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Solar to Wreck Economics of Existing Power Markets


  1. Continued solar growth could lead to significant decreases in wholesale electricity prices during most peak hours.
  2. High solar penetrations could also impact power prices when solar does not operate, affect the frequency and severity of electricity price spikes, and impact natural gas price volatility.
  3. While lower wholesale prices could impact solar’s growth they will also hurt other energy sources, particularly coal and nuclear but also natural gas and energy efficiency.
  4. Ultimately, the price effects of solar have significant but uncertain ramifications for environmental goals, energy prices, and, ultimately, electricity market design.

Power Markets Due for Massive Changes

During the last twenty years, the majority of the U.S. electricity system has restructured from the traditional vertically integrated model to competitive wholesale markets. The defining characteristics of these markets, competitive daily energy markets and dispatch, is about to collide with the rapid increase in solar generation, with uncertain consequences.

As an intermittent resource, solar only generates during daylight hours when electricity prices are highest. Solar has high capital costs but near zero operating costs – solar will always produce when it is able. This drives down power prices when solar operates, displacing other, more expensive forms of generation.

Known as the merit-order effect, this market consequence of increasing solar generation is relatively well recognized – it results directly from the merit order dispatch of competitive wholesale markets. By reducing prices for hours when solar operates, solar could eventually reduce its own economic competitiveness, a phenomenon known as solar value deflation.  In the last year, there have been many articles focused on these effects:

Almost all of these articles have focused on how solar (or wind) hurt its own economic competiveness at high penetration levels. However, they do not address the massive economic disruption that solar could cause for traditional energy sources through wholesale power markets.

This article more broadly examines the potential wholesale market impacts of solar PV at high penetrations. It examines four ways solar can impact prevailing prices: the merit order effect, increased cycling costs, impacting electricity price spikes, and by changing natural gas pricing dynamics.

This is part 3 of a 3-part series on the future of solar. Part 1 described how solar’s continued growth, cost reductions, and tax credit renewal could drive solar to 10% of U.S. generation by 2025. Part 2 discussed the challenges facing states as they reform net metering in search of a successor policy.

Solar to Dramatically Impact Wholesale Power Prices

In the U.S., there are seven competitive wholesale electricity markets which operate the grid and constitute more than 2/3 of national electricity generation. While the specific markets have different rules and designs, they all use two daily energy markets when dispatching resources to operate the grid: day-ahead and real-time energy markets.

The purpose of these markets is to procure sufficient electricity supply to meet demand at the lowest possible price. In practice, this means that power plants are dispatched on the basis of lowest short-run marginal costs. If a power plant has low marginal costs, like nuclear or solar, the plant will almost always be dispatched. Conversely, if a power plant has high marginal costs, like coal or natural gas, it will only be dispatched in hours when its dispatch cost is lower than or at the market price for electricity.

Example of Dispatch Curve

Hypothetical dispatch curve indicates that renewables and nuclear have lowest dispatch costs while natural gas and coal are higher. Demand levels can vary significantly, leading to different price outcomesSource: EIA

There are four primary ways that solar can impact prices in wholesale power markets:

  1. Reducing prices during daylight hours through the merit-order effect (shifting the dispatch curve to the right)
  2. Increasing prices through higher dispatch costs for cycling units (shifting cycling units to the right on the dispatch curve)
  3. Through exceptionally uncertain, region-specific changes in the frequency and severity of scarcity price spikes
  4. By changing both overall and seasonal demand for natural gas

Each of these effects will vary regionally depending on the prevailing resource mix, renewable resources, weather conditions, and market design. Understanding each of them individually is critical to understand how solar will impact any specific power market.

Lower Prices through the Merit-Order Effect

As solar and wind increase, they displace more expensive thermal generation and decrease power prices in hours in which they operate.

In essence, variable renewable energy shifts the entire dispatch curve to the right, leading to a lower wholesale power price for a given level of demand. At their most extreme, prices can go negative if there is too much power on the system (although this may reflect systemic inflexibility more than anything else).

California’s infamous duck curve provides a good way to conceptualize how the merit-order effect impacts prices in certain hours. As solar is closely tied to sunlight, its generation levels rapidly increase around dawn and rapidly decrease around dusk. In particular, the rapid decrease as night approaches and power demand is still high requires other generation to ramp up quickly.

