Shining Sun, Blowing Wind

…when the sun doesn’t shine and the wind doesn’t blow.

You’ve surely read such a phrase in any number of articles about supplying climate-friendly electricity to households and economies. Me, I roll my eyes every time I see it, no matter who the author is, but that’s mainly because it has to already be numbingly obvious that sometimes it’s cloudy or nighttime or calm.

Yet you wouldn’t know it from headlines like

This and articles like it invariably rely on significant dispatchable hydro but you wouldn’t know it from the choice of image.

or hot takes like

More than 150,000 [rooftop PV] systems installed in the last year alone would produce enough energy for 226,000 homes.

Why not? Because of last night on the mainland, for example:

Care of Tomorrow.

That’s an average of 91% fossil fuels supplying the evening’s electricity, with most of the remainder from existing hydro. The perseverance of solar and wind development in Australia is absolutely commendable, but even with all current projects completed this picture from last night would barely change.

Renewable energy advocates (and I count myself as one) were cautioned at the beginning of the year to be mindful of the reality of energy supply systems. When the triumphalism shown by advocacy groups like GetUp eventually fails to translate into rapidly diminished fossil fuel consumption at those times when the sun’s not shining and the wind’s not blowing, the resulting cynicism might make the “Tony Abbott years” not seem so bad by comparison.

GetUp heralds Australia’s progress with renewable energy as “the end of the era of big polluting energy companies dominating the market” but the growing awareness of waste and pollution also generated directly by the big overseas manufacturers of their favoured alternative energy sources must be addressed, not ignored just because it’s not happening here.

I’ll conclude with official data on annual shares from Australia’s technology mix.


Comparing Like for Like

Since you’re reading this blog, you’ve almost certainly encountered this claim:

We don’t need nuclear because we can use renewables.

For renewable sources like geothermal and hydroelectric this may apply, since they can provide guaranteed generation around the clock. But the former has been abandoned in Australia and both can meet only a small portion of our future requirement for climate-friendly electricity.

But in truth the claim invariably refers to solar and wind, not all renewables. For a scalable technology like solar power to hypothetically meet such a demand profile, storage is implicitly included, or at least invoked upon inquiry. David Green of Lyon Solar described it well:

If we really want to address the penetration of large-scale renewables – and not just be able to satisfy the market you can connect large-scale batteries onto the grid – you need to be able to demonstrate that power generated from renewables can be dispatched with power from the batteries like base-load power, so it’s not creating problems.

However, the size of Lyon’s projects instead indicate a peak demand role in the power market. The megawatt hour (MWh) capacity of their batteries are too limited to supply constant overnight power (not to mention the unlikely economics of supplying at low overnight prices). So the question still remains, what would that look like, and how would it compare to the modern nuclear energy technology some believe it supercedes?

Simplified capital costs over time

In this thought experiment, we’ll use

By multiplying the number of 50 MW class solar plants to ensure that excess generation above this number equals overnight requirements, an idealised “solar+storage plant” can be modelled. Slightly more than 3 Broken Hill-sized plants would be needed but we’ll assume three for simplicity. Similarly, operational costs are excluded for both technologies.

Thus, we can compare assumed overnight capital costs for a NuScale plant, 60 year design life, and twelve solar+storage plants which would hypothetically match its nameplate capacity. As mentioned in the Finkel Review, the lifespan of lithium ion technology is 10 years so the cost of regular replacement has been factored in, in addition to renewal of the solar panels after 30 years (assumed to be half today’s cost).

When the capabilities of the two technologies are hypothetically levelised in this simplified way, it appears that the specific argument on cost is reversed.

Estimated required land area

The area of Broken Hill solar plant is 140 hectares. Thirty-six such plants will need about 5,000 hectares, only slightly smaller than the area of Sydney Harbour. However they don’t all need to be co-sited.

NuScale’s plant, which is now under formal design and licencing review by the US Nuclear Regulatory Agency, will cover a little over 36 hectares, including its maximum required emergency planning boundary. It can essentially be situated anywhere that would be suitable for an industrial facility, as water is not necessary for operational cooling. Notably, other options may well be available for the 2030 timeframe.

Material requirements levelised by generated energy

The US Department of Energy 2015 Quaternary Technology Review estimated various levelised material requirements for major electricity sources. Additionally, silver and uranium requirements can be authoritatively sourced. Charting these estimates illustrates the difference in amounts of materials needed by solar and nuclear, for the same amount of electricity produced.

