Global warming *has* accelerated

 From Open Mind (Tamino)

I won't repeat the whole article.  Read it in full here.

My paper with Stefan Rahmstorf showing that global warming has accelerated was published in Geophysical Research Letters today. The main result is that global warming is NOT proceeding at the same old rate it has been since 1975. It’s going faster.

In this data set [from Berkeley Earth], 2025 turned out to be the 3rd-warmest year on record (as in the other data sets except NASA, where it came in 2nd). When I adjust the data to remove the estimated impact of el Niño, volcanic eruptions, and solar variation, I get this:

The trend is unaffected, but the noise level is much reduced, which enables us to estimate warming rates with less uncertainty. I’ve added a red line to this graph which is a modified LOWESS smooth of the adjusted data.

To test for acceleration we isolated the data since 1975, and the simplest way to test for it is to fit a parabola to the data; if the quadratic term is statistically significant, we can reject the null hypothesis, that the signal is just a straight line. Of course we must correct for autocorrelation of the noise, but still the quadratic term turns out to be strongly significant. We can safely reject the null hypothesis: there has been acceleration.

According to this model, the warming rate right now is the slope at the endpoint of the parabola, which is 0.28 ± 0.05 °C per decade (i.e. between 0.23 and 0.33 °C per decade, 95% CI). I will emphasize that this is the “best estimate” and those are the correct uncertainty levels IF (and this is a BIG IF) the data actually follow a parabola plus stationary noise. If not (which is the overwhelmingly likely case), we can consider the estimate good but not best, and the uncertainty levels are a lower bound on the actual uncertainty.

Another test for acceleration is to find the best fit of a continuous piecewise-linear function which is allowed to change slope at a time chosen by changepoint analysis. This is a challenge to evaluate statistically because we have to allow for autocorrelation and account for the extra degree of freedom to choose the changepoint time. But it can be done, and the best-fit model again turns out to be strongly statistically significant.

Both those models serve excellently to demonstrate the presence of acceleration. But I doubt they are best to estimate what the warming rate is right now, and what it will be in the near future. For that, I offer yet another model, which I will apply to the data since 1880, a continuous piece-wise linear fit (PLF) which is allowed to change its slope every 15 years from 1905 through 2010. I call this model “PLF15”

The PLF15 model not only estimates the signal value, it conveniently gives us an estimate of the average warming rate over each segment between the knots. I can plot the warming rate itself (which for this model is constant during each segment) along with light blue shading to show the uncertainty range.

All these graphs plot the warming rate in °C per year, but when quoting numbers I have followed the custom these days to talk about the rate in °C per decade. According to this analysis, the current estimated rate is 0.31 ± 0.07 °C/decade.

Which estimate is best? I don’t know, but I do know that even 0.24 °C per decade will take us past 2 °C right around the year 2050. The whole point of the Paris agreement is: DON’T GO THERE. My advice: fasten your seat belt, things are going to get ugly.

We need to redouble efforts to cut emissions, or things will get very ugly.  What can we do?

• Set a renewable energy target in every country.  The percentage of renewables+nuclear needs to rise by 6-8% a year, at least.  This will cut emissions by 27% (emissions from electricity generation are +-30% of total global emissions) within a decade.  We may not yet be able to go above 90 or 95% renewables in the grid, because we don't have long-term storage to offset periods of dunkelflaute, but we will have cut most emissions from electricity generation.  
• We must tax imports from countries which do not have an R.E.T. or a price on carbon.  (See my posts on a carbon border tax)
• We need to accelerate the replacement of petrol/diesel vehicles (ICEVs) with EVs.  This is a problem, because even when we reach 100% of sales being EVs, it will take 10-20 years for all ICEVs on the roads to be replaced.  This is too long.  Most countries are nowhere near 100% EV sales.   We could, for example, ban the import of new or second-hand ICEVs, or slap 100% taxes on them.   Ethiopia has already done this.  This policy should apply to two and three-wheeled vehicles, too.  Countries which do this deserve reduced carbon border taxes.
• In rich countries, we need to replace oil- or gas-based household and industrial heating with heat pumps.  Because they have high up-front costs, they will require government subsidy to start the revolution rolling.

All of these combined will cut emissions by 50 to 60%.  If we also switch to low-emission steel and cement, the emissions cuts could reach 70%.

That will leave (mostly) agriculture.  Put that in the too-hard basket for now--people love their meat too much to give it up.  But it won't go away.  When we've cut emissions by 70%, agriculture will dominate what's left over.  And action will no longer be postponable.

The final nail in the fossil fuel coffin

 From Just Have a Think

When he describes batteries as, say, 500 MW and 2000 MWh, what that means is that the battery can produce 500 MW of electricity for 4 hours (2000/500).  MW is a measure of the output, MWh (or kWh in the case of an EV battery) in this context, is a measure of how much electricity has been stored.

