January 9, 2018
ENERGY WATCH #1 by Karel Beckman
Moves in the great geopolitical-economic gas battle
January 9, 2018
One of the major geopolitical and economic energy power plays today is taking place across the international gas sector. The long-standing special gas relationship between Russia and Germany is coming under heavy pressure as the German economy becomes more interwoven with the EU (which has some strongly anti-Russian states among its members), and as the U.S. is trying to barge in on the European gas market, both for economic and political reasons.
This great gas conflict, playing out across many smaller policies and controversies (Nord Stream 2, the EU’s antitrust action against Gazprom, EU pipeline politics, US shale gas exports) is of life-and-death importance to Russia, whose government is strongly dependent on its gas revenues.
“A new stage” in Gazprom’s history as it exports record amount of gas to Europe
For the moment, the Russians seem to be on the winning side. “Russia to keep its grip on Eurpe’s gas market after record 2017”, news agency Bloomberg reported recently.
Russia exported a record 190 bcm (billion cubic metres) of natural gas to Europe in 2017, beating the record that had been set in 2016:
For 2018, Gazprom is planning “to ship a minimum of 180 billion cubic meters”, Deputy Chief Executive Officer Alexander Medvedev told Bloomberg.
“Of course, it’s business, not sports,” Medvedev said. Yet, this is “a new stage” in the company’s history, he added.
“Gazprom meets more than a third of Europe’s demand for natural gas, Russia’s biggest and most lucrative market worth some $37 billion in revenue this year”, notes Bloomberg. This does not sit well with “EU lawmakers” who “have had their hearts set on diversifying energy supplies away from Russia and are urging expansion of ports to handle LNG tankers from the U.S.”
Gazprom accuses the U.S. of politicizing its economic interests in the EU through a sanctions law earlier this year that targeted pipeline projects. Executives in Russia have so far shrugged off the threat of serious competition in Europe.
While EU gas demand depends on weather and economic growth, “it’s likely to increase next year as domestic production falls and coal prices recover, making imports from Gazprom more competitive”, Medvedev said. Russia has the biggest potential to meet the additional demand, he added.
Medvedev acknowledged that Europe may take more LNG imports, especially when demand exceeds the capacity of pipeline suppliers. In Britain, pipeline imports are near peak levels, and there’s little storage available to give its system flexibility. The U.S. in particular is eager to supply more LNG to Europe. Production there has skyrocketed, making the U.S. a potential top producer of LNG in the mid-2020s, according to International Energy Agency estimates.
But Medvedev said “supplies drawn from pipelines will remain more competitive than LNG.” He expected U.S. LNG to go to Latina America and Asia, where prices are higher. “A global LNG market still does not exist,” Medvedev said. “There are three large regional markets — America, Europe and Asia — with a big price difference. An Asian price premium will stay in place as demand there is booming.”
Germany and Russia: a special gas relationship increasingly scrutinized
That’s all rather short-term news, though. In the longer term, Russia’s dominant position on the European market is not a given. Much will depend on the relation between Germany, Gazprom’s biggest customer, and Russia – and this relation will depend in turn on Germany’s position in Europe, as researchers Aurélie Bros, Tatiana Mitrova and Kirsten Westphal make clear in a recent research paper published by the German Institute for International and Security Affairs (SWP) in Berlin.
In “German-Russian gas relations – a special relationship in troubled waters”, they note that in the EU, this special relationship is receiving growing scrutiny. Russian gas supplies are increasingly being seen as antagonistic to:
- a more sustainable energy system
- a norm-based liberal political and economic order, and
- the process of EU integration
The authors explain that “Historically, the Soviet-German gas-for-pipes deal was embedded into the German Ostpolitik. Concrete cooperation in the economic sphere was perceived as a major element of détente and ‘change through rapprochement’ (Wandel durch Annäherung).”
“Following German reunification and acknowledging Moscow’s key role, a strategic partnership was proclaimed in the early 1990s. In the 2000s, a ‘new Ostpolitik’ succeeded the idea of ‘rapprochement through interdependence’ (Annäherung durch Verflechtung). In 2008, a Modernization Partnership supplemented this Strategic Partnership, also in the energy field.”