This doesn’t include the materials like lithium, graphite and cobalt needed for the batteries, which aren’t a power source. It is assumed that materials needed for iPWR (intergrated pressurised water reactor) type SMRs are sufficiently similar to conventional PWRs.

This thought experiment attempts to match solar energy capability to that of nuclear. It hardly needs to be said that the reverse is a much less valuable exercise. Cyling a collection of SMRs daily between 0% and 100% output (with considerably less in poor weather) makes little sense in many ways, not least of which is the consequence of diminshed emissions abatement in a system still overwhelmingly supplied by coal and gas combustion. The whole benefit of including nuclear energy sources is they represent a drop-in replacement for dispatchable fossil fuel fired generators.

There are also commercial scale examples of battery storage paired with wind farms, such as the facility in Rokkasho, Japan. The particular battery chemistry used – sodium sulphur – was recently evaluated in California with sobering results.

We won’t compare the potential emissions savings since authoritative research puts solar and nuclear both at desirably low factors. However, the extra material intensity of batteries may contribute dramatically to lifecycle emissions, depending largely on their country of manufacture.

Solar plants and battery modules can be installed rapidly. In contrast, a certain first time regulatory cost and lead-time for that nuclear plant is unavoidable. Yet it isn’t necessary to overstate this hurdle. In its submission to the South Autralian Nuclear Fuel Cycle Royal Commission, Engineers Australia observed that ANSTO’s OPAL research reactor is of similar size but greater complexity than an SMR unit, and concluded:

The OPAL development at Lucas Heights provides an excellent management example for an SMR nuclear power station in South Australia. Extensive international guidance is available from the IAEA to assist in establishing a nuclear power program…

Australia already has a competent and very well managed regulatory regime with staff with wide international experience. Many of the ARPANSA staff have extensive experience in operating nuclear power plants both civil and military. There is no fundamental reason why the ARPANS Act 1998 cannot be amended to include the regulation of nuclear power in Australia.

The results illustrated here should not be taken as any reason not to build solar, especially paired with storage so as to shift generation to meet high demand, like Lyon Solar’s projects. The importance of this was underscored in the Finkel Review.

However, excluding nuclear energy, with its specific supply profile that can’t realitically be emulated by a variable source like solar, is probably unjustifiable on grounds of cost, land use, material intensity or regulatory challenges. This isn’t intended to downplay the regulatory and public education headwinds the technology faces, but rather to emphasise how important it is – considering the results here-in – to face them now and seriously begin the process. As the Engineers Australia submission noted:

The utilisation of a mix of all low emissions electricity generation technologies will be essential to achieve long-term greenhouse gas emissions targets.

What can be more serious than achieving targets that are aggressive as possible with everything available?


Levelised Cost of Electricity – a Few Thoughts

Following on from the previous article regarding the misuse of metrics, this article is a guest post by Keith Pickering. More of his analysis and commentary can be found at Daily Kos.

A few thoughts on LCOE, Levelized Cost Of Electricity.

The first thing to realize that LCOE is, and always has been, an investment tool, designed for investors, to aid investors in energy markets make investment decisions. And when LCOE is used for that purpose, it is (usually) appropriate.

The problem comes when we want to use LCOE to make public policy decisions, which can (and usually do) have a different set of decision parameters than financial investment. One obvious difference is in asset lifetime.

For example, the US Energy Information Agency publishes LCOE estimates every year, and while they do a pretty bad job of explaining how they compute things, one thing they do say is that for all energy types they use a lifetime of 30 years. Why? Because banks don’t make loans for longer than 30 years, that’s why. Now if you’re considering whether to loan money to an energy project, that 30 year lifetime makes perfect sense. But if you’re planning an energy infrastructure for half a century or more, the 30-year lifetime in your LCOE calculation will systematically undervalue long-lifetime assets (like nuclear and hydro) and systematically overvalue short-lifetime assets (like wind.) Using a 30-year lifetime implies, essentially, that generating assets with a lifetime of more than 30 years will have zero asset costs during their lifetimes beyond loan payoff. Essentially that pretends that the electricity cost would *drop like a stone* to extremely low levels at the 30 year point. But those really low future electricity costs are *never reported* in LCOE; the assumption is just left out there, unmentioned.

Another thing to realize is that a key component in all LCOE calculations is the “discount rate.” Basically, the discount rate is the annual rate of return investors would expect to get on a properly valued asset. If the discount rate is high, investors want their money back right away. High discount rates value the present highly, while discounting the future strongly. High discount rates therefore penalize technologies that rely heavily on long-term fixed assets (once again, hydro and nuclear.)

