First SMR in a G7 country

Construction of its first SMR (Small Modular Reactor) has started in Canada.    I've talked about SMRs  before, but have been sceptical.    But I've also said that high latitudes will probably need nuclear power, because solar is so variable from summer to winter. 

The electricity from this SMR is forecast to have an LCOE (levelised cost of electricity) of about US$108 per MWh, and completion is expected by 2030.  Nuclear power stations tend to come in late and over budget, so we'll see whether this one is any different.  If it is on time and under budget, there will be many more built.  Even in countries in lower latitudes, adding another power source to the grid will make the grid more stable and easier to manage.

From CBC

Premier Doug Ford's government has given Ontario Power Generation the green light to start construction on Canada's first small modular reactor, a new nuclear energy technology to be built next door to the Darlington power plant. 

The small modular reactor (SMR) would provide 300 megawatts of power, enough electricity to supply about 300,000 homes, according to briefing documents from Ontario's Ministry of Energy and Mines. 

It would be the first of four such reactors that OPG aims to build on the site, at a total project cost of $20.9 billion, in an effort to meet what's forecast to be a steep rise in demand for electricity in the province.

The estimated construction cost of the initial reactor is $7.7 billion, which includes $1.6 billion of infrastructure to be shared across the project.

"Ontario needs more power, I think we understand this problem today. When you turn the lights on in your living room you may not think about where that power comes from," said Stephen Lecce, Ontario's minister of energy and mines, on Thursday.

"But ensuring that we have reliable, affordable energy is essential to the economic sovereignty of our province and country," he continued.

Lecce made the announcement near the Darlington nuclear generating station. Preparation work has already begun at the project site, immediately east of the existing nuclear plant along the Lake Ontario shoreline. 

The province's electricity system operator recently estimated that demand for power across Ontario is set to increase 75 per cent by 2050.

"As it stands today, we just don't have the supply to meet that demand," Lecce said.

In a briefing, ministry officials told reporters that roughly 80 per cent of the SMR project spending will go to Ontario companies, another 15 per cent to European and Asian firms, and just five per cent to companies in the U.S., primarily for GE Hitachi's design and development of the power plant model, called the BWRX-300. 

Ontario would become the first place in the world to build the BWRX-300, which is a smaller version of GE Hitachi's existing boiling water reactor technology.

The officials say the Canadian companies involved in the project will have the potential to export components to other countries that decide to build this type of SMR. 

The timeline is to finish construction of the first reactor by the end of 2029, and connect it to the grid in 2030.  

The average lifetime cost of electricity generated by the SMRs is estimated to be 14.9 cents per kilowatt hour (kWh)[C$149/MWh, US$108/MWh], according to an analysis by the Independent Electricity System Operator, the provincial agency that oversees the provincial grid. 

According to that analysis, providing a similar level of base power as the SMRs by building wind and solar power with battery energy storage would cost in the range of 13.5 to 18.4 cents per kWh. However, that alternative would require additional transmission, use up far more land and potentially face constraints in finding acceptable sites. 

A concept image of a GE Hitachi BWRX-300 small modular reactor (SMR), the nuclear technology Ontario Power Generation is using for its new project adjacent to the existing Darlington nuclear plant. (GE-Hitachi)

 

Nuscale SMR costs jump to $119/MWh

From IEEFA

Last week, NuScale and the Utah Associated Municipal Power Systems (UAMPS) announced what many have long expected. The construction cost and target price estimates for the 462-megawatt (MW) small modular reactor (SMR) are going up, way up.

From 2016 to 2020, they said the target power price was $55/megawatt-hour (MWh). Then, the price was raised to $58/MWh when the project was downsized from 12 reactor modules to just six (924MW to 462MW). Now, after preparing a new and much more detailed cost estimate, the target price for the power from the proposed SMR has soared to $89/MWh.

Remarkably, the new $89/MWh price of power would be much higher if it were not for more than $4 billion in subsidies NuScale and UAMPS expect to get from U.S. taxpayers through a $1.4 billion contribution from the Department of Energy and the estimated $30/MWh subsidy in the Inflation Reduction Act (IRA).

