March 13, 2017
ENERGY WATCH #1 by Karel Beckman
False hopes for hydrogen?
March 13, 2017
In January, the Scottish government launched a consultation on a new energy strategy, which, in addition to phasing out nuclear power (of which Scotland has 2 GW), a four-fold increase in renewable energy by 2030 and a CCS strategy, is seeking to embrace “a hydrogen economy”, especially in heat and transport. (You can find the PDF of the draft strategy here.)
How wise is this?
Euan Mearns, a well-known independent energy expert and blogger, has written an extensive critical analysis of the feasibility of such a transition to “hydrogen” (The Hydrogen Economy – More Green Mythology), which is well worth a read. I will try to summarize his arguments here.
First of all, the Scottish government, Mearns notes, has quite high hopes for hydrogen. The draft strategy notes that “Hydrogen may have the potential to deliver the lowest cost and least disruptive solution for the decarbonisation of heat.”
It notes, among other things that “At point of use hydrogen is a zero emissions fuel, and by 2050 could be a major component of the UK’s energy system.”
The goals of the hydrogen strategy are summed up as follows:
- The draft Climate Change Plan pathway includes a moderate amount of hydrogen gas in the gas network from the mid-2020s.
- While more analysis will be required, there is some evidence to suggest that hydrogen can offer significant cost savings for customers compared to alternative low carbon heat sources such as electricity, or district heating.
- Hydrogen gas at scale will most likely require natural gas (methane) as the source feedstock and as such in order to be low carbon, carbon capture and storage facilities will be a necessary system requirement. Scotland is therefore uniquely placed to support an emerging hydrogen economy.
- These proposals, at national scale, have the potential to substantially reduce the total system cost of decarbonisation, but they will require further innovation in technology, high-volume hydrogen production at an acceptable cost, and a carefully managed hydrogen ‘switch over’ – as with the switch to natural gas in the 1970s.
Mearns, however, argues that using “hydrogen gas at scale” would be extremely costly, indeed “madness”.
The starting point of his analysis is a comparison of the costs of electricity and natural gas. He takes the tariffs industrial users tend to pay: £95/MWh for electricity versus £15/MWh for natural gas. (The wholesale price of electricity is around £50 but the tariffs include transmission charges. )
Conclusion: “Natural gas, therefore, is dirt cheap compared to electricity and a central plank of our economy’s current business plan is to take cheap natural gas to make more valuable electricity from it. Making H2 via electrolysis from water turns this thermodynamic and economic plank of our economy on its head. It should be abundantly clear that it will be impossible to make cheap hydrogen gas from expensive electricity. In fact, the plan calls for this electricity to come from renewable sources that will make it significantly more expensive than the £95 used in this analysis!”
An alternative to electrolysis which the Scottish draft plan also embraces is to produce hydrogen through a process called steam methane reforming (SMR). This is cheaper, but has the disadvantage that it emits CO2, so the costs of CCS (carbon capture and storage) must be added, which will cancel the cost advantage.
Mearns clearly explains the two processes that can be used to make hydrogen. He calculates that at an electricity price of £95/MWh, hydrogen from electrolysis will cost £142/MWh to make, i.e. more than 9 times as much as natural gas at a price of £15/MWh.
The SMR process is cheaper and comes out at around £54/MWh, but to this needs to be added the cost of CCS, estimated at £56/MWh on the basis of UK government sources. So this would bring total cost to some £100/MWh, cheaper than electrolysis, but still over 6 times as expensive as natural gas.
And all of this does not take into account the additional problems of using hydrogen in gas mains pipes. Mearns notes: “The smaller atomic radius of hydrogen makes it easier for it to escape from pipes, it has a much larger explosive range mixed with air from 4% to 75% and a lower energy density meaning that the operating pressure would need to be increased, increasing the risk of escape and explosion…. Why would anyone want to bother or take the risk of all this when the starting point is an uplift by a factor of 6.7 times the cost?”
He also takes a look at some alternative ways of producing zero-emission heat and concludes that a nuclear electric heating system, which makes use of nuclear power combined with heat pumps, achieves the lowest cost at £47/MWh (based on an electricity price of £142/MWh: the production cost of Hinkley Point C, £92.50, plus £50 in transmission costs).
The Scottish government’s plan, Mearns concludes, will result in “the least reliable, [most] hazardous and most expensive energy systems ever”.
ENERGY WATCH #2 by Karel Beckman
High hopes for power-to-gas
March 13, 2017
A few days after Euan Mearns produced his article, another well-known independent energy expert, former Guardian reporter Chris Goodall, produced an article on his blog Carbon Commentary with a closely related theme, namely “power-to-gas”, but with different conclusions.