Discount rates are used elsewhere too, for example in computing the Social Cost of Carbon (SCC). If you’re taking the long view, a low discount rate values the future more highly. For that reason, climate hawks like to use low discount rates when computing SCC, because that computation raises carbon cost. The carbon we emit today will continue warming the earth for centuries, and will continue to cause damage for that entire time. The lowest possible discount rate will capture (some of) that future damage and value it when computing SCC. The US government currently uses a 3% discount rate when computing SCC. And even that may be too high, when you consider the entire lifetime of CO2 in the air.

To be consistent, then, us cliamte hawks should also press for an equally low discount rate when computing LCOE; that is the socially responsible way to value the future in the face of long-term climate change. But EIA uses a Weighted Average Cost of Capital (which is the discount rate by another name) of 5.5%, nearly twice the rate used in computing SCC. That doesn’t mean it’s wrong; for an investment tool, it’s appropriate. But again, if you want to use LCOE for policy purposes, there are other things to consider.

The investment management company Lazard publishes their own LCOE results every year, and every year the low-low LCOE of wind is caressed and trumpeted by certain wind-loving types. It’s no coincidence that Lazard is heavily involved in wind energy stocks, and has skin in the game as far as wind energy is concerned. The Finnish blogger Jani-Petri Martikainen has already cataloged some of the many thumbs Lazard puts on their scale to favor wind, and it’s no surprise that jacking up the discount rate is one of them: Lazard’s rate is a whopping 9.6%, which immediately rockets high-asset technologies (like hydro and wind) way up in price. Then they lower their LCOE (for wind only) by assuming hugely unrealistic (55% !!) capacity factors for wind. The net result is that Lazard’s bottom-line wind numbers look about like EIA’s (so they can reassure their customers that they’re doing it right) while all other technologies are way too high. It’s utterly deceptive, but they apparently hook the investors they’re trolling for.

Another good LCOE resource is the OpenEI Transparent Cost Database, which is a meta-analysis of everybody else’s LCOE, but with homogenized parameters for tax rate, discount rate, and capacity factors for the various technologies. Unfortunately it looks like it hasn’t been updated in more than a year now, but it does have everything spreadsheeted out, which lets you examine the calculations and play around with the assumptions. With OpenEI’s standard parameters, nuclear already looks appropriately cheap, even in the first thirty years. And if you count the second thirty years of expected plant life, it’s no contest.

The Hornsdale wind farm in South Australia operates under a tariff agreement with the Australian Capital Territory worth $77 per megawatt hour. In the absence of this arrangement, it would derive revenue from selling Large-scale Generating Certificates as the majority of incentivised renewable generators do in Australia. Stage 2 was completed in 2016, adding 100 megawatts for $250 million. For comparison, the cost of the first 100 megawatt stage at Snowtown in the same state in 2008 was $220 million – practically the same, adjusted for inflation. The impact of adding to so much wind capacity on system strength in South Australia, as identified in the Finkel Review, is not accounted for in the tariff. However, Hornsdale stage 2 is trialing a method to supply Frequency Control Ancillary Services to the market.

One final word about cost. You often read about some contracted electricity price for some new installation (typically solar) that is impressively low. These Power Purchase Agreements (PPAs) are common in the industry, but you should be aware that PPA price is always lower than LCOE. That’s because a PPA does more than transfer energy: it also transfers risk, from the seller to the buyer. If you want to build a new generator (of any type), you’re taking different financial risks: the risk that the project will never get built, and the risk that you won’t be able to sell the electricity, or not for the price you need. Banks understand these risks and set the interest rate on the loan accordingly. When a PPA is signed, the first part of that risk (that it won’t get built) has already passed, because as a general rule a PPA isn’t signed until the generator is already built. And when a PPA is signed, the second risk component (not being able to sell it, or for the right price) has also been eliminated. With a newly signed PPA in hand, the generator owner can re-finance his loan to a very, very low rate, because at that point the risk is almost completely gone. The buyer of the electricity (the other party in the PPA) has assumed the risk that the price he’s paying on the PPA will be lower than the price he could have gotten elsewhere on the wholesale spot market. Because the buyer is assuming that risk, he expects a lower price than he otherwise would have gotten; and because the seller is shedding that risk, he’s willing to sell at a lower price too. Generally, a PPA price is about what LCOE would be if the discount rate were close to zero.