We still don't have a cure for multi-day windless periods--dunkelflaute--but that may be the only place where we will still need gas peaker plants (for now).   For most of the world within 40 degrees of the equator, 8 hours of storage will be enough, as night demand is about two-thirds of average day-time demand.  This means that solar combined with 8 hours of storage will provide power 24/7.  And that's ignoring the huge capacity available with EVs.  For example, Australia has 16 million passenger vehicle and 4 million light commercial trucks.  At 40 kWh storage per EV, that totals to 800,000 MWh/ 800 GWh of stored electricity.  Obviously, only some of that is available at any given time, but even if merely one quarter is available, this would provide 200 GWh of storage.  Even before you add grid-scale batteries, which are about 23 GWh at the moment.

Why Trump and big oil won't win

 This is my chart using data from Our World In Data of the price of PV panels in US$ per watt, in constant 2024 dollars.  In other words, a 5000 kW system, ignoring inverter, grid connections, land, and installation would cost 5000x30 cents, or $1500.  (Of course, this pricing is for wholesale systems with economies of scale; a rooftop solar system would be more expensive.)   This is a 99.8% fall from 1975.

Note logarithmic scale

On its own, this is not enough to show that solar will provide most of our power, inevitably, eventually.  After all, the denialists will gleefully tell you the sun doesn't shine at night (goodness me, who knew?) 

So you've got to add the cost of storage.  And the fact is, battery prices are falling even faster than PV prices. 

This chart shows BNEF's battery costs survey data, also in constant dollars, with my estimates for 2025 and 2026.  If you do the numbers, it turns out that adding 4 hours of storage to a solar farm will add just $12/MWh of electricity generated to the cost.  Adding 8 hours storage would cost $24/MWh, which is still cheaper than new coal, or (outside the US) new gas.

Note log scale

But, I hear the denialists wail, what about dunkeflaute, those periods in high latitudes when there is no wind, and little solar, and it's cold?  Well, until we get long-term storage, we will need gas peaking.  We can make the gas using electrolysis of water, and using the hydrogen produced to make methane via the Sabatier system, which would in effect be long-term storage.  Or we can go on using fossil gas.  But even if we do the latter, we will still have cut emissions from electricity generation by 95%.  

A final chart from Our World in Data.  It shows a classic "learning curve".  A new technology starts.  It's expensive, and has only a few uses out in the wild.   But usage increases.  Manufacturers get a bit better at making it.  Demand increases, costs fall.  Falling costs lead to still more demand, which in turn leads to still lower prices, and so on, until the technology has gained a 100% market share. 

The chart uses a double log scale.  On the vertical axis, each tick mark shows a halving of PV module prices.   On the horizontal axis, each tick mark shows a 10-fold increase in cumulative installations.  So each 10-fold increase in installations leads to a halving of module prices --- and vice versa.

There is probably another 10-fold increase in solar installations in prospect over the next 10 years.  Which will be associated with another halving of the cost of solar.  Meanwhile, the rapid progress of EVS and the need for stationary storage will drive down battery costs, which will continue to halve every four years.

This is irresistible.  The learning curve is being driven by fierce competition, which in turn drives rapid technological advance.  There is nothing Trump or Big Oil or coal miners or the rabid Right can do about this.  They can delay the technological advances in the USA, which will just retard the US economy, but in the rest of the world, the advance of solar plus storage to market dominance in inevitable.  Except in high latitudes.

Dunkelflaute

When I first heard about this phenomenon, I explained it to myself as occurring when there was a cold, cloudy, windless winter's day.  Which isn't too bad a quick descriptor.  But here is a more informative Wikipedia article: 

 

In the renewable energy sector, a dunkelflaute (German: [ˈdʊŋkəlˌflaʊtə] ⓘ, lit. 'dark doldrums' or 'dark wind lull', plural dunkelflauten)[1] is a period of time in which little or no energy can be generated with wind and solar power, because there is neither wind nor sunlight.[2][3][4] In meteorology, this is known as anticyclonic gloom.[5]

Meteorology

Unlike a typical anticyclone, dunkelflauten are associated not with clear skies, but with very dense cloud cover (0.7–0.9), consisting of stratus, stratocumulus, and fog.[6] As of 2022 there is no agreed quantitative definition of dunkelflaute.[7] Li et al. define it as wind and solar both below 20% of capacity during a particular 60-minute period.[8] High albedo of low-level stratocumulus clouds in particular – sometimes the cloud base height is just 400 meters – can reduce solar irradiation by half.[6]

In the north of Europe, dunkelflauten originate from a static high-pressure system that causes an extremely weak wind combined with overcast weather with stratus or stratocumulus clouds.[9] There are 2–10 dunkelflaute events per year.[10] Most of these events occur from October to February; typically 50 to 150 hours per year, a single event usually lasts up to 24 hours.[11]

In Japan, on the other hand, dunkelflauten are seen in summer and winter. The former is caused by stationary fronts in early summer and autumn rainy seasons (called Baiu and Akisame, respectively),[12] while the latter is caused by arrivals of south-coast cyclones.[13]

Renewable energy effects

These periods are a big issue in energy infrastructure if a significant amount of electricity is generated by variable renewable energy (VRE) sources, mainly solar and wind power.[14][1][15] Dunkelflauten can occur simultaneously over a very large region, but are less correlated between geographically distant regions, so multi-national power grid schemes can be helpful.[16] Events that last more than two days over most of Europe happen about once every five years.[17] To ensure power during such periods flexible energy sources may be used, energy may be imported, and demand may be adjusted.[18][19]

For alternative energy sources, countries use fossil fuels (coal, oil and natural gas), hydroelectricity or nuclear power and, less often, energy storage to prevent power outages.[20][21][8][22] Long-term solutions include designing electricity markets to incentivise clean power which is available when needed.[19] A group of countries is following on from Mission Innovation to work together to solve the problem in a clean, low-carbon way by 2030, including looking into carbon capture and storage and the hydrogen economy as possible parts of the solution.[23]

Renewables naysayers say that because of dunkelflauten, we can't use wind and solar to power our economies.  But let's have a look at how often they happen:  a maximum of 150 hours a year, or, about 1.7% of the time.  

