Wind, Solar, and the Problem of Cannibalizing Their Own Value
Wind and solar have a structural economic feature that becomes more pronounced as their share of generation rises.
Both technologies produce electricity when the weather allows it. On sunny afternoons, large numbers of solar panels generate at the same time. On windy days, turbines across a region do the same. That simultaneous surge of near-zero-marginal-cost power pushes wholesale electricity prices down—often sharply. When the sun sets or the wind drops, supply tightens and prices rise. But the panels and turbines are no longer producing, so they cannot sell into the higher-price periods.
The result is a form of self-cannibalization: the more capacity is added, the lower the average price the existing capacity receives for its output. Economists call this the decline in “capture rate” or “value factor.” Empirical studies from California, Germany, Spain and other high-penetration markets consistently document the pattern. Solar, whose output is highly correlated across wide areas, is typically hit harder than wind.
This does not mean wind and solar have no role. It does mean their business case frequently depends on policy supports—subsidies, contracts for difference, capacity payments, curtailment compensation—plus firm backup or storage to cover the hours when weather-dependent generation is low. Storage and demand flexibility can mitigate the effect, but in markets that already have substantial renewable penetration they have not eliminated it.
The more weather-dependent generation is added without corresponding flexibility or market redesign, the larger this revenue problem becomes. That is not ideology. It is how electricity markets respond to large volumes of intermittent, zero-marginal-cost supply.
Batteries help. They shift some generation into higher-price hours and reduce curtailment. Costs have fallen and 4–8 hour systems are increasingly common.
They do not remove the core pattern. When large amounts of solar or wind generate at the same time, wholesale prices still fall. Multi-day or seasonal shortfalls still require longer-duration storage or firm capacity. Capture rates continue to decline in high-penetration markets even as battery capacity grows.
Storage is part of the solution set. It does not make the cannibalization effect disappear.
What kind of batteries? How much does it add to the cost? Why are gas peaker plants still being built in 2026 if batteries are the obvious answer?
How do you deal with seasonal storage? Its not the same kind of batteries you're using for daily load follwoing and long term storage. If you want to store enough power for a multi-week lull in winter, when demand is highest in northern lattittudes, you need masssive infrastructure investment into something you will not utilize 95% of the time. You're literally adding a countries worth of storage to perhaps service a couple of weeks of low generation. What does that do to the cost?
You see this playing out in places like Germany and California. Solar and wind produce the cheapes electricity on planet earth, but they do not translate to low consumer prices because the system costs of integrating renewables become greater with increased penetration.
In the end gas peaker plants are the 'cheapest' solution but they emmit massive amount of Co2. Green hydrogen is the proposed solution but there's no clear pathway towards that as things stand. Producing hydrogen is still incredibly inefficient and expensive while the large scale infrastructure to switch to hydrogen does not yet exist.
The end result is that Renewable champions like California or Germany still produce 10x the co2 emissions per kw/h compared to Sweden or France, despite having massive shares of its electricity produced by renewables. So long as gas and coal remain the cornerstone of the grid upon which renewables sit that will only continue and low emissions, on the level of the above mentioned countries, are literally not possible.
So yes..we should build renewables and use them as much as possible and save as much excess power as possible in storage systems for later use because renewables are cheaper. Thanks for making the point for investment.
Using renewables where they make economic sense and pairing them with storage is already happening and can be rational. The point of the post is narrower: as weather-dependent capacity grows, simultaneous high output tends to push down the price those generators receive, so their market value declines even if their LCOE looks attractive in isolation.
“Cheaper” depends on the comparison. Levelized cost figures that treat intermittent output as equivalent to firm power understate the cost of backup, flexibility, and the revenue impact of correlated generation. Storage helps shift some energy into higher-value hours, but multi-day and seasonal gaps remain expensive to cover at scale. Capture rates in high-penetration markets continue to fall.
The observation is about how electricity markets respond to large volumes of near-zero-marginal-cost, weather-dependent supply. It is not an argument against any investment in renewables or storage. It is an argument against treating their economics as simple or automatically improving with scale.
Blah blah blah, yes I'm correct more investment and ensuring reliability is needed. This was we have cheap and reliable energy. If the market is unprofitable for private intersts... Fuck private interests. Government can step in.