CAISO Duck Curve

California's duck curve indicates that net energy demand will fall significantly during daylight hours during each of the next five yearsSource: CAISO

Most discussion of the duck curve focuses on what it means for evening ramping requirements or what it indicates about integrating high levels of solar. However, these analyses often miss a critical point: the generation/net load duck curve also leads to a duck curve in power prices.

A quick comparison of California electricity prices illustrates this price duck curve: the graphic below compares average hourly electricity prices between May 2012 and May 2016.

Day-Ahead Average Hourly Electricity Prices at SP-15 (CAISO), May 2012 versus May 2016

Difference in electricity prices between 2012 and 2016 closely resembles the net load duck curveSource: SparkLibrary, based on data from CAISO

These two years provide a solid point of comparison: the vast majority of California’s solar capacity has been added since 2012 and natural gas prices were near similar levels. The bottom of the price duck curve, where solar is reducing power prices significantly, is the merit-order effect in action. Very high levels of solar generation push out higher marginal cost thermal units, lowering overall power prices.

Critically, power prices are lowered the most during peak hours, when electricity is usually the highest. Average prices between 8 AM and 6 PM were only $17/MWh in 2016, almost half of the $32/MWh level in 2012.

Over time, these reduced hourly prices can really add up. In Germany, one study found that increasing renewable energy reduced average wholesale power prices by 6-10 €/MWh in 2010-2012 with the potential to reduce prices by 14-16 €/MWh this year. These declining prices have severely damaged the economics of electric utilities using traditional generation sources.

Higher Prices from Increased Cycling

While the downwards price pressure from merit order effects is significant, solar can also impact prices through increased cycling/ramping costs.

The need to ramp up generation rapidly in the evening (as indicated by the duck curve) can lead a corresponding jump in power prices. With solar having minimal impact during these hours, prices will equal the dispatch cost of the marginal unit (likely natural gas or coal in most cases).

Critically, these dispatch costs may be higher in a system with high levels of solar than they would be otherwise. This is because starting units and ramping their generation is costlier than maintaining constant generation. These increased cycling costs could mitigate some of the downwards pressure from the merit order effect.

Hypothetical Price-Duration Curves with Solar PV Effects

Hypothetical price duration curve indicates that the merit order effect will reduce prices in some hours while cycling costs increases them in othersSource: MIT Future of Solar

The actual price effects of cycling in a region will depend on the region’s demand profile, its generating mix, weather, and the solar penetration level. In general, upwards price effects will be lower in systems with higher flexibility from:

  • Readily-dispatchable natural gas generation
  • Available energy storage
  • Interregional transmission
  • Demand response resources

Overall, in the United States, the large prevalence of rapid response natural gas capacity will likely limit increased costs from cycling. While cycling will impact some of the higher cost hours, it will only be limited to a few hours a day. Comparably, merit-order effects will dominate most peak hours, leading to a net decrease in average electricity prices.

Uncertain Changes in Electricity Price Spikes

High solar penetrations could also impact power prices in a way that is relatively unexamined:  by changing the frequency and severity of price spikes (also referred to as scarcity prices).

As electricity cannot currently be stored in significant quantities, the electric grid needs to meet demand at all times or the system collapses into a blackout. When electricity demand approaches available supply, two things can happen.

First, the highest marginal cost resources (primarily natural gas or oil peaking facilities) are dispatched, greatly raising either day-ahead or real-time prices. These types of price spikes happen relatively frequently: most ISOs experience them during summer heat waves, other extreme weather events, or as a result of transmission or generation outages.

Second, if operating reserves becomes sufficiently limited, the ISO/RTO institutes shortage pricing procedures, where market clearing prices become (more or less) administratively determined. While these procedures are implemented rarely, they play an outsize role in ERCOT, Texas’ grid operator.

In August 2011, high temperatures in Texas drove ERCOT demand to record highs while drought caused key forced outages. Although the state narrowly avoided blackouts, prices spiked severely – average day-ahead peak power prices broke $100/MWh on many days. On particularly severe days, average peak prices were higher than $500/MWh, around ten times higher than normal prevailing summer power prices.

Daily average electricity prices in ERCOT during August 2011 frequently broke above $100/MWhSource: EIA

Why are these price spikes important? Because they are highly profitable for electricity generators and very costly for consumers. In a system like ERCOT, one day of peak power prices at $500/MWh will raise average electricity prices for the whole year by $0.50-$1.00/MWh.