In this article, also well worth a read, Goodall argues that the technology of converting power into gas is “the critical remaining ingredient in the energy transition”. Without it, writes Goodall, “the renewables revolution may ultimately fail”.
This seems to be a diametrically opposite conclusion to the one from Mearns. However, it should be noted that the two authors agree with each other on many points.
Goodall writes that “very approximately, hydrogen made from methane costs about twice the cost of natural gas per unit of energy carried. So if natural gas (mostly methane) costs 1.6 pence (2.0 US cents) per kilowatt hour [=£16/MWh], which is approximately the current wholesale rate in the UK, then producing a kilowatt hour of hydrogen will cost about 3.2 pence (4.0 cents) [=£32/MWh].” The £32/MWh is lower than the £54 calculated by Mearns, but the overall point holds.
On electrolysis, Goodall similarly notes: “This uses electricity and until recently the conversion process has been less than 70% efficient. And, generally speaking, electricity has been several times expensive than natural gas per kilowatt hour. A commercial customer might have bought electricity at 8 pence a kilowatt hour [£80/MWh] or more, meaning that at 70% efficiency hydrogen costs about 12 pence per kilowatt hour [£120/MWh] or almost four times as much as gas produced from methane. Clearly, no-one produces hydrogen using electrolysis unless they are remote from steam reforming plants.”
Again, broadly speaking, this confirms Mearns’ analysis, though Goodall does make the added point that “Electrolysers are getting much cheaper and more efficient. We will see electrolysis costs fall to around $400/kilowatt and efficiencies rise above 80%. However making hydrogen from power will still be usually more expensive than from steam reforming of natural gas.”
But then Goodall puts a different twist on the story. What, he says, if electricity could be delivered virtually free of charge? That would change the picture completely.
This can’t be always the case of course, but wholesale electricity prices do frequently dip to extremely low figures, even below zero, when there is more wind or solar power in the system than there is demand for: “The low wholesale price of power at times of wind or of strong sun means that making hydrogen from electrolysis is often cheaper than using natural gas. And as wind and solar capacity rises, this reversal of usual pricing differences is going to happen far more frequently.”
Goodall notes, like Mearns, that distribution and transmission charges also enter into it, but not if the electrolysers are put next to wind farms or solar parks.
So what about other disadvantages of hydrogen, apart from the cost? Goodall acknowledges that “moving it around is complicated and expensive”, which is why, he argues, “it will be used predominantly at the point of production, either for chemical products, fuelling fuel cell cars or making methane.”
Indeed, Goodall discusses a next step which Mearns does not consider: the hydrogen produced by electrolysis can be turned into methane by adding CO2. This methane, which is the same as natural gas, can then be used in the gas grid for heating. The difference is that it is zero-emission gas – well, that is to say, if the CO2 is derived from “organic waste”, as Goodall puts it.
Needless to say, this last step involves energy losses and thus extra costs. “The best we can hope for,” writes Goodall, is “to obtain 65% of the energy in electricity out of the process in the form of methane.” What does this mean for the costs? “Natural gas trades at about 1.6 pence (2.0 US cents) per kilowatt hour at the central trading point in the UK. How cheap does electricity have to be to make it financially attractive to use it to make ‘renewable’ methane? Very roughly, and before the operating costs of the machines, it has to be 1.6 pence times 65% or just over 1 pence per kilowatt hour (1.25 US cents).”
“The German market operated at less than this price for about 35 hours last week”, Goodall adds, “or one fifth of the time. In all those periods, an electrolyser could have been profitably making hydrogen to be converted back into methane. The methane – which has very low greenhouse gas emissions because it has been made from renewable electricity and the CO2 from organic waste – can be pumped into the gas grid. It can then [also] be used to make power in a gas turbine when electricity is in short supply.”
Goodall acknowledges that “to most people in the utility industry, the idea that it can possibly make sense to use valuable electricity to make cheap natural gas still seems absurd.” But he argues that “They aren’t looking at the charts, I say. As wind and solar electricity grows in importance, the cost of power will inevitably drift towards zero (…) Electricity will become cheaper than gas. On a windy weekend night in the North Sea offshore turbines will produce more electricity than northern Europe needs at some date in the not-to-distant future. Negative wholesale electricity prices will become increasingly prevalent.”