That’s the historical background (comparable in many ways to the special U.S.-Saudi relationship). However, in recent years “disappointment and alienation crept into the relationship. As of 2009 at the latest, German-Russian natural gas relations cannot be analyzed without including the EU, because this is when the Third Energy Package was introduced. Brussels has become a factor of change.”
Moreover, the paper notes, “the EU enlargement of 2004 brought with it a more critical view of these relations, as did the Russian-Ukrainian gas disputes in 2006 and 2009. Finally, external energy governance has shifted from the policy initiatives influenced by the idea of a common European market from Lisbon to Vladivostok to the export of the EU acquis communautaire to the neighborhood. Commercial gas relations have undergone a grand transformation as well.”
What this means, according to the authors is that “the impression of ongoing ‘business as usual’ is misleading.”
They distinguish three phases in the German-Russian gas relationship: “During the first phase, from the 1970s till the 1990s, gas trade was developed and supported politically to have positive spillover effects. In the 1990s the relationship transformed into a commercial and business-driven relationship, which covered the whole value chain and resulted in vertically integrated, bilateral monopolies and a kind of special reciprocity. The big change came with the creation of the EU’s internal gas market and a gas glut that affected the business models of companies’ gas undertakings and led to the loss of clear prospects. A low-price buyers’ market since 2009/2010 and a gas supply surplus have fundamentally changed the behaviors of gas traders and consumers.”
At this moment, the authors conclude, “a common idea, vision, and understanding of how future gas relations will look are lacking…. commercial relations have become more complicated, unstable, and uncertain than in the past. This weakens the stabilizing effect and may heighten the exposure to geopolitical instrumentalization.”
So what will be next? According to the paper, “the number of potentially intervening (f)actors – such as legal actions and regulatory changes in the EU, or the new U.S. sanctions regime in force since August 2017 – limit the German government’s room for maneuver.” They argue that “if German-Russian gas relations are to be preserved as part of the economic cooperation, dialogue is essential in order to navigate the troubled waters.”
This dialogue “should be supported by smaller, innovative lighthouse projects that are mutually attractive and beneficial (such as the use of bio/synthetic gas, gas in transport, cooperation to fight methane leakage, and agreement on improving efficiency in gas use). It is important to adapt gas relations to a low-carbon future and more integrated and liquid gas markets in the EU (and especially in Central European member states). Both have to look for new models of cooperation and, possibly, for new partnerships and new stakeholders (independent gas producers, power generators, municipalities, startups), both in Russia and Germany.”
“It is thus highly problematic that German-Russian gas relations are being overshadowed by the Nord Stream 2 issue”, the authors add.
They advise German proponents of gas relations with Russia to adopt “a pragmatic attitude” – Germany “should not have high expectations about positive spillovers into the security realm, but rather emphasize the value of economic cooperation as one pillar of a dual strategy of containment and cooperation.” Russia, in turn, should not “let geopolitics prevail over commercial logic”, as this would “heighten the level of sensitivity, also in Germany.”
Baumgarten explosion shows EU gas markets not yet diversified enough
It is well-known that the EU has been quite successful at creating a competitive, integrated EU gas market over the last decade or so. The result of three successive Gas Directives has been that the cosy old gas monopolies (shared between big producers in Russia, the Netherlands and Norway, and the big consumers, notably in Germany) have been broken up, pipelines have been opened up to third parties, and prices have converged across the European continent.
This could be seen as bad news for Russia, since it makes Europe less dependent on Gazprom. But that could also be viewed as good news for the Russians, since it means that dependence on Russia has become less of a concern. The proponents of Gazprom’s new pipeline project, Nord Stream 2, argue that the EU does not need to worry about the pipeline, since most EU countries are now always able to source gas in the wholesale market. They may choose Russian gas – but they don’t have to, if they don’t want to.
Nevertheless, the real resilience of the EU gas market has not been tested since the Russian-Ukrainian gas dispute in 2009, so we don’t really know what will happen if Russian gas should get cut off for some reason or other. However, last year, on 12 December, a real live test of the gas market took place when an explosion took out the European gas hub at Baumgarten in Austria for 13 hours.