While ERCOT provides a poignant example of the effects of price spikes, major price spikes occur throughout the country. The causes of price spikes are highly variable and are (likely) impossible to model: prevailing weather conditions, generating fleet composition, electric trade, and contingent forced outages, to name a few.

Accordingly, it is exceptionally difficult to determine how solar growth will impact the frequency and severity of electricity price spikes. Realistically, scarcity pricing could either become more or less frequent or severe:

  • By generating at their highest levels during sunny heat waves, solar’s generation profile is well matched to the heat waves that most often cause price spikes. Thus, for most hours, solar could prevent the occurrence of scarcity pricing or limit its severity if it does occur.
  • Conversely, solar’s rapid drop off in the evening hours could cause price spikes in the evening to ensure sufficient ramping generation comes online. Although this ramping generation would be for only a few hours, severe conditions could cause shortage price conditions more severe than would occur in the absence of solar.

On balance, solar is likely to reduce the severity and occurrence of summertime price spikes in most regions. In particular, unlike thermal generation, solar does not really suffer from forced outages – as the system penetration level of solar increases, the system actually becomes less vulnerable to individual forced outages.

Reduced Overall Natural Gas Demand

There is a final major way that solar could impact wholesale power prices: indirectly by reducing power sector natural gas demand overall and by impacting seasonal demand.

During most hours in U.S. electricity markets, the market clearing price set by the electricity dispatch curve is determined by either natural gas or its main competitor coal. Accordingly, power prices usually have a direct relationship with natural gas prices.

By reducing the need for natural gas or coal generation, increased solar will tend to lead to decreased natural gas consumption. On average, this leads to lower natural gas prices and lower wholesale power prices. For example, a recent LBNL report found that the renewable energy required by state RPS policies reduced natural gas prices by $0.05-0.14/MMBtu in 2013. Higher solar penetrations will similarly keep natural gas and electricity prices down by limiting natural gas consumption.

Greater Natural Gas Price Volatility

Increasing solar generation will also impact natural gas prices by changing seasonal natural gas demand patterns and potentially altering the dynamics of natural gas price volatility.

Compared to other energy sources, natural gas has the most diverse end uses. In the U.S., only about a third is used for electricity, with the rest of demand coming from residential (16.9%), commercial (11.7%), and industrial sectors (27.3%). Most residential and commercial sector consumption of natural gas is for heating in wintertime.

This heavy demand for heating directly leads to natural gas’ price volatility: the natural gas market needs to ensure sufficient natural gas supplies to get through the next winter. A cold winter (like 2013-2014) leads to large consumption of natural gas, depleted storage, and higher prices to refill that storage. A warm winter (like this last winter) limits consumption of natural gas, leads to overflowing storage, and requires very low prices to burn off ‘excess’ natural gas.

During the last five years, this volatility has led to Henry Hub prices generally ranging between $2-6.50/MMBtu. As natural gas prices set power prices either directly or indirectly (through competition with coal), natural gas price volatility leads directly to electricity price volatility.

High generation from solar, as well as from wind, could change the dynamics of natural gas price volatility. Wind capacity factors reach their highest in spring while solar capacity factors reach their highest in summer.

2015 Monthly Natural Gas Demand versus Wind and Solar Capacity Factors

Monthly natural gas demand, concentrated around winter months contrasts sharply with the seasonal max capacity factors of wind and solarSource: SparkLibrary, based on data from EIA

As wind and solar grow, they may increasingly displace natural gas during these seasons. Power sector natural gas demand could become even more concentrated towards both winter and fall, further increasing the impact of variable winter weather on natural gas demand and prices.

As such, solar could actually lead to greater volatility in natural gas prices. The final effects will depend on the degree to which wind and solar reduce natural gas consumption and how closely winter weather severity correlates with subsequent wind and solar resource availability.

Critically, unlike the other factors covered in this article, solar’s impact on natural gas prices is a national, not regional, phenomenon. This means that even regions with relatively low levels of solar will see reduced and more volatile power prices indirectly through natural gas prices.

Solar May Not Hurt Itself as Much as Many Think

In sum, solar is likely to have an extremely disruptive effect on U.S. power markets. It will:

  1. Lower power prices during most peak hours (historically the highest priced hours);
  2. Slightly increase power costs due to ramping generators;
  3. Reduce the prevalence and severity of scarcity price spikes in most hours;
  4. And reduce overall natural gas prices while also making them more volatile.

