery storage project — “that aims to take the hybrid model to the next level when it comes into operation at the end of this year.”
“Hybrids are not solely about the cutting-edge technology: the promise is advancement of the energy transition in a way that is flexible and customer-centred insofar as if the economics work then the progress of renewables will be more certain”, says Vestas’s senior vice president of product management Johnny Thomsen.
Thomsen describes the Kennedy project as “a first proof of utlity-scale, grid-connected hybrid renewable energy production using integrated wind, PV and storage assets, while complying to grid code, which is a side of the equation that is often overlooked.”
Siemens Gamesa Renewable Energy (SGRE) in its turn is building “the 194MW Bulgana Green Energy Hub in Australia, a complex that would marry 56 of the OEM’s 3.4MW wind turbines to a Tesla 20MW/34MWh Li-ion battery.”
SGRE’s “mission on hybrids is to devise a system that can optimise energy injection, grid stability and capacity factor, depending on location and hourly profile.” In Zaragoza, Spain, the company has been testing hybridisation with “a test-bed that integrates a G52-850 kW turbine, 245kW of PV, a 500kWh/500kW battery and a 66kW diesel gen-set — as well as a recently added 120kW/400kWh Vanadium redox flow battery.”
“Key to [this] integration, we feel, is the power controller, the ‘brain’ of any hybrid power plant”, comments Antonio de la Torre, SGRE’s chief technology officer of SGRE.
“Markets will vary region to region for hybrids [depending on resource profile and power purchasing models],” says De la Torre. “Controllers that can manage production and storage from different sources and export onto the grid in an optimal way is what we need to develop to deal with this reality.”
Then there is GE, which “started testing its Wind Integrated Solar Energy technology platform concept in 2016 with projects including a 1.6MW wind/223kW PV demonstrator in Anantapur, India, and two in the US state of Minnesota.”
“Reliable access to firm — and ideally load-following — renewable energy production is what developers are after, and you won’t get that with standalone wind or solar,” GE Renewable Energy Global Strategic Growth Leader Amelie Wulff tells Recharge.
According to Snieckes, “many in the strategy departments at major developers and OEMs reckon the adaptability and flexibility that hybrid renewables plants have demonstrated — even at the pilot level — points to the potential of the decentralised energy system that will in the next decades take shape around the globe.”
He quotes Morten Dyrholm, senior vice-president of marketing, communications and public affairs at Vestas, as saying that renewable energy can now “fight the fossil-fuel guys on merchant terms”.
“Variability is the only question that can be put to the renewables sectors and the only reason the fossil-fuel industry can argue we need to keep them around — for system stability,” he says, “adding that hybrid projects, coupled with the falling price of battery storage, are removing the need for fossil-fuel back-up capacity.”
Thomsen adds “that hybrids will help answer the question of how renewables will earn money in the future, when wind and solar are unsubsidised and so cheap that the levelised cost of energy (LCOE) becomes irrelevant and projects have to rely on the wholesale market price.”
“What will the LCOE of the future be? The earnings per MWh? The cost of being connected to the grid and being able to produce to it — like the concept today for our internet connection? Something we haven’t dreamt of yet? Whatever it is, we are going to make money from energy differently in the future, and hybridisation is how we are going to address this, to find the best answer.”
De la Torre agrees: “Ultimately, our mission as a company — and there is a reason we added ‘Renewable Energy’ to the name [when Siemens and Gamesa merged] — is to provide clean energy for the future. This will require power plants that can be substituted for the carbon-based energy production of today — and hybrids will be key to this.”
“Hybridisation is teaching us how these still relatively new but increasingly competitive [energy] technologies can be brought together to bridge intermittent energy resources, while providing flexibility, through storage and energy management that considers the demand side,” says Riccardo Amoroso, head of the innovation and product lab at Enel X, the group’s advanced energy services arm.
Dyrholm adds: “Hybrids make the case for speeding up the march of the electricity sector in the energy transition, moving us towards a new reality of the electrification, the renewable baseload that we are all yearning for — and not just companies ‘in’ renewables, but also the corporates, the automotive industry, heating and cooling sector. Everyone.”