Analyst Thierry Bros from the Oxford Institute for Energy Studies investigated the effect of the interruption on the functioning of the market. The interruption hit Italy, the EU’s second largest gas market, hardest. The Italian government declared a state of emergency – actually the second time it has done so in a short period.
Bros’ conclusion is that “whilst the gas industry is resilient, and markets do work, implementation of the existing regulation is needed”.
With “existing regulation”, Bros is referring to the three criteria that ACER (EU Agency for the Cooperaton of Energy Regulators) has said the gas markets of all EU member states should conform to. They should
- have at least three distinct origin sources (defined as gas-producing countries or countries hosting a liquid hub from where gas is purchased)
- have a market concentration, as measured by the Herfindahl-Hirschman Index (HHI), lower than 2,000
- have the capacity to meet yearly demand without their largest upstream supplier, which equates to a Residual Supply Index (RSI) greater than 110% of demand
Italy, Bros notes, “complies with 1) and 3) and should therefore have the capacity to meet yearly demand without its largest upstream supplier”. The problem is that “Italy’s market-concentration is too high with an HHI higher than 2,000.”
What lessons can be drawn from this? “If Italy, which provides a good representation of the EU-27 gas market as a whole, witnessed repeated alerts in 2017, the rest of Europe should take the HHI metric seriously in order to evaluate the potential risk of a non-competitive EU market (for instance one relying too heavily on Russian gas)”, notes Bros.
According to Bros, “Italy and the EU-27 do not need any additional storage … nor any major infrastructure. They simply need to ensure that the diversification metric is enforced! Without enforcing this regulation, Italy and the EU-27 allow companies to choose the cheapest supplier so as to maximize short-term profits, exposing the system to unexpected shocks, with negative economic impact if EU gas prices spike for more than just a few hours!”
He adds that “if this entails too much work for energy regulators, perhaps the EU’s Directorate-General for Competition (DG Comp) should take a more active role: either the diversification of supply rule is relevant and must be enforced, or the rule is irrelevant and must be cancelled.”
EastMed won’t replace Russian gas
Note that the development of Israel’s offshore natural gas resources, until recently seen as a wonderful economic opportunity for the country, “has slowed to painful crawl in recent months”, according to an article by Simon Henderson, director of the Gulf and Energy Policy Program at The Washington Institute, on the website Breaking Energy.
Henderson notes that “On December 13, the government announced that it was awarding licenses for just six of the twenty-four offshore blocks on offer. Each of the six had received only a single bid, and the three-year permits do not include an obligation to actually drill. Israel’s snail’s pace development—largely a product of its shifting regulatory environment and falling global gas prices—highlights the country’s persistent domestic and diplomatic obstacles, which are having a ripple effect on Eastern Mediterranean gas projects.”
Five of the six licenses announced last week were awarded to an independent Greek company, Energean, while the sixth went to a consortium of Indian state companies (ONGC Videsh, Bharat PetroResources, Indian Oil Corporation, and Oil India), notes Henderson. “The absence of major international firms is at least partly a consequence of their historical caution about being commercially involved with Israel—after all, top firms Eni and Total placed bids in Lebanon’s recent license round despite the country’s thorny (to put it mildly) domestic politics.”
According to Henderson, “the substance of the [Indian] bids may be superficial: two of the Indian companies have no exploration experience.”
The ultimate value of Energean’s bid is uncertain as well: “The company’s current oil production is a miniscule 5,000 barrels per day from a field in shallow waters off Greece. It also owns two small Israeli offshore gas fields: Karish and Tanin, both undeveloped. It bought the fields from a consortium led by Houston-based Noble Energy, which originally discovered them but was forced to sell by the Israeli government in order to meet monopoly rules.”
More generally, Henderson notes that “exploring for natural gas in the deep waters of the Eastern Mediterranean is an expensive challenge, but it remains enticing for many international companies due to past successes and the prospect of major finds.”