Because battery storage is getting so cheap, we soon won't need to use gas peaking plants.  The problem with dunkelflauten is that they last much longer than the 4 to 6 hours when electricity demand exceeds supply, the sort of shortage that can easily be covered by batteries.  For now, until cost-effective long-term storage is invented, we will need to use gas to make sure the lights don't go out.  However, we can make synthetic natural gas from green hydrogen using the Sabatier process, or we may store hydrogen, which we can burn in gas plants for the 150 hours a year when we need it.  These won't add net CO2 to the atmosphere. 

Even if we used fossil gas to provide 100% of the power during dunkelflaute events, and renewables/nuclear the rest of the time, we could still cut emissions from power generation by 98%.  

Because we won't be using dunkelflaute gas plants for most of the year, the cost of their electricity per MWh will be high, because the cost of interest payments and depreciation will be spread over only a few hours of usage.  But, by the same token, taken over the whole year, the occasional high cost per MWh will be spread over thousands of hours of electricity generation.

Dunkelflaute is not an insoluble problem.  We can fix it, and still switch to renewables and cut our emissions.

Pan-Europe wind & solar = stable output

 A most interesting thread from Sarastro on Bluesky.

The past two days we [have] seen something interesting in the European power market: continent wide balancing that is providing security of supply at the lowest prices driven by commercial incentives…

We know that solar and wind and inverse output characteristics. A system that contains both is more secure than one or other alone. This chart from @ember-energy.org makes the point on a European wide scale

 

You can see that on a European wide scale the combined output of wind and solar is less intermittent than solar and wind alone. These charts do not show the risk of hourly balancing though so you still need a source of flexible generation. [Or storage]

This morning we can see that in action. The French grid is importing power from Spain and exporting it to other markets across the French grid in Northern Europe. That’s how you get solar from southern Europe to Northern Europe and wind from the north to the south

 

But take a look at the output of the French nukes: the French have reduced nuclear output in response: they are not just wheeling power across the French system they are managing the French system for cost and using the nukes as a battery

It’s a revelation for those (like me) who have thought of nuclear has inflexible. EDF is showing us that at the heart of the European grid is a huge battery, its nuclear park, capable of firming both south solar and northern wind.

Yesterday we saw something similar with wind from the uk being imported into France and French exports to other European countries

But critically the nukes modulating output…

A couple of points:

1.  I've talked before about how wind and solar tend to balance each other, not just daily, but also seasonally.  It's not perfect, but on a continent-wide grid (as in Europe) the necessary storage/dispatchable power needed (such as gas) is significantly reduced from what would be needed if just wind or just solar was used.
2. Like Sarastro, I also did not know that nuclear could be ramped up and down.  Notice that the percentage moves are small --- roughly 20% --- but because nuclear is so large in European generation, that's enough to go a long way to balancing total grid output.  From the top chart, I estimate the seasonal variability of wind and solar together as ~10% of total output.
3. New nuclear is still much more expensive than new wind+solar combined with 5 hours of storage.  In Australia (without nuclear), 5 hours of storage with 20% overcapacity of wind and solar is enough to provide a stable grid for 99% of the time.    The tricky period seems to occur in July (mid-winter in Australia), when periods of little wind combine with low insolation and high demand for heating, a situation which is called dunkelflaute.  Even though this is a problem only 1% of the time, it would be unacceptable to close down the grid.
4. The solution, until we get better methods of long-term storage, is gas.  Currently, natural gas, but plausibly, in future, synthetic natural gas via the Sabatier process, produced using surplus green electricity.  
5. Alternatively, concentrated solar power (CSP) may do the trick.  Vast Solar, an Australian company, is busy constructing a CSP plant at Port Augusta in South Australia (on the edge of the desert, with lots of sunshine and heat --- CSP doesn't just use light, as solar panels do, it also uses infra-red, otherwise known as heat.)  CSP provides much more storage than batteries (1 hours compared with 4), so is much cheaper for long duration storage.  (Now called Vast Energy, the 30 MW CSP plant is yet to be started, with start-up now planned for Q2/2025.  However, they will now be co-producing green methanol at the plant as well)

Why Europe never has blackouts

 A most interesting analysis.  He shows that without wind and solar, even with maximum demand in mid-winter, the electrical grid in Europe can still cope.  He discusses storage (pumped hydro, with batteries growing fast) and the trans-Europe grid.