Darius Snieckes of Recharge is not the only one who has spotted the hybrid trend. “It is no longer wind vs. solar but both vs. fossil generation”, writes energy expert Fereidoon Sioshansi in the June 2018 edition of his EEnergy Informer newsletter.
Moving forward, wind, solar and storage are likely to become increasingly co-mingled as hybrid solutions rather than stand-alone installations, he notes. “The renewables’ value proposition will be greatly enhanced by offering more reliable, predictable supply rather than a “run-of-the-river” mentality where renewable generation is fed into the grid when, where, and if available. “
He quotes Steve Sawyer, General Secretary of the Global Wind Energy Council, who writes: “Hybrid wind/solar/storage plants are now being built, able to supply clean reliable power 24/7 for most of the year; utilities are seriously experimenting with battery storage in place of peaker plants; and EV sales are booming in key markets. The development of local micro-grids, some using peer to peer power trading with blockchain technology, and more and more sophisticated market structures for matching up supply and demand at all scales are just some of the elements beginning to emerge.”
ENERGY WATCH #3 by Karel Beckman
The need for gas – how Europe is responding
May 22, 2018
Clearly, though, despite advances in renewable energy and efforts to revive/maintain nuclear power, gas will presumably be a key source of energy for Europe at least for a few decades.
This is not necessarily a reassuring message.
Euractiv published an alarming article recently on the European gas market. According to the article, Europe has surprised by the fact that the Netherlands became a net importer of gas last year. “Although the decline of Dutch gas production was long anticipated, the abruptness of the fall came as a surprise to industry observers”, writes Euractiv.
“We did not realise until relatively recently that, in the Dutch gas sector, [production] would decline very quickly,” Jonathan Stern, head of the Natural Gas Research Programme at the Oxford Institute for Energy Studies told Euractiv.
According to the article, “How Europe eventually replaces Dutch production will probably redefine the fundamentals of the EU gas market in the coming decade or so. In fact, the effects are already being felt in a market where consumption is propped up by a gradual switch from coal to gas resulting from the pressure to decarbonise energy.”
“Natural gas consumption in Europe last year reached its highest level since 2010, according to EU figures released in April. And the vast majority of it was imported, representing a whopping 360 billion cubic meters (bcm) of the 491 bcm consumed in Europe, up 10% from 2016.”
“This resulted in an estimated import bill of €75 billion, the European Commission said in its latest quarterly report on European gas markets.”
Russia, needless to say, was Europe’s dominant supplier, at 43% of EU imports. “Pipeline gas from Norway came a distant second, at 34%, while the combined share of Algerian and Libyan supplies stood much lower, at 10% of EU imports in 2017, down from 11% in 2016.”
“The general trend is that the domestic EU production is declining and the import need of gas is increasing. And that’s a trend we’ve seen coming for years,” said Jannik Lindbaek, the head of EU office at Statoil, the Norwegian energy company.
As Euractiv rightly observes, “with domestic production falling inexorably, no country other than Russia seems in a position to raise its production significantly – at least in the short to medium term. For different reasons, imports from Algeria and Libya are projected to erode slightly. And Norwegian imports aren’t expected to grow much either… This leaves policymakers in Brussels grappling with an uncomfortable reality: Despite their best efforts to liberalise gas markets and diversify supplies, Russia is likely to remain Europe’s dominant supplier for many years.”
There is one alternative of course, which is LNG. In 2017, “LNG imports covered 14% of total extra-EU gas imports, up from 13% in 2016, a share which is only projected to grow. Research by Bloomberg New Energy Finance (BNEF) shows LNG demand in Europe is expected to jump to 23.1% in 2030, on the back of falling domestic production in the North Sea and reluctance to import more gas from Russia.”
The increasing dependency on Russian gas brings up the question of Nord Stream 2. Some argue that this planned Gazprom pipeline increases dependence on Russia, but it could also be viewed as an additional means of transport of gas to Europe, which implies that it adds to security of supply by lowering dependence on Ukrainian (and Polish) transit. A lot depends on where you are in Europe – in the West or in the East.
The European Commission has long tried to block Nord Stream 2, siding with Eastern European member states against countries such as Germany and the Netherlands, but it seems to have decided this won’t work. Instead, Brussels now seems to be trying to make Nord Stream 2 part of a wider agreement with Russia, which would include the preservation of Ukrainian and Polish transit.