Goodall points out an added advantage of power to gas: it will help utilities get back into the game of renewable energy, as it requires skills that these companies typically have: “The right way to ‘fix the broken utility model’ […] is to link the gas and electricity markets through large-scale application of power-to-gas technologies. Big utilities talk about understanding the need for decentralisation but the reality is that they will be terrible at moving away from centralised production plants. What they would be good at is running large scale electrolysis and methanation operations that allow them to continue to run CCGT power plants when electricity is scarce. We will not need capacity payments or other complex subsidies and incentive schemes. By creating a continuing role for CCGT we will have found a way to keep our energy supply secure without threatening decarbonisation objectives.”
To conclude: Goodall does not quite arrive at the model of a “hydrogen economy” that the Scottish government seems to be aiming at. But he does give arguments why it may well be economically profitable to create a renewable power-to-gas system, based on hydrogen plus CO2, which would serve as an essential complement to the renewable energy system.
ENERGY WATCH #3 by Karel Beckman
Limited hopes for pumped hydro and batteries
March 13, 2017
The reason that Goodall views power-to-gas as “the remaining critical ingredient in the energy transition” presumably (he does not discuss this explicitly in his article) is that the gas thus produced can be stored and used when there is not sufficient renewable electricity. That is after all the well-known Achilles Heel of a renewable energy system.
And he may well be right at that, if we are to believe Dr. Björn Peters, a financial expert at DWS Investments, the retail asset management arm of Deutsche Bank and the largest mutual fund company in Germany. In an interview with Energy Storage Report, Peters says that it will not be possible for Europe to rely completely on intermittent wind and solar power complemented by storage, whether in the form of pumped-hydro or batteries.
Peters’ research into weather patterns shows that the European continent is hit about twice a year by “doldrums”, spells of cloudy calm weather in which there is hardly wind or sun. In German such a spell is called a “Dunkelflaute”. On Energy Post we have had an exchange of views on this phenomenon recently in articles by Heiner Flassbeck, who wrote that the doldrums spell “the end of the Energiewende”, and Craig Morris, who argued that they could be addressed by a combination of storage, demand response and backup.
Peters, however, concludes that storage is not a feasible option with the currently available technologies. To balance out a Dunkelflaute, which can last up to two weeks, “you would need 2,000 times the entire pumped-hydro capacity in Germany. We have 45GWh and we would need about 80TWh at least.”
Battery technology is simply out of the question for such long periods, notes Peters: “Practically all the storage plants today are being built with a storage time of up to four to eight hours. But wind systems build up over 18 hours, may last several days and can go back to zero within 18 hours, followed by doldrums of several days.”
Pumped hydro, moreover, faces another problem in today’s market: it is built to store base-load thermal generation at night, when demand is low, to be used in the daytime when demand – and prices – are high. But with the expansion of solar power, daytime prices have dropped. This has “wiped out the business case for pumped hydro”, notes Energy Storage Report.
Peters’ findings also appear to counter findings by German energy expert Gregor Czisch, whose research proved that it is possible to a achieve a fully renewable and at the same time affordable electricity supply for Europe and its neighbourhood if the output from production plants is allowed to be transported far enough.
According to Peters, this means “that to achieve a fully renewable energy system Europe would have to depend on generation from beyond its borders, for example from wind farms stretching from West Africa to Siberia. It is doubtful whether European leaders would find this palatable.”
The only feasible solution, according to Peters, is to have backup capacity in the system, which ideally should be nuclear power – if that were safe enough, which he does not think is the case at present. Instead, he believes Europe “should embrace reactor technologies that shut down automatically on overheating and producing waste that only needs to be stored for around 200 years.”
However, Peters does not discuss the power-to-gas option in this article. No doubt the discussion will continue.
ENERGY WATCH #4 by Karel Beckman
Big boost for offshore wind
March 13, 2017
One renewable energy sector that is decidedly flying high at the moment is offshore wind. Countries around the North Sea are frantically building large offshore wind farms, whose costs have been declining remarkably.
Now in a further development, the transmission system operators of Denmark, Germany and the Netherlands – Tennet GmbH, Energinet.dk and Tennet BV – have announced they will sign a trilateral agreement in Brussels on 23 March 2017 that will press ahead on developing a large renewable European electricity system in the North Sea.
The idea, first launched by Dutch TSO Tennet in June 2016, is to build one or more “energy islands” (or “Power Link islands”), on the Dogger Bank in the North Sea, which will serve as a central connection point for the wind farms. The goal of the agreement is “to achieve a multi-party consortium”, which will also involve other companies, to realize this North Sea Wind Power Hub.
The Wind Power Hub should be able to connect 70 to 100 GW of wind farms and transmit the power over direct current lines to the Netherlands, Denmark, Germany, Great Britain, Norway and Belgium. In these countries, “transmission cables will simultaneously function as interconnectors between the energy markets. Besides transmitting wind electricity to the connected countries, these ‘wind connectors’ will enable the countries to trade electricity.”