He makes two points.  The first is that solar is never zero during daytime, but wind can be zero for a prolonged period.  This means that Europe will still have to "burn things" to make sure it always has enough power.  This implies long-duration storage, if they are not to use gas. He mentions synthetic gas, but doesn't go into detail.  He may mean green hydrogen, or synthetic "natural" gas (green methane) made from green hydrogen via the Sabatier process.   

It seems to me that Europe needs to add more solar from sites in Southern Europe (Spain, Italy, Greece, etc), as solar's winter lows can be compensated for by excess capacity and its nighttime absence by storage.  

Renewables costs rise .....

 .... but so do coal and gas costs. 

It seemed as if Lazard had stopped producing their famous LCOE (levelised cost of electricity) calculations when they released no estimates in 2021 and 2022.  This was a great pity, because although there are others (e.g., BNEF, IRENA) who produce estimates of the cost of electricity from renewables, Lazard has been doing it on a consistent basis for 15 years.  But all at once they came out with their latest estimates a few weeks ago.  There have been some small changes in format and some additional data.  For example, they now release the LCOEs of wind and solar with and without four hours of storage.  Four hours storage is enough to take us to 80-90% renewables on a mixed grid with a blend of wind and solar.  

To reach 100% requires seasonal storage for times when it is windless, cloudy, and cold, called (who knows why?) "dunkelflaute" (pronounced doonkelflowta, which is, mysteriously, German for "dark flute")  To put it differently, there are rare occasions (10 to 20 days a year) when renewables output, even with 4 hours of storage, will not keep the grid going in the face of high demand and low renewables output.  We might only need a couple of weeks of long-term storage and only use it a few times a year, but that is prodigiously expensive using li-ion batteries (it may be much cheaper using vanadium-flow batteries, which don't suffer from "vampire drain").  

Michael Liebreich here mentions green ammonia as a fuel for long-duration storage.  I've talked about using the Sabatier process before to produce green methane, for the same purpose.  But making green ammonia is easier, because it is much easier and cheaper to extract nitrogen from the atmosphere than to extract carbon dioxide.  Lazard does not cost green ammonia for long-duration storage, so I haven't included it.  I have however estimated a wind+solar system with 10% peaking gas, in effect using natural gas as long-term storage.  Actual green methane (synthetic natural gas) or ammonia would be at least twice as expensive.   On the other hand, most of the cost of peaking gas is capital cost, because the plant and equipment has to be ready to go at all times, but it's only used for 10% (or less) of the time.  In that context, fuel cost is less important.

Lazard no longer provides an estimate of the cost of CSP (concentrated solar power), presumably because the company now developing it is in Australia.  That company, Vast Solar, is cagey about the plant’s LCOE, but describes it as "competitive".  It will provide 10 hours+ of storage, which means it's not competing directly with wind and solar with just 4 hours of storage, but with long-duration storage, which is more expensive.  $140/MWh? That's what Lazard was estimated for CSP 5 years ago.  

In addition, I have added a column for NuScale's small modular reactor, assuming 80% wind and solar and 20% SMR nuclear, and using the most recent data for its LCOE.    As the percentage of wind and solar increases in the grid, the need for long-term storage increases, especially at high latitudes, so that's where nuclear may be needed to reach 100% carbon-free generation.   Unlike the giant old-fashioned nuclear plants, the NuScale SMR can be ramped up and down (by 40% per hour), which would make it easily fit in with a mostly renewable grid.  Given the costs of long-duration storage, the NuScale SMR would be cost-effective, provided NuScale can prevent any further rise in its LCOE, which like all other LCOEs has risen sharply in response to supply chain difficulties.

As always, Lazard covers only the US.  But these markets are global, except for gas, which is much cheaper in the US than in the rest of the world.

The rise in LCOEs of renewables is mostly due to supply chain difficulties, caused by Covid and the war on Ukraine.   I suppose we can assume that these difficulties will gradually disappear, and the trend of steady declines in costs will continue.  Even as they stand, however, new-build wind and solar, with 4 hours of storage, remain cheaper than new-build coal, and comparable to new-build baseload gas (remembering that gas is a lot cheaper in the US than in Europe)  Lazard also comments that a large gap has opened up between large and small projects, with larger projects located at the bottom of the costing columns in the chart below.

All these data are before tax and subsidy and also a price on carbon emissions.

Observe that even the marginal costs (i.e., ignoring capital costs, depreciation, debt repayment and interest rates)  of coal are on average above the total costs of brand-new wind and solar farms.   A mere 10% fall in the costs of new-build wind and solar with 4 hours of storage would make them cheaper than new-build baseload gas, even in the US.  

The rise in the renewable percentage is likely to continue, even though costs have temporarily risen,

Prometheus Fuels -- petrol from water, air and electricity

Source: Prometheus Fuels

I talked about this nearly three years ago. Today, I checked back to see how this fascinating startup was going. Of course, it's all taken much longer than they were forecasting then. All the same, there seems to have been clear progress. I've taken the text below from a piece written by the founder and CEO of Prometheus Fuels.