He observes that “Gas has been produced from fields off Egypt’s coast for many years, and optimism in the area’s potential was renewed after the Italian company Eni discovered the giant Zohr field in 2013. Estimated to contain 30 trillion cubic feet (tcf) of gas, Zohr is tantalizingly close to Cyprus’s exclusive economic zone, resulting in renewed exploration but, so far, no commercially viable discoveries.”
Henderson summarizes the status of Eastern Mediterranean gas fields as follows:
Note that 30 tcf is large for a single gas field, but not earth-shaking in terms of the global gas market: it’s half of Norway’s proved reserves. In other word, the Eastern Mediterranean gas fields may develop into a significant regional factor, they won’t replace Russian gas for Europe.
ENERGY WATCH #2 by Karel Beckman
Renewables deliver on their promise; plus: solar is getting razor thin
January 9, 2018
Critics of solar and wind energy often claim that the so-called “Energy return on investment” (EROI) of these technologies is negative, or barely positive. In other words, they argue that more (or almost as much) energy is used over the lifetime of the assets than they deliver.
However, according to a new study published in Nature Energy, reported on by Carbon Brief, this is not true. The study measured the “full lifecycle greenhouse gas emissions of a range of sources of electricity out to 2050. It shows that the carbon footprint of solar, wind and nuclear power are many times lower than coal or gas with carbon capture and storage (CCS). This remains true after accounting for emissions during manufacture, construction and fuel supply.”
“There was a concern that it is a lot harder than suggested by energy scenario models to achieve climate targets, because of the energy required to produce wind turbines and solar panels and associated emissions,” explains project leader Dr Gunnar Luderer, who is an energy system analyst at the Potsdam Institute for Climate Impacts Research (PIK).
Luderer tells Carbon Brief: “The most important finding [of our research] was that the expansion of wind and solar power…comes with life-cycle emissions that are much smaller than the remaining emissions from existing fossil power plants, before they can finally be decommissioned.”
So the study focused on net emissions, rather than EROI, but it has implications for EROI as well, as Simon Evans explains in Carbon Brief: “The first stage of the work [was] to add up the energy needed to build power stations and to provide them with the fuel and other inputs they need to run. This is called “embodied energy use”. It is the inverse of “energy return on investment” (EROI).”
The study finds that electricity from fossil fuels, hydro and bioenergy has “significantly higher” embodied energy, compared to nuclear, wind and solar power.
For example, writes Evans, “the study finds that 11% of the energy generated by a coal-fired power station is offset by energy needed to build the plant and supply the fuel, as the chart below shows. This is equivalent to saying that one unit of energy invested in coal power yields nine units of electricity. Nuclear power is twice as good as coal, with the energy embedded in the power plant and fuel offsetting 5% of its output, equivalent to an EROI of 20:1. Wind and solar perform even better, at 2% and 4% respectively, equivalent to EROIs of 44:1 and 26:1.”
See this chart:
This research “uses the embedded energy numbers to work out the lifecycle greenhouse gas emissions of different sources of electricity. It finds that the footprint of nuclear, wind and solar are much lower than coal and gas with CCS, as well as hydro or bioenergy.” See this chart:
There is some devil in these details, though. As Evans writes: “Note that this chart shows figures for a 2C world in 2050, when global electricity supplies have been largely decarbonised. This shift cuts the impact of indirect emissions due to electricity use, for example at a solar cell factory or nuclear fuel site. The chart also accounts for technological progress, which is particularly significant for solar as manufacturing processes get more efficient.”
In other words, if today’s production of solar and wind farms were studied, the numbers would not come out so positively, since production processes today still largely use fossil fuels. The assumption of a low-carbon 2050 world “explains why many of the footprints are lower than the corresponding values from the IPCC’s AR5, which did not account for changes over time.”
As Luderer tells Carbon Brief: “A crucial strength of our approach is that it fully accounts for future changes in the energy system. For example, increasingly less energy will be required to produce solar modules, due to technological progress and a shift towards less energy-intensive technology variants. At the same time, the global climate change mitigation effort will reduce the CO2 emissions per unit of electricity and steel inputs, further limiting life-cycle greenhouse gas emissions. The earlier studies considered by the IPCC did not account for these future changes, thus overestimating indirect energy requirements and indirect greenhouse gas emissions of several low-carbon technologies.”