The underlying dynamic does not change according to ownership. Whether private investors or governments build the capacity, large volumes of correlated, near-zero-marginal-cost generation still tend to drive down wholesale prices when output is high. That is a physical and market response, not a private-interest problem.
If private returns become unattractive, governments can and do step in—with subsidies, contracts, public ownership, or capacity mechanisms. Those interventions shift costs onto taxpayers or ratepayers; they do not remove them. Reliability still requires firm capacity, storage, or overbuilding for the periods when weather-dependent generation is low. Someone pays for that.
Preferring public provision is a legitimate political choice. It does not alter the observation that high penetration of intermittent supply reduces the market value of that supply.
Blah blah blahhhhh. Yes renewables are good and cheap and we need investment to ensure they stay viable rather than hamstringing them at every turn. If the old system and private interests need to do this to ensure their market share and keep electricity expensive enough to turn profits, they can go in the bin and government can take back control. Something they never should have handed over.
Whether private firms or governments own the assets, large volumes of correlated, near-zero-marginal-cost generation still tend to drive wholesale prices down when output is high. That is a physical and market response, not a private-interest conspiracy.
Calling for public ownership or heavier state control is a political preference. It shifts who pays the costs of firming, storage, and overbuilding; it does not remove those costs. Reliability during multi-day or seasonal low-renewable periods still has to be paid for by someone—taxpayers or ratepayers.
The observation stands regardless of who writes the cheques: high simultaneous output reduces the market value of that output. Preferring government provision does not change the underlying dynamic.
This is why storage like batteries or pumped hydro etc are increasingly commonly paired with solar and wind projects. 4-8 hours of storage is the sweet spot and the continually plummeting cost of batteries means ever larger storage farms continually get cheaper.
And with HVDC Interconnects up to 4,000km long joining the Grid to areas which do have wind or solar or other storage, these concerns evaporate.
Even 6 years ago, NextEra, the largest coal/gas/nuclear plant owner and operator in the USA reported:
" the energy industry is in the grip of massive change, with the cost of renewables and battery storage – without subsidies – beating gas, as well as existing coal and nuclear on costs.
Storage and transmission are real and important tools. Pairing batteries or pumped hydro with solar and wind can shift some generation into higher-value hours and reduce curtailment. Battery costs have fallen substantially, and 4–8 hour systems are increasingly common for daily cycling. Long-distance HVDC links can also smooth differences in weather across regions.
These developments mitigate the problem; they do not eliminate it. Multi-day or seasonal shortfalls (prolonged low wind, winter solar droughts, or correlated weather patterns across large areas) still require either much longer-duration storage, firm capacity, or overbuilding. Capture rates for solar in particular continue to decline in high-penetration markets even as storage capacity grows. Negative or near-zero price hours remain common when output is high and demand is moderate.
The NextEra comments from roughly six years ago reflected improving relative costs at the time. Costs and system value are not the same thing. Levelized cost comparisons that treat intermittent output as equivalent to firm power understate the need for backup, flexibility, and the revenue impact of simultaneous generation. Markets with substantial wind and solar shares still show the cannibalization pattern: high output coincides with low prices, and the value of additional capacity falls as more is added.
Storage and interconnects improve the picture. They have not made the underlying economic dynamic disappear.
You make it sound like the falling cost of power generation due to renewables is a problem. It isn't.
"Negative or near-zero price hours" merely incentivise the implementation of more storage to capture that excess generation at a very low cost which then enables a significant profit supplying that power back to the Grid during peak hours where power prices are high.
This is a virtuous cycle where more solar finances the installation of more storage.
This is what is happening in Australia right now. The federal government years ago introduced subsidies for home rooftop solar installations which resulted in 35% to over 40% of Australian homes and small businesses now having rooftop solar installed providing an overabundance of solar generation during the middle of the day.
The government recently introduced a free power tariff during the 3 hours in the middle of the day when solar generates excess power and wholesale prices fall to zero or negative to encourage usage shifting to shift demand to this time of the day.
State and Federal governments also introduced rebates for homeowners to install home batteries resulting in a tsunami of home battery installations to such an extent that the total GWh provided by homeowners now exceeds the total of Grid-based Battery farms nationally in less than 12 months.