To this end, it proposed an amendment to the Gas Directive last year, which aims to bring Nord Stream 2 under the EU gas market regime. Under the current Gas Directive, so-called “import pipelines”, which run from a third country to the EU, are exempt from EU rules.
If this were to change, it would mean that Nord Stream 2 would have to comply with such EU rules as ownership unbundling, non-discriminatory third party access, certain network tariff rules and transparency requirements on network capacities. For Gazprom this would not be an attractive option at all. Gazprom has an export monopoly in Russia and does not want to share ownership or use of the pipeline.
But the Commission also offers a way out: it believes that if the amendment is adopted, Gazprom might be amenable to make the pipeline part of a wider deal – “an intergovernmental agreement” – in which the EU could grant Gazprom certain freedoms in return for concessions in other parts of the market, e.g. in Ukraine and Poland.
However, the proposed amendment to the Directive is controversial. It would have to apply to other import pipelines as well, such as those running from Norway and from North Africa to the EU. Those gas suppliers won’t be happy with the new rules. And even if they get exemptions, it could deter investors contemplating future projects.
And there is another catch: the amendment would also increase the power of the European Commission over the gas market at the expense of the member states.
What the Commission proposes is that when part of a pipeline is not within the Union jurisdiction of the EU and part of it is, the resulting “conflicting rules” should be resolved through an intergovernmental agreement (IGA) between the two countries involved. However, such an IGA would have to be approved by the Commission; in fact, it may even be the Commission who would have the right to conclude the IGA, not the Member State in question. Thus, Member States would see their freedom to shape their own energy policy significantly curtailed.
The question is now what the Council of the European Union (i.e. the Member States) will decide. The Council’s Legal Service submitted two opinions on the proposal, on 1 March and 26 March.
The first one examined “whether the application of the proposal to the exclusive economic zone (EEZ) of the Member States is compatible with the UN Convention on the Law of the Sea (UNCLOS)”. That is to say, can the EU decide that its laws apply to a pipeline that’s built in the EEZ of its member countries. Nord Stream 2 runs through the EEZ of several EU member states in the Baltic Sea.
The answer of the legal service was quite clear: no, under UNCLOS rules, it cannot. States may take measures to prevent pollution from pipelines, but they cannot regulate them as the Commission would like to do.
But that’s not yet the end of the story. The second opinion looked at the impact of the proposal on “the allocation of competences between the Union and its Member States”. This opinion clearly states that the Gas Directive “can only apply to the part of a pipeline that lies within the territory of the Member States and not to the part of the pipeline under the jurisdiction of a third country”.
It adds that “Beyond the limits of the Union jurisdiction (…), the rules on energy which are set out in Union law will be applicable only if the third countries are willing to adopt those Union rules, unilaterally or by agreement (…)”.
But of course Nord Stream 2 has a beginning and an end. It begins in Russia, but it ends in Germany – an EU Member State. Under the current Gas Directive, this is not a problem: it simply does not apply to any section of the pipeline, including in German territorial waters. This is how the Gas Directive was always intended to work.
The proposed amendment, however, will change this. It will make EU law apply to the German end of the pipeline. In that case, obviously a problem will arise. The pipeline will be subject to two different regulatory regimes. In which case, as the legal opinion notes, “the conclusion of an intergovernmental agreement for the operation of a pipeline becomes necessary to resolve contradicting requirements and ensure legal certainty.”
What is more, since this agreement would affect the “security of supply” of the EU, it would fall under the competence of the EU rather than the member states. Which would mean, as the legal opinion makes clear, that from now on the EU would have the last word over not just Nord Stream 2, but all pipelines from third countries to EU countries.
A clever move from the Commission no doubt, but whether the Council will go along with it is doubtful.
Although Member States such as Germany may not agree to the proposed amendment to the Gas Directive, there are signs that Germany is trying to find a compromise over Nord Stream 2. At a press conference in April with Ukraine president Petro Poroshenko, Chancellor Angela Merkel unexpectedly said that Nord Stream 2 cannot proceed without clarity on Ukraine’s role as a gas transit route.