Solar solar everywhere
One of the major drawbacks of solar (and wind) energy is that they have low energy density. This means they require a lot of space. Solar panels can be integrated into urban environments of course, up to a point, but if solar PV is to make a big dent, big solar farms will have to be built as well.
But there may be a solution: ultrathin solar cells – thinner than human hair – which could be literally integrated into just about everything: clothes, windows, hats, backpacks, portable electronics, cars, bikes, etc.
It’s a technology that MIT in Boston and other institutions have been working on for a number of years, and according to David Roberts at the website Vox.com, they are likely to conquer the world.
Roberts writes that “South Korean scientists have created solar PV cells that are 1 micrometer thick, hundreds of times thinner than most PV and half again as thin as other kinds of thin-film PV. (The research is in a paper published in Applied Physics Letters last June.) The cells are made with gallium arsenide as the semiconductor, “cold welded” directly onto a metal substrate, with no adhesive to make them thicker. Remarkably, they produce roughly as much power as thicker PV cells, though in testing, “the cells could wrap around a radius as small as 1.4 millimeters.”
And this not even the thinnest solar cell ever: “Back in February 2016, MIT researchers made solar cells so small and light they could sit atop a soap bubble without popping it.”
Vladimir Bulović, MIT’s associate dean for innovation and the Fariborz Maseeh (1990) Professor of Emerging Technology, said: “the key to the new approach is to make the solar cell, the substrate that supports it, and a protective overcoating to shield it from the environment, all in one process. The substrate is made in place and never needs to be handled, cleaned, or removed from the vacuum during fabrication, thus minimizing exposure to dust or other contaminants that could degrade the cell’s performance.”
“The process takes place in a vacuum chamber at room temperature, without the solvents and high temperatures required to make conventional PV. Researchers say the same fabrication process could work with a number of different materials, including quantum dots or perovskites, yielding solar cells small and transparent enough to be embedded in windows or building materials.”
Now these are all “lab breakthroughs”, Roberts acknowledges, and “it’s a long road from the lab to a commercial product”. But he believes the trend is clear: “Cells are getting smaller and smaller, and more and more flexible, using new fabrication techniques that are less and less resource-intensive. It’s all super expensive now, and probably will be for a while. Eventually, though, these new methods will find their way into markets and start getting scaled up. With scale, costs come down.”
So what does this all add up to? Roberts offers a tantalizing vision: “PV is different from any other energy technology”, he writes. “It can change the way we view power, from something we generate at a specific location to something we harvest, everywhere. Sufficiently cheap, small, and flexible solar cells could be integrated into our building materials, streets, bridges, parking lots, vehicles, clothes, even our skin.”
“These tiny solar cells won’t produce much power individually, but what they lack in energy density, they will make up for in ubiquity. They will be everywhere. And as solar diffuses into infrastructure, so too will energy storage and management.”
“Eventually, the entire built environment of human civilization will become one giant energy harvester and manager. The power system will not be something overlaid onto infrastructure but something that is part and parcel of infrastructure, something infrastructure just does, automatically. Most or all of the power urbanites need will simply exist in a seamless web, all around them. It sounds like sci-fi. But I bet kids born today will live to see something like it.”
ENERGY WATCH #3 by Karel Beckman
After disastrous year for global nuclear sector, some encouraging news from U.S. and China
January 9, 2018
The international nuclear power sector has been under tremendous pressure last year, but it can take heart at some encouraging developments.
Whereas in Germany RWE’s 1284 MW Gundremmingen-B reactor was shut down at the end of December, in line with the country’s nuclear phaseout, China at the same time saw the 1000 MW Russian-designed Tianwan reactor connected to the grid (with Areva instrument and control systems).
Fast reactor in China
Much more importantly, China also has started on the construction of a 600 MW demonstration fast reactor at Xiapu, the World Nuclear Association reports. Fast reactors belong to the category of “advanced” nuclear reactors that are the industry’s hope for the future. (For more on this see Ian Hore-Lacy’s article on Energy Post here. For a contrary view, see this article by Jim Green.)