It also is important to remember that the $89/MWh target price is in 2022 dollars and substantially understates what utilities and their ratepayers actually will pay if the SMR is completed. For example, assuming a modest 2% inflation rate through 2030, utilities and ratepayers would pay $102 for each MWh of power from the SMR—not the $89 NuScale and UAMPS want them to believe they will pay.

The 53% increase in the SMR’s target power price since 2021 has been driven by a dramatic 75% jump in the project’s estimated construction cost, which has risen from $5.3 billion to $9.3 billion. The new estimate makes the NuScale SMR about as expensive on a dollars-per-kilowatt basis ($20,139/kW) as the two-reactor Vogtle nuclear project currently being built in Georgia, undercutting the claim that SMRs will be cheap to build.

NuScale and UAMPS attribute the construction cost increase to inflationary pressure on the energy supply chain, particularly increases in the prices of the commodities that will be used in nuclear power plant construction.

For example, UAMPS says increases in the producer price index in the past two years have raised the cost of:

• Fabricated steel plate by 54%
• Carbon steel piping by 106%
• Electrical equipment by 25%
• Fabricated structural steel by 70%
• Copper wire and cable by 32%

In addition, UAMPS notes that the interest rate used for the project’s cost modeling has increased approximately 200 basis points since July 2020. The higher interest rate increases the cost of financing the project, raising its total construction cost.

Assuming the commodity price increases cited by NuScale and UAMPS are accurate, the prices of building all the SMRs that NuScale is marketing—and, indeed, of all of the SMR designs currently being marketed by any company—will be much higher than has been acknowledged, and the prices of the power produced by those SMRs will be much more expensive.

Finally, as we’ve previously said, no one should fool themselves into believing this will be the last cost increase for the NuScale/UAMPS SMR. The project still needs to go through additional design, licensing by the U.S. Nuclear Regulatory Commission, construction and pre-operational testing. The experience of other reactors has repeatedly shown that further significant cost increases and substantial schedule delays should be anticipated at any stages of project development.

The higher costs announced last week make it even more imperative that UAMPS and the utilities and communities participating in the project issue requests for proposal (RFP) to learn if there are other resources that can provide the same power, energy and reliability as the SMR but at lower cost and lower financial risk. History shows that this won’t be the last cost increase for the SMR project.

The problem with this analysis is that renewable costs have also risen (see chart from Lazards' latest LCOE calculations below).  Supply chain difficulties because of Covid, the Ukraine War, China's Covid lockdowns, "onshoring" (returning manufacturing to your own country, to reduce supply chain difficulties) and rising interest rates have increased wind and solar costs for the first time in decades.   And, presumably, as we improve the supply chain, these costs will fall.   Also, if more NuScale's SMRs can be built, unit costs will fall, in a classic learning curve feedback loop.

We may well need SMRs at high latitudes, while SMRs even in lower latitudes will add to grid security, because the more different sources of electricity available to the grid, the more balanced and secure it is.  It would be a pity not to at least try NuScale's SMRs, given the strong possibility that component prefabrication will cut costs compared to the hugely expensive giant nuclear power plants which are a decade behind schedule everywhere.  

I have said before that if nuclear is necessary for de-carbonising the world's electricity grid, I would grit my teeth and support it, because the climate emergency is so severe.  But the problems with nuclear remain:  expense and delay.  This SMR will only start operating in 2030, if there are no further delays.  By then, if we are to avoid an increase in global temperatures since pre-industrial times of more than 1.5 degrees C, we will need to have increased the share of renewables in the grid to 80%.  The last 20% will be the hardest to de-carbonise.   SMRs may be necessary for that.   

Source: Lazards
Click on graphic to see clearer image

Wind/solar cheaper than operating cost of coal

From BNEF

It’s now cheaper to build and operate new large-scale wind or solar plants in nearly half the world than it would be to run an existing coal or gas-fired power plant.

That’s the latest analysis from BloombergNEF, which sees that even with the risk of rising commodity prices, a new solar park or wind farm is still competitive with existing coal or gas plants in countries that represent 46% of the world’s population.

So far, bigger and more efficient solar panels and wind turbines have helped prevent the higher prices of key materials from adding to the overall cost of projects. But it’s not clear how long that trend can last.