Recent discussion of these effects have primarily focused on the merit order effect (#1) and what it means for solar value deflation. Jesse Jenkins and Alex Trembath argue that these downwards price impacts will limit solar’s penetration levels to near its capacity factor (solid critique of this argument here). Meanwhile, Shayle Kahn and Varun Sivarum argue that the solar industry can mitigate solar value deflation through continuing to drive down costs through innovation.

The impression from this coverage is that solar will definitely ‘eat its own lunch’ and will be the resource hurt most by its success.

The reality for solar is considerably more complex.

First, the actual market impacts of high penetration solar on wholesale markets will depend heavily on regional characteristics, system flexibility, prevailing weather, and even market design. Over time, price effects from solar can encourage greater electricity trade, shift solar generation to favor generation later in the evening, reduce overall net peak demand, and even make short term energy storage more valuable. All of these will tend to limit the effects of solar value deflation.

Second, there is a critical difference between the wholesale market impacts of an energy supply and how it receives compensation. Most renewables today are on long term contracts, making them largely insensitive to short term electricity prices.

Long term contracts are based on perceptions of wholesale prices, but it may take a while for downwards price impacts to actually filter through to long term contracts. Similarly, distributed solar is almost entirely insulated from wholesale power prices – aided by net metering, it is largely competing with all-in rates.

Thus solar may be more resilient to its wholesale market effects than the current discussion indicates.

Lower Electricity Prices to Hurt Baseload Generation

However, the impacts on other energy resources could be much greater. With the potential exception of wind and hydro, solar’s impact on power markets will hurt the economics all other energy resources: coal, nuclear, natural gas, biomass, and even energy efficiency.

For most of these resources, the challenge comes from a glaring tension at the heart of U.S. competitive power markets: daily energy markets are dispatched on the basis of short term marginal costs that do not match the all-in cost structures of energy resources. To put it another way, energy resources are dispatched based on what it takes to run today not on the costs to keep the plant running tomorrow.

In particular, coal and nuclear have large fixed costs that they do not always recover in energy markets. Unlike renewables, most thermal plants do not use long term contracts, increasing their sensitivity to wholesale power prices. Thus the ultimate effect of high penetrations of solar could be to accelerate coal retirements and potentially exacerbate the financial troubles facing nuclear. The reduction in peak power prices from solar will significantly hurt these baseload resources.

Critically, natural gas capacity may be the least impacted by solar’s growth. With limited capital and fixed costs, natural gas’ cost profile closely matches its energy market revenues. Natural gas is able to ramp up and down quicker than nuclear or coal, making it better able to capture any price fluctuations from solar’s intermittency or from short term price spikes. Solar will generally reduce natural gas prices while also making them more volatile – however, natural gas will still often set marginal clearing prices, limiting financial impacts on natural gas units.

Read More

  1. An in-depth examination of the duck curve:
  2. Good discussion of potential cost innovation in solar to overcome solar value deflation:
  3. Solid (but limited) discussion of the merit order curve and cycling costs:

Original Post


Alex Gilbert's picture

Thank Alex for the Post!

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Nathan Wilson's picture
Nathan Wilson on Jul 12, 2016 3:51 am GMT

Good discussion Alex. This is also a great time to discuss the very generous subsidies solar projects receive. Assuming the developer puts down 20% of the cost in cash, the 30% investment tax credit lets them recover their entire down payment, plus 50% more on day one. This ITC has been extended so that projects that “begin construction” by 2019 (and finish by end of 2023) get the 30% ITC; with subsequent years reduced to 26% and 22%, followed by a permanent 10% utility ITC.

In addition to the loan guarantee and the ITC, these PV projects also receive accelerated depreciation. Depreciation is an expense deduction that reduces taxable business profits. Businesses normally must depreciate an asset over its useful life (e.g. 30 years), but PV projects qualify for 5 year depreciation. This means that if a business is in a 35% tax bracket, it gets another tax subsidy worth 35% of the cost of a PV project, with payments spread over 5 years.

With 65-70% of the cost of these PV projects paid for by taxpayers, they are a bargain for developers.

[repost with links removed]

Helmut Frik's picture
Helmut Frik on Jul 12, 2016 10:22 am GMT

@ Nathan Wilson – how many aears do Gas and Oil industry have to write off drilling costs and other investments?