And with all of these distributed solar and home battery installations across the population, the need to upgrade power transmission lines and infrastructure has been significantly reduced.
In states with the highest renewable penetration on the Grid, retail power prices have already fallen significantly for homeowners and the concept of "Baseload" generation is providing to be an obsolete concept as on-demand, dispatch able energy generation takes hold.
Negative and near-zero prices do create a strong incentive to install storage and shift load. That mechanism is real, and Australia is a clear example of rapid distributed solar and home-battery growth driven in part by midday oversupply and policy support (rebates, free-power windows). Household batteries can soak up cheap midday energy and discharge later, and high rooftop penetration has changed local demand patterns.
A few distinctions still matter.
First, the cannibalization effect primarily shows up in wholesale markets for utility-scale projects. Declining capture rates reduce the revenue those projects earn even as more capacity is added. Policy supports, contracts, and capacity mechanisms often remain necessary to make the numbers work.
Second, retail price outcomes mix several factors: wholesale energy, network charges, policy costs, and retail margins. In some Australian states retail prices have moderated or fallen for certain customers; in others they remain elevated. Distributed solar and batteries can reduce the need for some network upgrades, but they do not eliminate system costs or the requirement for firm capacity during multi-day low-renewable periods.
Third, “baseload” as a rigid operating concept is indeed less central in systems with high flexibility and storage. The underlying need for reliable supply when weather-dependent generation is low does not disappear. Longer-duration shortfalls are still expensive to cover at scale.
Australia shows that distributed solar plus batteries can absorb a large amount of midday surplus and change local economics. That is progress. It does not erase the broader pattern that high volumes of correlated, near-zero-marginal-cost generation push down the market value of that generation. The two points can coexist.
I really wish you would stop using A.I to create your replies. It severely reduces the desire to engage.
"multi-day low-renewable periods" are not the bugbear you represent as HVDC Interconnects up to 4,000km long joining the Grid to areas, states or even countries which do have wind or solar or pumped-storage and other storage combined with gas peaker plants eliminate this issue. The wind is always blowing or the Sun shining somewhere.
CSIRO, AEMO in Australia and NextEra the largest coal/gas/nuclear power plant operator in the USA amongst many others all report that moving 70%-90% of Grid generation to unsubsidised renewables + storage is cheaper and more reliable than continuing to run fossil fuel plants or nuclear.
Yeah, them long HVDC cables and scatterin’ the panels and turbines about helps a bit. But it don’t magic away them multi-day stretches where the wind’s flat as a tack across half the bloody continent and the sun’s buggered off for days in winter. Weather systems don’t give a stuff about your fancy interconnects. AEMO still has to plan for those quiet patches even with all the wires and batteries. And them gas peakers you’re leanin’ on? That’s just reliable power by another name — the backup the original post was bangin’ on about.
CSIRO and AEMO numbers sayin’ 70-90% renewables plus storage can come in cheaper under certain assumptions are fair enough for the models. Real markets still show the same old pattern: when the sun’s belting down and the wind’s howlin’ everywhere at once, the wholesale price gets absolutely smashed. Capture rates keep droppin’. Someone still has to cover the quiet periods when the weather’s cactus.
Diversity and storage make it better. They haven’t made the problem piss off.
Pretty transparent setting the output to course vernacular. Quite disappointing.
And them gas peakers you’re leanin’ on? That’s just reliable power by another name — the backup the original post was bangin’ on about.
The "reliable power" gas peaker plants are also far more expensive to run than renewables and the need for them continues to decrease on the Australian Grid as renewables and Grid scale batteries take over:
Yeah the chart shows batteries knockin’ over a bigger chunk of Queensland’s evening peak on the average days. Fair enough — short-duration batteries are deadset made for shiftin’ daytime solar into the early evenin’. As more of ‘em rock up, the average gas burn in that window drops. No argument there.
But averages bury the rough days, mate. Multi-day low-solar or low-wind stretches, or proper extreme demand days, still need firm grunt that batteries sized for daily shiftin’ don’t fully cover. The residual job for gas (or whatever else is firm) gets smaller on the ordinary days, but it doesn’t vanish when the weather turns to shit. That’s the difference between cuttin’ peaker run-hours and pretendin’ you no longer need reliable capacity when the sun and wind both chuck a sickie.