“The rise in commodity prices has not resulted in an increase in our global levelized cost of energy benchmarks for solar and wind just yet,” said Seb Henbest, chief economist at BNEF. “But if sustained through the second half of 2021, this rise could mean that new-build renewable power gets temporarily more expensive, for almost the first time in decades.”

The price of polysilicon, one of the key raw materials for solar panels, is up threefold in the past year. That’s set to contribute to average solar module prices increasing at least 5% globally this year from 2020, according to BNEF. The surging cost of steel is set to boost wind turbine prices by as much as 17% this year.

Still, the overall trend for renewable power prices makes them increasingly competitive with fossil fuels. The cost of power from solar panels that track the sun fell 4% from the second half of 2020 to $38 per megawatt hour. The cheapest solar projects in Chile, India, the UAE, China, Brazil and Spain can produce power for as little as $22 per megawatt hour, BNEF found.

The steel-dependent wind industry has so far seen prices remain flat this year compared to the second half of 2020, with BNEF’s global benchmark cost for wind farms on land steady at $41 per megawatt hour. The rising input costs have been partially offset by increasingly large and powerful turbines, which grew by about 10% on average compared to last year.

In countries including China, India and Germany, it’s now cheaper to build a new large-scale solar farm than it would be to run an existing coal or gas-fired plant, according to BNEF. Similarly, in countries such as Brazil, the U.K., Poland and Morocco, a new wind farm would be cheaper than running an existing fossil-fuel plant.

Although steel and polysilicon prices have risen, so have coal and natural gas prices.  For example, gas in the US is up 3-fold since the pandemic lows.  Obviously coal or gas power stations with fixed price contracts have become relatively cheaper, but eventually fixed price contracts tend to be renegotiated if they are seriously out of whack.   

90% renewables

 Study after study has shown that we can get to about 90% renewables if we have a grid with mixed wind and solar and about 4 hours of storage.  In the chart below, I have taken Lazard's LCOE calculations and BNEF's battery-pack costs and estimated what achieving 90% renewables would cost, assuming 30% wind/solar overcapacity and 4 hours of li-ion storage.  The additional 10% could come from a variety of sources: hydro, small hydro, wave power, tidal power, biomass, SMRs, green gas, or peaking gas, but these are not costed.   Some of them are more expensive than this model, so overall costs for the whole grid will be higher than shown.

Assumptions:

• Battery-packs are co-located with wind/solar farms with shared grid connections and inverters
• Excess output from wind/solar farms is not curtailed (variability doesn't just mean there's too little wind/sunshine, but also sometimes too much) but used instead to produce green hydrogen.
• The power used to charge the batteries is fully paid far, and isn't just the generation surplus, diverted into storage to prevent curtailment.  I also assumed it would earn nothing when sold, which, now that I think about it is unrealistic.  But conservative. 
• Batteries are not managed to "ride the cycle", i.e, they don't take advantage of movements in the wholesale price to make money, by charging when prices are low and discharging when they are high.
• The projections are derived from extensions of the average rates of decline for the last 5 years, except coal costs (new-build and marginal) are assumed to be flat.
• The cost of finance is assumed to equal the inflation rate in retail electricity prices.  However, this may be invalid, as the expansion in renewables will cut the costs of electricity.

What the chart shows is that  the cost of a wind+solar grid, with 30% overcapacity, and 4 hours of storage became cheaper than the cost of new-build coal in 2015 and will fall below the marginal cost of coal in 2025.   This means that after 2025, there will be rapid closures of existing coal power stations, even if they are not fully depreciated and paid off because the cost of brand-new wind and solar farms, with excess capacity and storage to "firm" output, will be cheaper than digging up the coal, shipping it and burning it.

IRENA vs Lazard's solar costs

 The chart below is derived from two different sources:  IRENA  and Lazard.  The biggest difference between the two is that the Lazard report covers just the US, while IRENA's data covers the globe.  Another difference is that IRENA (in recent years) has used actual contracts instead of LCOE calculations as Lazard does, though in fact contract costings in the US have been broadly similar to Lazard's LCOE calcs.