Many thanks to Keith for this clarifying commentary. I added the description of Hornsdale wind farm to help illustrate it with real world Australian context.

For the reasons mentioned above, and as it’s so heavily relied on by anti-nuclear campaigners, I avoid using Lazard’s analysis on this blog. But its latest edition included this piece of important guidance which many would be wise to take on board.

Even though alternative energy is increasingly cost-competitive and storage technology holds great promise, alternative energy systems alone will not be capable of meeting the baseload generation needs of a developed economy for the foreseeable future. Therefore, the optimal solution for many regions of the world is to use complementary traditional and alternative energy resources in a diversified generation fleet.


(Mis)use of Metrics & (Ab)use of Arithmetic

Source: REN21

The levelised cost of electricity – LCOE – is defined as the total cost per kilowatt hour of electricity accounting for the installation, operation, maintenance, financing, taxes, decommissioning, and other minor considerations for a given technology over its operating lifetime. LCOEs are routinely presented to compare different sources of electricity – unfortunately often when someone wants solar or wind energy to appear cheaper than nuclear energy.

It’s being increasingly recognised that LCOE doesn’t suit this sort of comparison. Important factors which aren’t accounted for, according to Aurora Energy Research, include market value, realistic generator performance and the value of storage technologies.

Furthermore, as explained by the IEA and NEA:

The LCOE methodology was developed in a period of regulated markets. As electricity markets diverge from this origin, the LCOE should be accompanied by other metrics when choosing among electricity generation technologies.

Probably the most important of these other metrics excluded from LCOE calculations is capacity credit, which is a function of the intermittent nature of the “fuel” for some technologies in the context of the demand on the grid. To take the IEA definition:

The capacity credit is the peak demand less the peak residual demand, expressed as a percentage of the variable renewables installed. For example, if 10 GW [gigawatts] of wind power plants are installed in a region, and their capacity credit is 10%, then there will be a reduction of 1 GW in the amount of other plants required, compared to a situation with no wind capacity. This is due to the weather-influenced output of variable generators (generally wind and solar, and also wave and tidal).

Clearly, if a 1 GW nuclear power plant is installed and operated well in the neighbouring region, it’ll replace 1 GW of, ideally, fossil fuel energy. The extraneous issue of its “waste” – which has no climate impact – will be capably solved through recycling and repositories without burdening our decendants.

Contrast the way the LCOE metric is used (or misused) to a rather different metric, the greenhouse gas lifecycle assessment – LCA:

There are many sources for LCAs of practically every generation technology, but arguably the most authoritative is provided in comprehensive meta-analyses by the US National Renewable Energy Laboratory.

Advocates of nuclear energy as a tool in climate action persistently cite this sort of authoritative metric, and one crucial thing should be recognised: they don’t exclude renewable energy sources by doing so.

Such advocates, exemplified by the 75 leading conservation scientists from around the world, who in 2014 implored environmental groups to reconsider nuclear energy, recognise the importance of not excluding any proven or promising options.

The NREL LCA for nuclear energy – already a very low emissions power source – analysed fast breeder reactors in supplementary material, finding a median value of 0.87 gCO₂-e/kWh, the lowest of all. This is mainly because they wouldn’t require mining for their fuel.

BN-800, an operating fast reactor in Russia. It runs on decommisioned nuclear weapons.

This is why such advocates are determined to include this option. And while the IEA’s example of wind energy may have a tenth of the supply capacity with over 10 times the median LCA emissions (on paper), they certainly don’t want it excluded.

And of course, it’s not just electricity. Take another look at that REN21 chart. Still nearly 80% fossil fuels to meet total energy demand – who exactly wants to limit our tools to just “cheapest” wind? Please be wary of anyone who does.


Speeding Up the Roadmap

*only these, but absolutely loads of them

Energy Networks Australia and the CSIRO have released the final version of their roadmap for transforming Australia’s energy supply, to the usual fanfare that these things receive. If you’re not keeping close track, yes it’s different to the efforts from ClimateWorks and from GetUp, amoung various others. Why do there need to be so many anyway?

Anyway, the headline chart illustrates the phase out of coal, then gas, with build up of solar and wind to simply supply all of the terawatt hours we’ll need in 2050 (a terrawatt hour, TWh, is a billion kilowatt hours). Well it certainly looks simple, and at the very least we can seperate out the wedges of renewable energy and take a closer, more critical look.

Analysed the old fashion way: pixels to TWhs.