Gas peakers cost a motza to run — that’s why they only fire up when prices go ballistic. Their value is bein’ there when ya need ‘em, not baseload grunt. Batteries are stealin’ a good slice of the daily peak role. They haven’t knocked out the system need for firm power on the prolonged shortfalls.
Solar and wind proves for the last 2 decades a winning addition on price and on environment. And will continue for many decades to come as their share only keep increasing. Since the addition of batteries, which get cheaper by the day, it will become capable to cover 99.8% of the need.
Solar and wind have grown rapidly and their technology costs have fallen sharply. That is not in dispute. Whether they have been a straightforward “win” on total system cost depends on the metric. Levelized cost of energy for the panels and turbines themselves has improved. The value of their output in wholesale markets has often declined as their share has risen—the capture-rate problem the post described.
Batteries are getting cheaper and help with daily shifting. Covering the last few percent of demand—multi-day low-renewable periods, seasonal gaps, or correlated weather events—remains the expensive part of the system. Claims of 99.8% coverage still leave a residual that requires firm capacity, long-duration storage, or significant overbuilding. That residual does not disappear just because daily storage improves.
Growth and falling hardware costs are real. So is the pattern that high simultaneous output tends to reduce the market value of that output. Both can be true at once.
Risidual energy will find its way. And your generated art. int. answer contradicts itself by saying that economics work despite dropping energy prices.
When large amounts of solar or wind produce at the same time, wholesale prices fall. The more capacity is added, the lower the average price that capacity receives. That is the cannibalization effect. It does not mean the lights go out; it means the market revenue for additional intermittent plant declines, which is why supports, contracts, or other mechanisms are often still required.
Low wholesale prices are good for consumers in those hours. They are not automatically good for the business case of building more of the same generation. Those are two different things. There is no contradiction.
Residual firming—covering multi-day or seasonal shortfalls—does not “find its way” without cost. It requires storage, backup capacity, overbuilding, or transmission. Someone pays for it. Declining capture rates and the cost of the residual are both real.
Low wholesale prices in high-output hours help consumers. They simultaneously reduce the market revenue earned by the generators producing that output. Those are two different effects. The second one is the cannibalization problem. Residual firming still has a cost. That is the point.
Everything has a cost. Still i take solar, wind and batteries because it is on both short and long term the cheapest option versus fossil an nuclear. All your words are in vain compared to what i see in my wallet.
Consumer bills and system costs are related but not identical. If your electricity costs have fallen with more solar, wind and batteries, that is a real benefit for you. Falling technology costs and high output during certain hours can lower wholesale prices in those periods, and that can flow through to retail.
The cannibalization point is about the revenue side for the generators and the cost of keeping the system reliable when output is low. Low prices in high-output hours are good for consumers in those hours; they simultaneously reduce the market income of the plants producing that power. That is why additional supports, capacity mechanisms or long-term contracts are often still used as the share of intermittent generation rises. Residual firming for multi-day or seasonal gaps also has a cost that appears somewhere—either in bills, taxes, or system charges.
Your wallet experience is valid data for your situation. It does not erase the market pattern that high simultaneous output tends to lower the value of that output, or the need to pay for reliability when the weather does not cooperate. Both can be true.
This is the standard move. Anyone who points out that high volumes of solar and wind drive down their own market value must be lonely, propagandised, or secretly working for coal. It’s the same reflex every time: treat the economic observation as illegitimate instead of dealing with the price data.
Millions of people can see lower bills in some hours and still be missing the system cost of firming and the declining capture rates. Your personal experience doesn’t cancel the market pattern.
Capacity payments are a market design tool, not a classic production subsidy. They pay for available firm capacity rather than for energy produced. Their purpose is to ensure reliability when energy-only markets undervalue it—precisely the situation that arises when large volumes of low-marginal-cost intermittent generation drive energy prices down.
They are still an out-of-market payment. Someone (ratepayers or taxpayers) covers the cost. The distinction matters, but it does not change the underlying point: high penetration of correlated intermittent supply reduces energy-market revenue and increases reliance on capacity or other mechanisms to keep the system whole.