Written by Rob McGinnis, Founder and CEO, Prometheus Fuels


As you know, Prometheus converts renewable electricity from solar and wind power into zero net carbon gasoline, diesel, and jet e-fuels (short for “electro-fuels”) that compete with fossil fuels on price. What some readers may not know is that the process we use to do this is new, is only recently possible, and is unlike anything that anyone else is doing to make synthetic fuels today. It is because of this new process that we are the only company making e-fuels that can compete with fossil fuels without new laws or subsidies — our fuels can compete simply by being better and costing less than the fossil fuels they will replace. This is a truly exciting breakthrough in our ability to solve some of the world’s most intractable problems, like climate change, energy security, and the need for increased energy-driven prosperity. But as often happens with breakthroughs of this magnitude, our process has provoked some dramatic responses - It sounds too good to be true! — and raised a lot of questions: How is it possible that your e-fuels are so much cheaper than everyone else’s? And if you can make these fuels, then where are they? Why aren’t they for sale yet? I’m here to answer these questions.

What’s everybody else doing?

If we ignore biofuels and waste-to-fuels and just focus on fuels made partially or fully from electricity from renewable sources, then everyone else who’s making e-fuels is using high temperature, high pressure synthesis. It’s been possible for almost a hundred years to make synthetic fuels from H2 and CO2 by using the Fischer Tropsch process, (invented in 1925), or similar processes that use high temperature and pressure with a catalyst to combine carbon and hydrogen into fuels. Currently, there are many companies using Fischer Tropsch or related processes that call their products e-fuels, which technically can be true if they only use electricity for CO2 capture and desorption, hydrogen generation, CO2 to CO conversion, synthesis reactions, and downstream cracking and distillation. In practice, it’s common to use fossil methane for the heat needed in these processes and to try to justify the additional CO2 this emits by promising to capture it also. Regardless of how closely they keep to the electricity-only ideal, however, none of these approaches can compete with fossil fuels on price.

What’s new about our process and why do our e-fuels cost so much less that they can compete with fossil fuels?

- Electricity is really cheap now

The first reason our fuels have such a low cost is not specific to us — it’s the recent abundance of really cheap renewable power. E-fuels are stored renewable energy. The day has long been anticipated when the cost of renewable electricity would become low enough to enable e-fuels, and that day has come. Specifically, it arrived in 2018, when the cost of utility scale solar power dropped to $0.02/kWh for the first time in a purchase by the city of Los Angeles. This marks a drop of over 90% in just ten years. The most recent record for the lowest utility scale solar bid was achieved last year at $0.01/kWh. The dramatic drop in costs is due to massive investment in solar panel manufacturing and in learning-by-doing cost reductions from making lots of solar panels. Low cost electrons mean low cost e-fuels.

- We don’t need pure CO2

The second reason our fuels are low cost, and one that is specific to us, is that we don’t need pure CO2. In order to make hydrocarbon e-fuels at scale one needs to capture CO2 from the air by direct air capture (DAC). For everyone else making e-fuels, this is a large cost. This is because their processes all require pure, pressurized CO2 gas. One obtains CO2 from the air by adsorbing the CO2 into or onto something, typically an amine liquid or amine functionalized bead, or in a hydroxide solution in water, or something more exotic, like an ionic liquid. This part isn’t so hard, and doesn’t require much energy, just a fan to blow air. In some cases, passive wind is used, but in either case, it’s not the main energy consumer.

The main energy cost is in getting the CO2 to release from the absorbent — to desorb. And that’s when things get really expensive, because this requires a lot of energy, almost always in the form of heat from burning fossil methane or a portion of the fuel produced. This is why most DAC CO2 processes cost $500-$600/ton of CO2 with a far distant and hopeful target of $100/ton at scale. But even at $100/ton CO2, any fuel one goes on to make is already too expensive to compete with fossil fuel.

At Prometheus, we don’t make or need pure CO2 gas, so we don’t need to desorb it. Therefore, we avoid the vast majority of this cost. Instead, we capture CO2 in water and then use it in water to make fuel. ARPA-E refers to this as “reactive CO2 capture” and identifies it as a significantly lower-cost DAC approach. Because our DAC tech is fundamentally different, our cost to capture CO2 is only $36/ton, the lowest in the world, and the only one low enough to enable fuel that competes on price with fossil. (More on this below.)

- We use electrocatalysts, not catalysts that need high pressure and temperature

The third reason our fuels are low cost, and another reason that is specific to us, is that we use electrocatalysts to do what only pressure and temperature could do before. The first widely read paper on this showed that CO2 in water could be turned into ethanol at a faradic efficiency of 63%. This means that 63% of the electrons that went into products in the process went into ethanol. We licensed a second-generation of this catalyst that has even better performance, making much larger and more complex carbon-based fuels with electricity alone.

Using electrocatalysts instead of the high pressure and temperature catalysts everyone else uses gives us a big reduction in cost because we can do the same job at room temperature and pressure while using much less expensive materials. It’s also great for our system performance because we can turn our process on and off quickly, matching intermittent solar and wind power. High pressure and temperature systems can’t operate like that.

- We’re the only ones who don’t need distillation

The fourth reason our fuels are low cost is that we’re the only company in the world that can replace distillation with nanotechnology to separate fuels from the water in which they’re made. In my previous startup, Mattershift, I commercialized a carbon nanotube (CNT) membrane, and published on it in 2018. Numerous academic publications have shown that membranes like this could separate alcohols from water, but until Mattershift produced them, no commercial CNT membranes were available. Previously, the only way to separate alcohols from water was to use distillation, another highly inefficient and expensive heat-based separation process. The CNT membranes solve this problem, using over 90% less energy than distillation and dramatically lowering the cost of extracting our fuel. This is a big deal because it reduces what is a major cost for other e-fuel makers to a minor cost for us.