In recent days, German Economic Affairs Minister Peter Altmaier has been visiting Kiev and Moscow in an attempt to reach some kind of agreement. It is not clear yet what this will look like, but Altmaier has said he is optimistic.
One reason for optimism may be that, according to new research from the Oxford Institute for Energy Studies (OIES), Gazprom will actually continue to need Ukrainian gas transit beyond 2019, at least to some extent, when the current contract between Ukraine and Russia expires. Ironically, this is because Gazprom’s gas exports are growing strongly, as we saw earlier.
Researcher Jack Sharples of OIES writes in a briefing paper – Ukrainian Gas Transit: Still Vital for Russian Gas Supplies to Europe as Other Routes Reach Full Capacity – that “with European gas import demand having risen substantially since 2014, Gazprom has dramatically increased its sales on the European market. In Q1 2018, Gazprom reported record daily gas exports to Europe in late February and early March.”
Gazprom has access to multiple pipeline export routes for the delivery of its gas to the European market, writes Sharples: “Greifswald is the point at which the Nord Stream pipeline enters the German gas transmission system. Kondratki is the point at which the Yamal-Europe pipeline crosses from Belarus into Poland. Wysokoje is the point at which the Soviet-era gas transmission system delivers gas from Belarus to Poland. Drozdovichi, Velké Kapušany, and Beregovo are the points at which gas passes from Ukraine into Poland, Slovakia, and Hungary, respectively. Finally, Isaccea is the border point between Ukraine and Romania. In addition, the Blue Stream pipeline delivers Russian gas direct to Turkey, and Gazprom is able to make direct deliveries to Finland, Estonia, Latvia, and Lithuania.”
The routes are shown in this graph:
After analyzing the gas flows, Sharples concludes that “Gazprom prioritised flows through the capacity that it owns, namely, Nord Stream, Yamal-Europe, and Wysokoje (the latter through its Belarusian subsidiary, Gazprom Transgaz Belarus). These high rates of utilisation are unlikely to be reduced even upon the completion of Nord Stream 2.”
“Gas transit via Poland (through the Yamal-Europe pipeline) is likely to continue even after the launch of Nord Stream 2”, writes Sharples, “while Ukraine, Romania, and Bulgaria will see a substantial decline in gas transit via Isaccea after the launch of Turkish Stream.”
Sharples concludes that if Nord Stream 2 is built, gas transit through Ukraine will drop from 84.3 bcm (in 2017) to around 26 bcm. That’s a substantial drop, but it’s not zero.
It could mean that Europe’s growing dependence on Gazprom may result in Gazprom’s continued dependence on Ukraine, which could prompt the Russians to make a deal over Nord Stream 2 …
Sharples, it must be admitted, is a little less optimistic. He writes that “the continuation of gas transit via Ukraine in volumes greater than the 26 bcm/y suggested above will depend on the European Commission and European gas importers, and their insistence that gas transit via Ukraine continues. Otherwise, gas transit via Ukraine will be reduced to delivering limited volumes for European storage re-fills in the ‘off-peak’ summer months, and acting as a provider of ‘peak flexibility’ in the winter months, when daily demand rises above the daily capacities of other routes.”
He adds that, “This prospect will undoubtedly complicate any negotiations between Gazprom and its Ukrainian counterparty over a new contract to govern the transit of Russian gas via Ukraine, once the existing contract expires at the end of December 2019. While Gazprom may be willing to commit to only limited annual transit volumes, the Ukrainian counterparty may question the commercial viability of maintaining a large gas transmission system with multiple exit points for the delivery of relatively small annual volumes, unless transit fees per cubic metre delivered were to increase significantly.”
ENERGY WATCH #4 by Karel Beckman
New EV report by Deloitte: is Big Oil ready for the “volt-age”?
May 22, 2018
“According to a new report by consultancy Deloitte, nearly half of oil and gas companies are not preparing for the shift to EVs. They could be in for a shock”, writes Giles Parkinson on the Australian website Reneweconomy.
“The underlying assumption of ever-increasing demand for crude oil due to an increasing appetite for transportation may soon stall,” Deloitte says in its report, “Enter the Volt-Age: Electric vehicle disruption of the oil and gas industry.”