Beside this a good article.
What is not considered is that east – west extension of the US will make it easy for FLorida to cover it’s evening peak with power produced further west, while california, at least as long as connections further west do not exist, will have to do more to cover its evening peak – as they are doing already by giving incentives to move demand away from evening to the noon e.g. for air conditioning.

Leo Klisch's picture
Leo Klisch on Jul 12, 2016 8:36 pm GMT

If the developer decides to own the project and sell on the wholesale market or has a PPA with a utility, and the PPA is competitive bidding, I would think that the utility would get cheap subsidized solar power minus what the winning developer thinks his investment is worth. And if the utility is not greedy, they will sell as low as possible based on reasonable ROI. So the consumer/tax payer would get subsudized solar power that some think is a good deal for the taxes payed and others not.

Mark Heslep's picture
Mark Heslep on Jul 13, 2016 12:04 am GMT

Despite that subsidy, without net-metering residential solar still fails economically.

Solar City pulled out of Nevada after state regulators cut the price that utilities have to pay for surplus electricity generated by home solar installations. ….”This decision has decimated the entire industry. There is no more rooftop industry in Nevada.”

I suspect the political price for the implementation of a future escalating carbon tax is that all energy sources be granted a level playing field, and the subsidies terminated. If that turns out to be the case, new utility solar would also collapse along with any new wind in areas where penetration is already driving spot prices negative.

Nathan Wilson's picture
Nathan Wilson on Jul 13, 2016 1:56 am GMT

You’ll have to ask Geoffrey Styles or David Hone about the fossil fuel industry.

Regarding using west coast solar to provide evening demand peaks on the east coast, I agree this makes sense in theory. However, I don’t see any way for this to happen in the real world.

The problem is that the south east US has almost as much average sunlight as California (but many more cloudy days), so that the improvement in capacity factor is not enough to pay for the long distance transmission. Plus, green groups are poisoning America against nuclear, which is well suited to be a local east coast energy source (and everyone hates being a net energy importer). As a result, the east coast will grow their own solar with fossil fuel backup, thus depressing market demand for imported solar (which has only 3 hours of peak shift, thus 9 hours of overlap), thus leading to fossil fuel lock-in for the majority of electricity.

On the other hand, if those trans-continental power lines carried nuclear power west at night time, and solar power east during the day, each region could happily net zero imports. It’s probably cheaper though, to skip the power lines, build nukes everywhere, and level demand with night-time EV charging.

Helmut Frik's picture
Helmut Frik on Jul 13, 2016 7:35 am GMT

Well, you show some cost calculations to proove your guesses. Sinc e Power lines smooth out sun (including clouds), smooth out wind and smooth out demand, while providing backup for local failures, you need to build many power plants to replace a single long power line, which cost more to build and cost much, much more to maintain.
Which is the cause why the russians use this way to smooth out demand peaks for decades, and it also happens within the european grid.
It is just so that in the US Electricity was always a murch regulated, local market, where utilities did not woant other utilities to interfer with them in “their” teirrtory, so building a grid was not in the interest of the owners of the local gridlets. Thhis is changing now.
And if it’s possible to do load shifting to the night for nuclear it is as well possible to do load shifting to the day for solar, it is even more easy in many circumstnces.

Helmut Frik's picture
Helmut Frik on Jul 13, 2016 7:53 am GMT

And negatoive Spotprices in one place while prices are positive in other areas fuels trade and the construction of new power lines, which then remove the negative prices again. This is already happening everywhere. And as a sideffect, these grid extensions make the grids more stable.

Alex Gilbert's picture
Alex Gilbert on Jul 13, 2016 8:32 pm GMT

Hi Nathan,

Thanks for the comments and happy you enjoyed the article. You make some good points about the different tax treatments that solar projects receive. It is important to note that the actual level of taxpayer assistance will depend on the tax liability of the solar company. Tax liabilities for a lot of these entities can be pretty low, meaning they often face external tax credit financing costs. The exact numbers vary but these costs can eat 10-30% of the value of the ITC – shows the limitations of using tax credits as subsidies instead of direct cash grants. I’m not sure how tax liability levels would play into accelerated depreciation issues.

Also a solid point that the way solar is financed is somewhat divorced from market realities. Power markets have their own issues and there are policy reasons to want to adopt solar, so this is not necessarily a problem. But it is a public policy decision that we are making – we need to recognize that and constantly reevaluate whether it is something that we want to do.