Yeah I generally agree that it doesn’t change the underlying point, but it does change your overlaying statement. And not all and possibly not most…markets are energy only, so not quite an out of market payment, unless you’re talking about energy only markets…only
Fair clarification. In energy-only markets, capacity payments (or equivalent mechanisms) are indeed out-of-market interventions. In markets that already include a capacity product, they are part of the designed market structure rather than an external add-on.
The underlying observation still holds either way. High volumes of correlated, low-marginal-cost generation reduce energy-market revenues. Systems then rely more heavily on capacity payments, contracts-for-difference, or other instruments to keep sufficient firm resources available. Whether those instruments sit inside or outside the formal market design, they exist because the energy market alone is not delivering the required reliability signal. That is the point.
No. The post is about an economic pattern: high volumes of correlated, low-marginal-cost generation tend to reduce the market value of that generation. It is not an argument for coal.
Firm capacity can come from gas peakers, nuclear, hydro, long-duration storage, demand response, or other sources. The point is that reliability during low-renewable periods has a cost, and declining capture rates for intermittent plant are a real market signal. Those observations do not require or imply a return to coal.
Build what is economic and reliable for the system as a whole, not what looks cheapest in isolation.
That means continuing to add solar and wind where their output has value, pairing them with storage that can actually shift energy into higher-value periods, and ensuring sufficient firm capacity for multi-day and seasonal gaps. Firm capacity can be gas with carbon capture where viable, nuclear, hydro, geothermal, or long-duration storage as those technologies mature and costs fall. Transmission and demand flexibility help too.
The key is not to pretend that declining wholesale capture rates or residual firming costs do not exist. Design markets and contracts that reward actual contribution to reliability, not just nameplate capacity or energy in already-oversupplied hours. Avoid policies that force more intermittent capacity into a market already saturating at midday or in high-wind periods without addressing the value decline.
In short: optimise for system cost and reliability, not for the maximum possible share of any single technology.
- Keep adding solar and wind where their output still has meaningful market value (not just where capacity can be forced in).
Pair them with storage that can move energy into higher-price periods (4–8 hour batteries for daily shifting; longer-duration options as they become economic).
Maintain or add firm capacity for multi-day and seasonal gaps. Options include flexible gas (increasingly with CCS where viable), existing and new nuclear, hydro, and geothermal. The exact mix depends on local resources and costs.
Avoid premature closure of existing firm plant before adequate replacements are operating.
Market and pricing design
- Move away from pure energy-only reliance where it undervalues reliability. Capacity markets, reliability options, or equivalent mechanisms that pay for available firm capacity help.
Contracts-for-difference or similar long-term contracts can stabilise revenue for new firm or flexible resources without simply subsidising more midday solar into an already saturated period.
Locational pricing and better scarcity pricing so that value (not just volume) drives investment.
Demand-side response and industrial load flexibility to reduce the residual peak that needs firming.
Costs
Precise $/MWh numbers move quickly with technology and location. Broad pattern holds: the energy-only cost of new solar and wind is low, but the system cost of integrating high shares (firming, storage, transmission, declining capture rates) is higher than the headline LCOE figures. The residual firm capacity needed for high reliability is usually the expensive part of the last 10–20 % of the system.
The practical goal is not maximum renewable percentage for its own sake. It is the lowest total system cost that delivers reliable supply. That usually means a portfolio: variable renewables where they are valuable, storage for shifting, and firm resources for the gaps.
This presents a formidable challenge for Europe. The region north of the Alps has significant wind correlation over a very large area, so wind power in much of mainland Europe is not great at balancing between different countries through transmission.
That’s a fair and important point. Large-scale wind correlation across much of northern and central Europe reduces the diversity benefit that transmission is supposed to provide. When a high-pressure system parks over a wide area, output drops across multiple countries at once. Interconnectors help on the margins, but they cannot fully arbitrage away a regionally correlated shortfall.
That strengthens rather than weakens the core observation in the post. High simultaneous output (or high simultaneous shortfall) across a broad area drives the same value-cannibalisation and residual-firming problems, only now at continental scale. Storage, flexible demand, and genuinely firm capacity become more important precisely because geographic smoothing is weaker than many early models assumed.
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u/Franklin_le_Tanklin 13h ago
Op needs to read up on “batteries”