Ok, that sounds good, but how does all this compete with fossil oil and gas?

The math on the cost of our e-fuel is pretty simple. The only inputs are air (CO2 and water) and electricity, and the only outputs are oxygen and fuel. The cost of the inputs plus the cost of the equipment and its maintenance make up nearly all of the [operating] cost. There are some other operating costs, like the vacuum pump and coolers on the CNT membranes or the power for pumps and controls, but these are less than 1% of total operating costs. I won’t include taxes or delivery fees since these vary a lot from place to place.

The main cost is electricity. The energy density of liquid e-fuels is very high, the main reason that they have long been desired as a solution for decarbonizing long-haul shipping and aviation. For gasoline, the energy density is approx. 33 kWh/gallon. In a TEA study we did last year with a third-party engineering firm, the estimate for the overall efficiency of our process (chemical energy in the fuel / electrical energy used to make it) is approx. 43%. This is a really great efficiency, because it includes everything involved from start to finish, including DAC of CO2, synthesis of the fuel, and separating the fuel so it’s ready to use. At this efficiency, our gasoline will need approx. 77 kWh of electricity per gallon. If the cost of power is $0.02/kWh, then the electricity cost of our e-gasoline is $1.54/gallon.

The next cost is CO2. The third-party TEA put our DAC cost at $36/ton of CO2 at $0.02/kWh, making it the lowest cost DAC in the world, and this cost drops further with lower costs of electricity. A gallon of gasoline contains approx. 8.9 kg of CO2 per gallon, so at a cost of $36/ton, this results in a CO2 cost for us of $0.32/gallon.

The most important cost after electricity is equipment cost, typically called capital cost. Adding up the electricity and CO2 costs, we get $1.86/gallon. If we want to stay below $3.00/gallon (for example), then we need to keep the capital and maintenance costs less than $1.14/gallon. Our cost models tell us that we can have capital and maintenance costs that are significantly lower than that, due to the advantages listed above, including not needing CO2 desorption or fuel distillation equipment, using low cost materials due to low temperatures and pressures, and deploying mass manufacturing methods like those used to make cars.

[Read more here ---the rest of the article is interesting, too.] 

The critical part of this process is the carbon nanotube membrane.  Without that, dissolving CO2 into water to produce hydrocarbons by electrolysis would be pointless, because you'd need distillation, which needs lots of energy and is expensive.  With the membrane, you just simply "sieve" the water, and the alcohols---from which petrol, diesel and jetfuel can be made---are left behind.

Petrol is currently trading at bulk at ±$2.50 per gallon, or $0.60 per litre.  So for this process to be profitable, it would need to have a capital and maintenance cost below $0.50 per gallon.   Except, that, if this works, then it will qualify for carbon credits.  For example, at a carbon price of $50/ tonne of CO2 emissions, a carbon credit would be worth roughly ±$0.45 per gallon.   For each $10 rise in the carbon price, petrol prices will rise by roughly 10 cents a gallon. 

More to the point, long-distance air and sea transport is still not possible with batteries, though it may well be in 10 years from now.  Also, fossil fuels will provide long-term storage for the grid---diesel generators using green diesel will be able to back up the grid.  We wouldn't have to worry about "dunkelflaute"---when it's cold and still and dark, so electricity demand is high but renewables supply is low.  

Let's hope that this process does work and that it soon scales up.  In my opinion, it looks as if we're still a couple of years away from commercialisation.  But by then, the pressure to de-carbonise will only have grown, as El Niño drives global temps towards the 1.5 degrees above pre-industrial times.

Westinghouse's new SMR

 From Reuters

U.S. company Westinghouse unveiled plans on Thursday for a small modular reactor to generate virtually emissions-free electricity.

Rita Baranwal, the Westinghouse Electricity Co's top technology officer, said the reactor, dubbed AP300 for its planned 300 Megawatt capacity, will not use special fuels or liquid metal coolants unlike some other next-generation reactors.

It will be a smaller version of its AP1000 reactor, several of which are operating in China, and which are ramping up in Georgia at the Vogtle plant, after years of delay and billions of dollars over budget.

Despite hurdles for new nuclear, Baranwal was confident. "We've kept it simple, designed it on demonstrated and licensed technology, and I think that's one of the advantages that we have with this concept," she told Reuters in an interview. Westinghouse, owned by Brookfield Business Partners, plans to start constructing the reactor by 2030 and have it running by 2033.

Small modular reactors (SMR) are meant to fit new applications such as replacing shut coal plants and being located in more remote communities. President Joe Biden's administration believes that maintaining existing nuclear plants and developing next-generation reactors is crucial for its goal of decarbonizing the economy by 2050.

So far the design for only one SMR, planned by NuScale Power Corp, has been approved by U.S. regulators and it still needs permits.