At a ceremony to mark the start of construction, chairman of the China National Nuclear Corporation (CNNC) Wang Shoujun described the new plant as a “landmark project for the development of China’s nuclear industry“. He said “it is of great significance for realising the closed nuclear fuel cycle, promoting the sustainable development of nuclear energy in China and promoting the development of the local economy.”
Fast neutron reactors (FNRs) are seen as the main future reactor technology for China, and CNNC expects the FNR to become predominant by mid-century, notes World Nuclear News. It does add that the country’s research and development on fast neutron reactors started in 1964!
A 65 MW fast neutron reactor – the Chinese Experimental Fast Reactor (CEFR) – near Beijing achieved criticality in July 2010, and was grid-connected a year later. Based on this, the 600 MW design – the CFR600 – was developed by the China Institute of Atomic Energy. The Xiapu reactor will be a demonstration of a sodium-cooled pool-type fast reactor design. The reactor will use mixed-oxide (MOX) fuel and will feature two coolant loops producing steam at 480°C.
The next phase will be the construction of a commercial-scale unit – the CFR1000 – which, if the CFR600 is a success, will start in 2028, with operation from about 2034. So there’s still a long way to go, but the proponents of advanced nuclear reactor at least have a concrete project to build on.
Lifesaver decision in U.S.
Other very important good news for the nuclear sector came in the U.S. in December, when a State Commission in Georgia voted to give conditional approval for the completion of the Vogtle 3 and 4 AP1000 nuclear reactors. This decision is a life-saver for the U.S. nuclear energy sector. After the VC Summer new-build project in South Carolina was cancelled in September, Vogtle was the only remaining new-build nuclear power project left in the U.S.
The twin reactors are also the only new construction of Generation III+ designs currently underway in the U.S., as nuclear journalist and commentator Dan Yurman writes. The III+ design is also envisioned for the Hinkley Point C nuclear power plant to be built by EDF in the U.K.
Yurman notes that “in voting 5-0 the commissioners overruled the recommendation of their staff who said that there was not an economic justification for a decision to go forward with the reactors.”
As Yurman writes, “the failure of Westinghouse to execute basic project management methods was a major contributing factor to the problems at both Vogtle and VC Summer. Westinghouse is now in bankruptcy proceedings, and Toshiba, is parent firm, is also in financial distress having lied about its earnings by saying it booked $1.2 billion in revenue that never happened. A buyer is being sought for Westinghouse so that Toshiba can exit the nuclear energy industry.”
Paul Bowers, CEO of Georgia Power, which is building the Vogtle reactors,, said “the recommendation was based on the results of a comprehensive schedule, cost and cancellation assessment that was prompted by the bankruptcy of former primary Vogtle contractor Westinghouse in March 2017. He added that Vogtle 3 is expected online in November 2021 and Vogtle 4 in November 2022.”
This does not mean that all is smooth sailing from now on. Yurman notes that “The original cost of both of the reactors was estimated at $6.1 billion in 2009. That works out to about $2,350/Kw. … Completion cost of the twin AP1000s is now slated to be $23 billion for both units that works out to about 10,000/Kw which is well above the current global average “overnight cost” of $6,100/Kw.”
The high cost “has led to howls of protest from ratepayers and may lead to lawsuits aimed at the PSC [Georgia’s Commission] decision from anti-nuclear groups bent on shutting down the entire project.”
None of this implies that a nuclear renaissance is anywhere in sight. As World Nuclear News (WNN) reports, 2017 saw only four new reactors to the grid worldwide, and the retirement of three reactors (in Germany, Sweden and South Korea). Even worse, it saw only two construction starts. With a net capacity gain of 1 GW, all in all a disastrous year.
All new grid connections, moreover, were Chinese one way or the other, notes WNN, with one new unit built in Pakistan by a Chinese company. Of the construction starts, one was in China and one (by the Russians) in India.
In other words, the outlook for the global nuclear power industry is still quite uncertain.