The Deloitte report notes that “the uptake of EVs could do wonders for Australia’s reliance on fuel imports, which as the federal government has finally admitted, is now perilously vulnerable to supply interruptions in the South China Sea.”
One of the authors of the Deloitte report, Steve McGill, said EVs are an obvious alternative to oil imports: “All the countries that are looking to ban sales of cars with internal combustion engines are among the major oil importers,” McGill told RenewEconomy.
Another consultancy, Accenture, agrees on the potential of EVs, notes Parkinson. “Our reliance on fossil fuels makes Australia vulnerable to external price spikes and supply disruptions,” says Edgar Demuth who is a managing director within the Accenture resources business. “Electric vehicles can help reduce this threat if the generation of electricity by renewable sources is extended.”
“So the increase of electric vehicles needs to be accompanied by an increase in renewable energy generation to reduce the reliance on fossil fuels and the reliance on imports of fossil fuels to Australia. With a larger portion of renewable energy generated for transport purposes, electric vehicles can reduce the emissions that contribute to climate change and smog, improving public health and reducing ecological damage.”
In its report, “Deloitte notes that the transportation sector is responsible for more than 55 per cent of the worldwide demand for petroleum products and demand for road transportation fuels accounts for 45 per cent of the global demand for oil.”
One interesting part of the report, writes Parkinson, is that “the big growth economies – particularly China and India – are looking to EVs for the future. In both countries, more than 85 per cent of consumers are showing an interest in EVs.”
“In many other countries, the interest is at 50 per cent or more. Those percentages will likely increase significantly as more lower-cost models become available, and the economics overwhelming trump internal combustion engine cars.”
“It’s easy to see why EVs have not been high on oil executives’ radars,” the Deloitte report says.
“Representing less than two percent of global car sales today, EVs are barely visible on the road. This is set to change, and fast. Every major car manufacturer has outlined plans for electrification over the next decade.”
As to range anxiety, “While questions remain about remote EV deployments and long range distance requirements, the suitability of EVs for city fleet vehicles, buses, taxis and daily work and school commutes is clear,” the report says.
According to Parkinson, “The Deloitte report suggests that one of the problems holding back the oil and gas industry is the scale of the change that they must contemplate.”
“Change will not come in the form of a one-for-one fuel switch from petrol to electricity, but rather through a fundamental re-imagining of the concept of transportation,” the report says. “The challenges and opportunities of this major disruption are significant. With EV releases coming from every major car manufacturer, autonomous-EV trials underway throughout the world, and emissions and combustion engine ban legislation in the works in a number of cities and countries globally, the world sits on the cusp of a global transportation transformation that will impact all market segments and industries, including Australia’s LNG industry.”
“The EV opportunity is enormous – oil and gas operators must recognise this and should not ignore the rise of EVs,” the report’s authors say. “They should use their massive competitive advantage in the form of large capital reserves, great technological prowess and their skills in managing large and risky capital projects and operations to get out in front of the unfolding energy and transport revolution.”
“In today’s rapidly changing energy landscape, oil and gas companies must get into the driver’s seat if they want to be competitive in tomorrow’s energy economy.”
But will they, asks Parkinson? “Part of the rhetoric of Big Oil about future transitions is that they don’t want to scare their investors, or more particularly the banks that would finance their projects.
It was interesting to note that in response to the survey’s question about impacts of the widespread adoption of EVs, only two per cent suggested stranded assets. Now, that is being hopeful.”
Then again, what alternatives does Big Oil have? It can’t manufacture cars. It can go into EV-charging, but most people will be doing that at home and won’t need EV charging stations along the highway. It could go for renewables, such as solar power, but will discover that a lot of companies are busy with that already.
And not just solar companies. Nissan for example, “the maker of the Leaf”, is following Tesla’s example and is now offering solar power and home batteries, as Wired reports.
In the UK, Nissan is offering “a generation-to-acceleration scheme that equips customers with roof-mounted panels and a battery to store some of the electricity they generate. If they drive a Leaf, or Nissan’s e-NV200 electric van, they can combine the whole process and drive from Scotland to Wales to wherever, guilt-free, fog lights on, windshield wipers whisking away.”
And not stop at any petrol station…