The costs have been plotted on a log scale in the chart, which means that a similar percentage decline is the same distance on the chart.  This means that a sustained constant rate of decline produces a straight line.  

IRENA's costs for solar globally have until recently been higher than Lazard's in the US, but recently, this gap has closed, and assuming that the recent 5-year rates of decline are extrapolated forward, the average cost of solar internationally will fall below the cost in the USA.   This presumably reflects the expansion of solar into poorer countries in low latitudes, whose solar resources are way better than the Northern Hemisphere developed countries which are higher latitude.  It's ironic―and good news!―that developing countries which have hitherto been at an energy disadvantage will now start to benefit from really cheap energy.  If the extrapolations do reflect reality, by 2025, electricity from solar will cost just $17/MWh.  In 2010, it cost $378/MWh. 

One final point: the lowest fossil fuel cost is $50/MWh (presumably for gas in the US).  The highest is $177.  They are already uncompetitive, though gas at least is complementary to renewables, and will get more uncompetitive as costs continue to decline.  Anybody who invests long-term in fossil fuels―as opposed to holding trading positions―will lose their money.

India coal costs wildly understated

 IEEFA has already done a piece on Ozzie coal capacity utilisation.  This extends the analysis to India.

From IEEFA

India’s future coal-fired power project pipeline carries a massive stranded asset risk due to the collapse in the average utilisation rate of its coal-fired power fleet leading to an underestimation of financial risk for new projects, finds a new report from the Institute for Energy Economics and Financial Analysis (IEEFA).

There are currently 33 gigawatts (GW) of coal-fired power plants under construction and another 29GW of proposed projects under various stages of regulatory approval in India.

Author of the report, energy finance analyst Kashish Shah says the LCOE (levelised cost of energy) is the required tariff at which the net present value of the investment is zero.

“In other words, LCOE is the minimum required average tariff for a power asset to reach a breakeven return at the end of its life. Anything less than that suggests the asset is unviable.”

Shah found that the average utilisation rate of India’s coal-fired fleet has collapsed to a financially unsustainable low of 53% in financial year (FY) 2020/21 from a high of 78% a decade ago in FY2011/12.

For most coal plants in India, the LCOE is calculated with an assumption of utilisation factor of 85-90% throughout the life of the project. However, the [actual] LCOE turns out to be 64% higher with India’s [actual] average capacity utilisation factor sitting at ~55% for the last few years.

“The aspiration for further builds of coal capacity stems from the notion that coal is still ‘cheap’,” says Shah. “However, with tariffs now below Rs2/kilowatt hour (kWh) (US$27/MWh), solar power is cheaper than even the variable cost of coal-fired power and is ready to absorb incremental daytime demand.”

IEEFA’s report highlights that utilisation factors of coal-fired power plants have declined not just in India, but across major electricity markets including China, the United Kingdom (UK) and the United States (U.S.).

“With zero fuel costs, the marginal cost of generation for renewables is practically zero,” says Shah. “On the other hand, with increasing inflation in Indian domestic coal prices and railway transportation costs for coal, the gap between cost competitiveness of renewables versus coal is widening.

“This raises a serious concern about the viability of coal-fired power plants.

“Debt servicing for underutilised coal-fired power assets becomes extremely difficult and creates a liquidity crunch in the whole value chain. The financial stress then spills over to the power distribution sector as well as affecting India’s financial lending institutions. This further inhibits growth in other important segments of the power industry such as renewables and transmission infrastructure, which are extremely critical for India’s electricity sector transition.”

The report concludes that the financial viability of India’s proposed and under construction coal-fired power projects should be re-evaluated based on the right estimation of utilisation factors including LCOE and capacity factor to avoid further bloating of India’s non-performing assets.

IEEFA points out that the cost of new-build solar is below the variable (operating) cost of coal.  It's cheaper to build new solar farms than to dig out, ship, and burn coal to make electricity.   Yet coal power stations are stuill being built because they are "cheap".

With falling capacity factors, gas and coal overvalued

 When we calculate the costs of different generation technologies, we use the LCOE (levelised cost of electricity), which makes it easier to compare costs across generation types.