ENERGY WATCH #4 by Karel Beckman
Blockhain: a disaster maybe, a disruption not likely
January 9, 2018
The spectacular increase in the price of bitcoins has been one of the big stories of 2017. For the energy sector, the potential uses of blockchain and, more generally, the continuing digitalization of processes will no doubt be one of the big stories of 2018 – and beyond.
Catastrophic energy guzzler
To start with the obvious relation between bitcoins/blockchain and the energy sector: the “mining” of bitcoins is using up ever more electricity. As professor John Quiggin of Queensland University writes on The Conversation, bitcoin is “a potentially catastrophic energy guzzler”.
At present, the most widely used estimate of the energy required to “mine” bitcoins is comparable to the electricity usage of New Zealand, but this is probably an underestimate, notes Quiggin. “If allowed to continue unchecked in our current energy-constrained, climate-threatened world, Bitcoin mining will become an environmental disaster.”
Quggin adds that “a widely used estimate by Digiconomist suggests that the bitcoin network currently uses around 30 terawatt-hours (TWh) a year, or 0.1% of total world consumption – more than the individual energy use of more than 150 countries.” By contrast, “in his 2013 analysis, [Australian analyst and entrepreneur] Guy Lane estimated [in 2013] that a bitcoin price of US$10,000 would see that energy use figure climb to 80 TWh. If the current high price is sustained for any length of time, Lane’s estimate will be closer to the mark, and perhaps even conservative.”
In the past, bitcoins could be mined on personal computers, but nowadays “miners” use purpose-built machines optimised for the particular algorithms used by bitcoin. “With these machines, the primary cost of the system is the electricity used to run it. That means, of course, that the only way to be profitable as a bitcoin miner is to have access to the cheapest possible electricity.”
And “most of the time that means electricity generated by burning cheap coal in old plants, where the capital costs have long been written off. Bitcoin mining today is concentrated in China, which still relies heavily on coal.”
Even in a large grid, notes Quiggin, with multiple sources of electricity, bitcoin mining effectively adds to the demand for coal-fired power. “Bitcoin computers run continuously, so they constitute a baseload demand, which matches the supply characteristics of coal.”
Since “any increase in electricity demand at the margin may be regarded as slowing the pace at which the dirtiest coal-fired plants can be shut down”, bitcoin mining “is effectively slowing our progress towards a clean energy transition”, writes Quiggin.
Quiggin is not impressed by claims from bitcoin supporters who argue that the global financial system uses a lot more electricity (probably about 100 TWh a year). “The global financial system serves the entire world”, notes Quiggin. “By contrast, the number of active bitcoin investors has been estimated at 3 million. Almost all of these people are pure speculators, holding bitcoin as an asset while using the standard financial system for all of their private and business transactions.”
It gets worse: “tsunami of data” will lead to huge surge in power demand
This is just about the energy use of bitcoin mining. But what about the energy use associated with the revolution in “big data” that’s starting to sweep across the global economy?
According to a report on the Climate Home website, new scientific research shows that “information and communications technology, or ICT, could create up to 3.5% of global emissions by 2020 – surpassing aviation and shipping – and up to 14% 2040 – around the same proportion as the US today.”
“Global computing power demand from internet-connected devices, high resolution video streaming, emails, surveillance cameras and a new generation of smart TVs is increasing 20% a year, consuming roughly 3-5% of the world’s electricity in 2015”, says Swedish researcher Anders Andrae.
In an update to a 2016 peer-reviewed study, Andrae found that without dramatic increases in efficiency, the ICT industry could use 20% of all electricity and emit up to 5.5% of the world’s carbon emissions by 2025. This would be more than any country except the US, China and India.
He expects industry power demand to increase from 2-300Twh of electricity a year now, to 1,200 or even 3,000Twh by 2025. Data centres on their own could produce 1.9Gt (or 3.2% of the global total) carbon emissions, he says.
“The situation is alarming,” said Andrae, who works for Chinese communications technology firm Huawei. “We have a tsunami of data approaching. Everything which can be is being digitalised. It is a perfect storm. 5G, [the fifth generation of mobile technology] is coming, IP [internet protocol] traffic is much higher than estimated and all cars and machines, robots and artificial intelligence are being digitalised, producing huge amounts of data which is stored in data centres.”