Large solar PV

In other words, solar farms like the 102 megawatt (MW) Nyngan plant in NSW, which apparently generates about 230 million kWh per year. Judging by the shape of the dark blue wedge, enough of these need to be built by around 2035 to supply 45.6 billion kWh in that year. So that’s roughly 198 farms of that size. We already have Nyngan and a couple of other large solar farms which add up to at least the same output, so make it 196 solar farms in 18 years, or just about 11 per year. Starting now. Then, towards the end of the 2040s, we’ll need to roll our sleeves up again and start replacing these farms as they reach the ends of their expected service lives.

Wind onshore

Again, at around the 2035 mark the light blue share of wind energy is set to begin expanding fast. How fast? To about 183.3 billion kWh through 2050, supplied by the equivalent of 172 windfarms the size of the 420 MW MacArthur wind farm in Victoria (Australia’s largest) at the national annual capacity factor for wind. With 15 years left to build them, we’ll need the equivalent of eleven and a half per year. This is well over 10 times faster than wind has been built in the last decade. Perhaps we can count some of Australia’s existing windfarms at the start of this period, but the fact is most of them will be reaching or passing the end of their rated lifespans in 2035.

Rooftop PV

By the Australian Photovoltaic Institute‘s upper estimate, there was a total national installed rooftop solar capacity of 5,968.341 MW in March this year. Ignoring the need for replacement by 2050 (let’s face it, nobody’s thinking about that anyway) and at the normal 15% annual capacity factor for Aussie rooftops, this is set to grow to 90,650 megawatts (to account for an annual 119.1 billion kWh supply) within 33 years, representing a monthly addition rate of close to 415.5 MW (it’s presently a bit over 60 MW/month) which would look like this:

The arrow indicates today, when we need to start adding rooftop solar capacity almost three and a half times faster than we have in the last year. And not stop for 33 years. Data: APVI

The APVI also keeps track of the current proportion of Australian dwellings with rooftop solar by state. Simply scaling up these figures to roughly 100% for each state (i.e. tripling Queensland and South Australia, up to 10x for Tasmania and so on) yields 25,857 MW. That’s allAustralian rooftops with solar. Obviously we either need more houses or much bigger rooftop systems (probably both), however the CSIRO/ENA’s document is specific about assuming no further subsidies to incentivise addition, so all else being equal it’s not obvious why an individual household would install any more than the kW capacity that covers its own needs.

Two issues are left entirely unaddressed by the headline chart:

  1. A kWh of solar or wind doesn’t serve the same sort of demand as a “conventional” kWh, say from a gas power plant. The hundreds of billions of renewable kWhs appear to more than cover for coal and gas in 2050 at an annual timescale, but week-to-week, day-to-day supply is a different matter. Something more is obviously required when the weather won’t oblige.
  2. Storage of energy is the obvious solution on paper, and CSIRO/ENA foresee a plausible national capacity of 87 million kWh of batteries in 2050. Consider this figure against the 52,000 kWh installed in 2016, and the limited lifespan of these devices (even hoping for 15 years, this would require 5,800,000 kWh worth of battery capacity installed annually till 2050). This is precisely the approach critiqued in the recent review of 100% renewable energy scenarios by Heard and co-workers:

A common assumption is that advances in storage technologies will resolve issues of reliability both at sub-hourly timescales and in situations of low availability of renewable resources that can occur seasonally.

Battery storage is undeniably wrapped in buoyant optimism these days, even though recent large scale operational experience in California points to serious limitations. Additionally, the issue of lifecycle (generally only 10 years for lithium ion) emissions is almost universely neglected in “net zero carbon” scenarios which rely on battery storage. And ultimately, as recently stated by no less than Lazard:

Even though alternative energy is increasingly cost-competitive and storage technology holds great promise, alternative energy systems alone will not be capable of meeting the baseload generation needs of a developed economy for the foreseeable future. Therefore, the optimal solution for many regions of the world is to use complementary traditional and alternative energy resources in a diversified generation fleet.

To be entirely fair to the authors, the document contains some useful assumptions about future energy usage in Australia. It’s certainly worth a flick through. And they do try to account for the required build rate, however it isn’t quite as clear as starting a major new solar farm or wind farm virtually every month for the next three decades, and beyond, like I’ve elucidated here.

Is the future of 2050 sufficiently far from foreseeable? How close do we get before we critically and honestly examine our progress, or lack thereof, and potentially reconsider other energy resources we initially chose to exclude? And how ambitious is 2050 anyway – when including all low carbon resources now may well significantly speed things up, if history is any guide?