More info on the North Seas Energy Forum event in Brussels on 23 March here.
ENERGY WATCH #5 by Karel Beckman
The limits of oil, coal and gas according to McKinsey
March 13, 2017
Yes, McKinsey has come around to “peak oil demand”!
Okay, so some people might not think it’s a big deal that McKinsey, in a new report, Beyond the supercycle: how technology is reshaping resources, published in February, the famous consultancy is predicting that “Total [global] primary energy demand growth will slow or peak by 2035, despite growing GDP”.
According to the report, “Demand for oil, thermal coal, and iron ore could peak and potentially decline in the next two decades while copper’s prospects remain buoyant, according to our analysis, although there may be regional differences. Advanced economies could experience a faster decline in demand for oil with rapid technological adoption, for example, while emerging economies may experience demand growth, regardless of the rate of technological change. However, the resource intensity of GDP growth is continuing to decline globally.”
True, McKinsey is not the first to come to these conclusions, but they are nevertheless significant, because 1) it is McKinsey after all; and 2) the reasons McKinsey advances are interesting. There is no talk of “climate policies” in the report; instead, the authors base themselves purely on such factors as “rapid advances in automation technologies”, such as robotics, artificial intelligence, self-driving electric vehicles, which will lead to energy savings, as well as the growth of renewable energy thanks to lower costs.
“Reduced energy demand from transportation, the proliferation of energy efficiency measures, and increased substitution of fossil fuels enabled by cost reductions in renewables could account for as much as $1.2 trillion of the total savings in an accelerated technology adoption scenario. The potential supply side savings for producers of the five commodities we focus on—oil, natural gas, thermal coal, iron ore, and copper—could amount to $300 billion to $400 billion annually in 2035”, says the report.
This is how McKinsey sees technology leading to energy savings and substitution:
These developments will lead to the following demand growth picture:
An important consequence of this development is that we will not see the kind of commodity price rises that we saw in the past when demand soared, at least not for oil, gas, coal and iron ore, according to McKinsey. Copper may be an exception.
During the “2003-2015 supercycle”, spending on these resources exceeded 6% of global GDP, which only happened once before, in the early 1980s:
But while the commodity producers seemed to profit from this high spending, McKinsey notes that weaknesses had already begun to appear: “Their gains from the up cycle masked declining productivity and rising costs, which continue to take a heavy toll.”
The return on capital invested of oil and gas companies started declining already in 2005 and has not recovered since:
Source: McGraw-Hill Companies S&P Capital IQ; MGI Commodity Price Index, McKinsey Global Institute analysis
In short, life will not be the same again, according to McKinsey, for the fossil fuel sector. Not for nothing did Shell last week sell off $8.5 billion worth of Canadian tar sands holding – after earlier beating a retreat from Arctic oil exploration.
ENERGY WATCH #6 by Karel Beckman
Confirmed: Battery gigafactory in Sweden
March 13, 2017
We reported on this initiative before, but just in case you missed it: a Swedish company, SGF Energy, now renamed as Northvolt, is planning to build a “gigafactory” for lithium-ion batteries in Sweden that will match Tesla’s factory in Nevada in size. Last week, at a press conference in Sweden, Peter Carlsson, CEO of Northvolt, announced that “we have a solid business plan in place that enables us to produce high quality batteries at an affordable cost.”
The Northvolt plan includes “a new concept inspired by the semiconductor industry, focusing on: scale, customized customer solutions, vertical integration and highly controlled manufacturing. The execution is fundamentally different compared to current battery production facilities. Northvolt is dedicated to create a circular system, and has the highest ambitions regarding life cycle management: our approach covers cradle to grave. Building the factory in the Nordic region, given its carbon free power base, will enable us to rely on fossil free energy.”
“Compared with Asia and the US, Europe is behind in the battery industrialization”, said Paolo Cerruti, COO of Northvolt. “The project resonates commercially, since the demand from automotive and energy storage sectors will be huge.”
Funding agreements from companies and organizations such as Stena, Vattenfall, InnoEnergy (European innovation ecosystem for sustainable energy), The Swedish Energy Agency and Vinnova (Sweden’s innovation agency) are in place, says the company. “This support, together with private investments by the founders, lays the foundation for the first phase. Additional external funding will be needed at a later stage. The 32+ GWh production site will require a €4+ billion investment over a period of six years. Our aim is to start construction in the second part of 2018 to enable volume manufacturing by the end of 2020.”
Last week InnoEnergy, an EU-funded “innovation engine for sustainable energy across Europe”, announced it will invest €3.5 million in Northvolt.