Basically, you take the output over the lifetime of the asset, and divide it by the cost of construction and operation, PV-ing that back to the present.  To calculate the output, it is usual to use a 'capacity factor'.  For example, solar has a capacity factor of around 25%, which means its output is about 25% of its nameplate capacity.  The capacity factor for fossil fuels is assumed to be flat over time, determined by technological (downtime for maintenance and repair reducing capacity, for example) rather than demand constraints.  But falling demand as renewables increase their market share means that fossil fuel capacity factors are falling.  This increases their LCOEs, making them even less competitive.

From IEEFA:

The Australian government may be relying on inaccurate financial assumptions for its gas-fired recovery as most gas- and coal-fired power plants in Australia, the UK, the U.S. and China are being operated less and less – what’s called a declining capacity factor, finds a new report by the Institute for Energy Economics and Financial Analysis (IEEFA)

Report author and LNG/gas analyst Bruce Robertson says a declining capacity factor poses serious risks to investors in fossil fuelled power plants if they have relied on financial modelling which anticipates power plants having a constant capacity factor throughout their lifetime, meaning they expect a plant to produce electricity at a constant level, every year, until the end of its life.

“Far from being constant, our research shows that the capacity factor for coal-fired power plants has been declining globally since before the beginning of last decade – with many soon to become stranded assets,” says Robertson.

“Similar to the downward trend in coal, the capacity factor of gas-fired power plants’ is also forecast to decline.

“Yet financial modellers are still basing their calculations on the assumption power plants are producing ‘constant’ power over their lifetime. This leads to an underestimation of the cost for each unit of electricity to be produced over the power plant’s lifetime – what’s called levelized cost of energy (LCOE). And this cost underestimation causes a financial overvaluation of the energy asset, which can mislead potential investors.

“Investors should take note.”

[The report] found widely cited energy authorities including the U.S. Energy Information Administration (EIA), the International Energy Agency (IEA) and the Commonwealth Scientific and Industrial Research Organisation (CSIRO), in addition to financial institutions, continue to rely on a ‘constant’ rate of capacity factor in their LCOE calculations.

IEEFA’s research however demonstrates a declining (not constant) capacity factor of fossil-fuelled power plants in four key regions across the globe: Australia, China, the UK and the U.S.

The capacity factor of coal-fired power plants operating in Australia’s National Electricity Market (NEM) has declined by about 24% since 2008, and by about 19% in China since 2007.

“Linear forecasting shows the capacity factor of coal-fired plants in China will fall below 40% in the next 4 years,” says co-author and energy analyst Milad Mousavian.

The UK’s collapse in capacity factor has caused numerous stranded assets, with the UK’s coal era now forecast to end in 2022.

In the U.S., research from think tank RethinkX shows the capacity factor of coal-fired power plants is forecast to drop to 10% by 2035, while a huge drop in capacity factor for gas-fired power plants is forecast to begin from 2022.

Australia’s NEM data shows an even more severe drop than that occurring in the U.S.

Gas peakers and combined cycle gas turbines (CCGT) power plants have been experiencing falls in capacity factor since 2010 and the average capacity factor of all gas-fired power plants in the NEM has fallen from 27% to just 16% in the last decade.

Wind, solar & gas cheapest

From Lazard's latest LCOE estimates.  To maintain comparability, Lazard hasn't changed the cost of capital used in these calculations.  But if you were to use the interest rates that are currently available for industrial scale wind and solar plants they would be even cheaper, but gas would only be a little cheaper because so much of its cost is fuel.  Note: these are the unsubsidised costs, but the hidden costs of coal, gas and nuclear are not included.

Since 2008, the cost of solar has dropped by 72%, wind by 48%.  Gas is cheaper too, as fracking has grown,  but whereas gas was the cheapest in 2009, now it's clearly wind and solar.  Gas produces half the CO2 emissions of coal per MW.  But methane is 86 times as potent a greenhouse gas as carbon dioxide over 20 years, and 34 times as potent over 100 years, and fracking causes serious environmental damage.  My guess is that while wind and solar will continue to gain market share, gas's share will peak as soon as battery costs fall far enough, which may only be 5 years away.