Westinghouse did not reveal how much the first reactor would cost, but said later units would cost about $1 billion. The company, based in western Pennsylvania, has had informal talks with parties in neighboring states Ohio and West Virginia about the potential building of AP300s at former coal plants.

Westinghouse also hopes to sell reactors to countries in eastern Europe, even though nuclear power critics have expressed concerns that developers and governments should think carefully before building new nuclear plants anywhere near the region. They noted that Russia took the Zaporizhzhia nuclear power plant in Ukraine, the site of repeated shelling.

Baranwal said Russia's actions have made countries motivated to become more energy independent and the AP300 will be passively safe because it does not need power supply or human intervention for 72 hours in the event of an incident.

Westinghouse also sees potential customers in sub-Saharan Africa, which could bring electricity for the first time to some areas.

The company is not sure yet whether the technology can be exported to China, where the first AP1000s began operations in 2018. That year, former President Donald Trump's administration issued restrictions on exports of nuclear technology newer than the AP1000 due to nuclear proliferation concerns.

Baranwal said if the U.S. government deems AP300 to be a subset of the earlier reactor technology "then we can start entertaining the possibilities" of exporting it to China.

It sounds good, except ......

For 1billion, we'll get 300 MW of electricity.  So, let's assume a 90% capacity factor, a 30-year life, zero fuel and maintenance costs, and an interest rate of zero.   Cost per MWh of output would be 1 billion/(300*365*30*0.9), or a breath-taking 338/MWh, more than ten times the cost of wind or solar.  

In addition, it won't be available until 2033.  And we need to have mostly switched over to zero carbon electricity generation by then.   

So, too late and too expensive.

Society might be willing to pay for nuclear for the last 10% of generation after we have replaced coal with wind, solar, hydro, tide and wave power, but this is very expensive.  Using gas for 'dunkelflaute' periods (when it's dark and cold and still) will produce emissions, but synthetic natural gas (which won't) made by the Sabatier (or some other) process will be cheaper than this SMR.   One rather gets the feeling that this project has been concocted to attract subsidies from the government, rather than a real commercial enterprise.

All the same, it makes sense that governments should buy SMRs, from varying suppliers and of varying technologies, because they might work, and if they do they'll make our grid more stable, plus unlike the infamous Vogtle nuclear plant, the total cost will be limited.

Record renewables in Australian grid

Even with relatively calm days producing the lowest recent quarterly utilisation rate, total wind farm output exceeded any previous December quarter. Photograph: Russell Freeman/AAP

From The Guardian

Milder temperatures and record levels of renewable energy drove [net] electricity demand to its lowest levels for any December quarter, according to the Australian Energy Market Operator.

Wholesale power prices also retreated during the period, particularly after the Albanese government imposed price caps on black coal and gas that are used to generate power, AEMO said in its quarterly report released on Wednesday.

“Electricity futures prices saw steep falls in the mainland states through to the end of the quarter” after the price limits were imposed on 9 December, said Violette Mouchaileh, an AEMO executive.

The average price of $93/megawatt-hour across the national electricity market (NEM) that serves eastern Australia was less than half the $216/MWh cost in the September quarter. Still, it was almost 80% higher than for the final three months of 2021.

Renewable energy from wind, solar and hydro supplied an average of 40.3% of power in the NEM, a record for any quarter since the NEM started in 1998.

It exceeded the previous high, set a year earlier, of 35.8%, AEMO said.

The tail end of the third La Niña event in as many years trimmed power demand for daytime air-conditioning.

A 16% increase in electricity output from rooftop solar panels, or 410MW on average, also decreased demand from the grid.

As a result, [net] operational demand fell 2% from a year earlier to an average 19,431MW, the lowest December quarter reading. New record lows for a quarter were set in South Australia, Victoria and New South Wales, while the 11,892MW use on 6 November was a new low for the NEM in the December quarter.

Power generation from black and brown coal-fired plants was the lowest since the NEM started. Higher prices for the fossil fuel in Queensland and NSW – at least before the price caps began – was one factor for the reduced use but also plant failures, particularly in Queensland.

Increased output from renewable energy, with its near-zero fuel cost, also nudged more coal and gas out of the generation market.

New instantaneous renewable penetration records were set in the NEM at 68.7% on 28 October – up 4.6 percentage points on the previous record – and in the Western Australian market at 84.3% on 12 December, up 3.7 percentage points. The records were “largely driven” by rooftop solar, AEMO said.

During a fault that cut South Australia off from other states for several days in November, renewables’ share of generation peaked at 91.5%.

“Output from wind and grid-scale solar grew strongly as new facilities were connected and commissioned,” AEMO said. Even with relatively calm days producing the lowest recent quarterly utilisation rate, total wind farm output exceeded any previous December quarter.

The percentage of renewables in the Ozzie grid is rising by rough 5% per annum.  At this rate, by 2035, we will have reached 100%.  However, the opening of new offshore wind farm lease areas off the cost of Victoria will most likely accelerate the switch.   We will still need some gas backup for cold, cloudy, windless days ("dunkelflaute"), which on average will be about 5% of total output.   Until, that is, we find a cheap means of long-term storage, such as molten-salt storage (CSP) or power to gas.   So the practical limit for non-hydro renewables now is prolly 85%.   And we could reach that by 2030.