Alex Gilbert's picture
Alex Gilbert on Jul 13, 2016 8:41 pm GMT

Hi Helmut,

Thats a very good point. There are both North/South and East/West elements (varying by season) that will affect the hourly prices in any region. Transmission is very hard but it brings significant dividends. In theory, by lowering power prices solar and wind should encourage the development of transmission to make up for these regional differences. In reality though, market realities not only factor – need regulatory pressure and movement.


Alex Gilbert's picture
Alex Gilbert on Jul 13, 2016 8:44 pm GMT

Good point here about how improved transmission will potentially benefit baseload power systems. The smaller the effective market region the more intense merit order effects will be. The large the effective market region the easier it is to balance the inflexible nature of existing nuclear plants with the intermittency of variable renewable energy.

Honestly, significant reforms to make transmission easier might have more impacts than passing a carbon price. Certainly more politically feasible.

Helmut Frik's picture
Helmut Frik on Jul 14, 2016 7:27 am GMT

Some see it like this. But renewables can cope with low prices at peak times easily, they can switch off in seconds. To ramp down nuclear below 60..80% depending on design takes days. So a not predicted downward movement in demand can easily bring nuclear to negative prices. And the average wholesale price is not enough to build new nuclear, or even to pay bigger repairs, which inevitabely come during longer times of operation. which makes it very likely that they are a slowly dying species. baseload does not help when there is only a remaining market for residual load.
Beside this, transmission is the cheapest way to remove CO2 emissions. This would include subsea cables in the caso of north america, I would say without doing exact calculations.
The advanatge is: transmission can be built very fast if reguulation allowes it. So it can continuously be adopted to the development of tranmission demand over time. And to keep tranmission running costs comparatively little money.

Nathan Wilson's picture
Nathan Wilson on Jul 14, 2016 11:39 am GMT

baseload does not help when there is only a remaining market for residual load.

Yes, in that case (residual after lots of variable renewables), baseload will have degraded economics, also remember that adding more solar or wind (which is highly correlated with existing solar and wind) will be even worse than adding baseload. Thus, fossil fuel is by far the cheapest solution; hence fossil fuel lock-in (this is very bad when the cheapest fossil fuel is coal, like in Germany, China, and India). That is a very serious problem with trying to go higher than 50% variable renewables; as the NOAA study showed, transmission just does not help enough.

And the average wholesale price is not enough to build new nuclear

This is a phony argument. In any sustainable grid, there is negligible fuel cost; electricity costs are dominated by plant capital cost. This means that all new plant construction must be funded with increases in electricity cost for plant cost recovery. This is especially noticeable when the plants last longer than the time it takes to pay for them (which is economically desirable).

Helmut Frik's picture
Helmut Frik on Jul 14, 2016 12:21 pm GMT

a) well research in germany, includig the big utilities today, up to 60-80% renewables share there will be no problem with any storage needed, above the need for storage will depend how much the international grids are expanded.
But even today the nuclear power stations are running into negative prices, and so out of any ecomomical reason. The interests of having them running is going toward zero also on utility side, so when they are in maintenance today, they try to save money more than time, because it does not matter so much how long they stay offline. So even if they would be allowed to run longer, they most likely would not be operated much longer, because they ar already a burden for the grid operation, and are more and more bocoming a financial burden.
For the utilitys it is cheaper to invesst in renewable capacitys abroad, and in transmission capacity, if they are also in the tranmission line business.

About the second part – well it is always required that renewables are able to finance themselves based on wholesale prices, everything else is declared as “subsidy and parasitic”.
Naturally in a grid where wholesale price is fixed by variable costs, and variable costs of all operating plants is about zero, nothing can be financed by the wholesale costs.
Which requires either funding, or flexible demand which then can set the price the other way round. Which is also more easy in bigger grids, to get the market running, by having more flexible demand in absolute numbers in the grid, and by having producers at zero variable costs +some transmission costs forming a merit order again over distance. How this will develop we will see. But it does not give any advantage for nuclear, as long as costs per kWh are higher than the costs per kWh for renewables. Other kinds of power production like biomass and hydropower are much better in filling the residual load.
And you always forget that the 50% or so number of the graph you cite in almost all of your contribution, is not fix, but variable over time, and rising due to old plants being scrapped and not replaced by new fossil powered plants.
Keep in mind that when the numbers of constructed conventional plants starts falling substatial, the technology is doomed due to the negative economy of scale it experiences.

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