It's dark, it's still, it's dunkelflaute

 From Energy Networks

Whether you’ve heard of it or not, dunkelflaute (dunk-el-flout-eh) is a challenge our energy systems will need to manage. Dunkelflaute is a German word that literally means dark doldrums or dark lull. It describes events where there is minimal or no sunshine and wind for extended periods, usually occurring during winter. Dunkelflaute is a specific problem of low electricity output that occurs in highly-renewable electricity systems. The challenge it presents is obvious – how to guarantee electricity supply when the dark lull descends?

In Australia, this has been referred to as a renewable drought. A recent lull in wind generation in South Australia is a small-scale snapshot of what could become a much larger problem in future.

AEMO data (via Open NEM) shows that across 11 and 12 June, wind power (represented by green in Figure 1 below) generated fewer than 4,800 MWh of a total demanded 55,000 MWh, only 8.7 per cent of total generation. This is compared with 9 and 10 June when wind power generated 46,000 MWh out of a total demanded 73,000 MWh, contributing 63 per cent to generation.

 

Germany is in a similar position as South Australia in terms of renewable penetration. Renewable electricity in Germany contributed 45.4 per cent of electricity consumption in 2020, more than coal, oil and gas combined. Germany also has significant transmission connection with the EU, possessing more interconnectors than any other country in Europe.

In Germany there is a growing fear of dunkelflaute as the share of renewable generation increases and displaces dispatchable generation. The type of event to cause dunkelflaute doesn’t have to be severe weather like we saw in Texas in February. It can be as benign as several still winter days in a row. 

How do we manage dunkelflaute?

A recent Grattan Institute report Go for net zero referenced dunkelflaute as ‘the winter problem’. In the document, Grattan notes that an energy system with 90 per cent renewable electricity would reduce emissions by 105 million tonnes at a cost of less than $20 per tonne. The final 10 per cent, however, is much trickier to achieve because the electricity system must increasingly rely on firming options.

The immediately available electricity storage option that might come to mind is batteries – but batteries tend to be best suited to managing hourly fluctuations across the day, charging from the midday sun and then discharging to help with the evening peak. Today’s batteries are not well placed to manage longer durations, with most having less than four hours of storage. The Victorian 300MW Big Battery project in Geelong is slated to be able to provide electricity to 400,000 households for one hour at full charge. That may be big but managing dunkelflaute will require a much bigger battery.

Broadly, there appear to be three options that could assist the transition from 90 to 100 per cent renewables.

Lots of renewable generation and transmission

The first is building a diverse renewable generation fleet all across the country in hopes that the wind is blowing or sun is shining somewhere, while ensuring sufficient interconnection to transport large quantities of electricity all across the country. This option would result in a large amount of electricity being ‘wasted’, along with lowering the utilisation of interconnection, while still leaving room for dunkelflaute in severe cases.

There is a positive correlation between solar energy across the National Energy Market (NEM) . When the sun is shining in one area, it is also likely to be shining in others, and visa versa. The absence of solar energy in one region may not be easily replaced by solar in another as different regions can be affected by similar weather systems.

Deep storage

The second option is building deep storage, like pumped hydro, that by its nature is well placed to provide storage capacity. Snowy 2.0 for example will be able to provide 2000 MW of generation capacity for 175 hours at full capacity. Grattan has modelled that across a 10-year period, up to 9GW of storage capacity might be required to bridge the largest gap between renewable generation and demand over 14 days. That’s about nine Snowy 2.0’s assuming they all start at full capacity.

This type of deep storage solution is likely to sit idle most of the time and could be challenging to finance, with Grattan rightly noting that many optimal sites for pumped hydro have already been developed. Additional interconnection would also be required to connect this deep storage, which may again be poorly utilised.

Developing this much deep storage is likely to be incredibly costly and unlikely to be in customer’s best interests.

Zero emissions dispatchable energy

The third and most promising option is building zero-emissions dispatchable energy, consisting of renewable gas usage in gas powered generation plants. Natural gas already provides a similar role in today’s generation mix and renewable gas will allow much of the current infrastructure to be utilised to support high levels of variable renewable electricity generation.

Frontier Economics examined the role of gas powered generation in South Australia during renewable droughts to support a highly-renewable system and found that using gas powered generation could reduce the overall system cost by between 28 to 35 per cent per year, depending on the extent of the renewable drought during winter.

Figure 3 – Indexed systems cost for 2030 and 2035 – South Australia (Source: Frontier Economics (2021), Potential for gas-powered generation to support renewables)

The optimal level of gas generation was found to be seven per cent of total generation. If natural gas can be substituted by renewable gas into the future, it’s likely that full decarbonisation can be achieved by utilising existing infrastructure and lowering overall costs.

 

Managing the winter lull

Dunkelflaute is a challenging problem that requires detailed planning and mapping of the electricity system and usage throughout the year, rather than relying on averages that are more commonly talked about.

There are a range of technical options available to manage dunkelflaute. Batteries and pumped hydro can be good options for managing hourly and daily fluctuations in demand, but there are questions over longer durations. Shorter-term storage is likely to best be complemented by renewable gas electricity generation to manage longer periods of low variable renewable generation.