real solar power (photo Bjoern Schwarz)
Continued solar growth could lead to significant decreases in wholesale electricity prices during most peak hours, writes Alex Gilbert, cofounder of US-based energy research platform Spark Library, in an article analysing the effects of solar power on electricity markets. While lower wholesale prices can impact solar’s growth they will also hurt other energy sources, particularly coal and nuclear but also natural gas and energy efficiency. Ultimately, the price effects of solar have significant but uncertain ramifications for environmental goals, energy prices, and, ultimately, electricity market design.
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:
- A Look at Wind and Solar, Part 2: Is There An Upper Limit To Variable Renewables?
- Solar power needs a more ambitious cost target
- The economics limitations of wind and solar power
- How Wind and Solar Will Blow Up Power Markets
- The market value of variable renewables
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
Source: EIA
There are four primary ways that solar can impact prices in wholesale power markets:
- Reducing prices during daylight hours through the merit-order effect (shifting the dispatch curve to the right)
- Increasing prices through higher dispatch costs for cycling units (shifting cycling units to the right on the dispatch curve)
- Through exceptionally uncertain, region-specific changes in the frequency and severity of scarcity price spikes
- 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
Source: 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
Source: 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
Source: 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 spikeshappen 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.
Source: 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
Source: 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:
- Lower power prices during most peak hours (historically the highest priced hours);
- Slightly increase power costs due to ramping generators;
- Reduce the prevalence and severity of scarcity price spikes in most hours;
- 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
- An in-depth examination of the duck curve: http://www.nrel.gov/docs/fy16osti/65023.pdf
- Good discussion of potential cost innovation in solar to overcome solar value deflation:http://www.vox.com/2016/4/18/11415510/solar-power-costs-innovation
- Solid (but limited) discussion of the merit order curve and cycling costs: https://mitei.mit.edu/system/files/Chapter%208_compressed.pdf
Editor’s Note
This article was first published on the website of Spark Library and is republished here with permission.
A thought provoking article – but missing from it was consideration of demand which in the summer is dominated by AC from mid-day through to the evening peak. There is little reason (& the tech exists) why AC systems could not store “cold” in the day and release in the evening. Likewise, battery storage could meet some/all of evening demand. This predicates roof-top PV and this was the other aspect missing, the PV split between utility stuff and roof mounted. Although there is continuing resistance by US (vertically integrated) utilities with respect to roof mounted PV, this is going to have to give at some point. Furthermore, if a combination of AC cold store & electrical storage using batteries absorbs most PV output – it is difficult to see what a utility can do. & thus we enter death spiral territory.
Yet another “analysis” by someone who does not appear to understand how security-constrained economic dispatch works or how the demand for ancillary services (operating reserves, frequency regulation, etc.) impacts, or should impact, the price/marginal cost/value (pick your favorite terminology) of a kWh of energy in a properly functioning wholesale energy market. The increasingly important role price responsive demand (including end-use energy storage in applications such as water heating, ice-storage air conditioning and numerous other low cost, readily available options) can and must play in a decarbonized power system in shaping market prices, both in conditions of shortage and in conditions of surplus, is essentially ignored. Apparently no appreciation for the fact that the reduction in average wholesale prices in markets like Germany has nothing to do with the short-run marginal cost of renewables and everything to do with a large surplus of generating capacity. The merit order effect is indeed “relatively well recognized” – it is also well recognized, at least among the experts who have studied it, that the merit order effect is a transitory phenomenon that dissipates as the balance of resources adjusts to the overcapacity resulting from policy-driven additions of capacity to an already over-supplied market. The breathless reaction to prices of $500/MWh evidences a lack of understanding of the actual value of lost load and what prices would be if they reflected the cost of the marginal action required to maintain system reliability – something that is increasingly occurring in better-functioning markets such as ERCOT and the NEM in Australia. It is worse than useless to focus on how an hour of shortage pricing incrementally impacts consumer prices. In a situation in which the system operator is actually short of the reserves needed to meet the system security standard the value of an increment of reserves released to deliver energy rather than continuing to be kept in reserves can be tens of thousands of dollars a MWh – that’s what we’ve come to expect as the value of uninterrupted service. We’ve always paid it, we just didn’t know it, and as a result we’ve underwritten a vast over-investment in utility resources to service unfettered demand at the worst possible times, much of which we would happily forego or postpone to periods of energy surplus – and are increasingly capable of automatically foregoing or postponing at a surprisingly low cost – if only we knew what the economic consequences are. The more important question is how an hour of legitimate shortage pricing, or an hour of extremely low pricing due to a surplus of available generation, affects the shape of consumer demand going forward. There are a number of studies, based on a more complete understanding of security-constrained economic dispatch, a more complete understanding of wholesale energy market price formation, a more complete understanding of the potential for and role of responsive demand in shaping wholesale market prices, that demonstrate that wholesale prices would actually remain reasonably healthy – healthy enough to support the investment actually required – even in a system with high penetration of intermittent renewables. Those prices are likely to exhibit greater volatility, which is critical to underpinning the business case for the flexible resources – including responsive energy appliances – that will be needed to integrate a growing share of intermittent renewables reliably and at least cost. Increased penetration of intermittent renewables will increase the demand for a wide range of “ancillary services” including system inertia, ramping reserves and flexible demand, all of which, if reflected properly in wholesale market prices, will actually drive up clearing prices regardless of the short-run production cost of the marginal generator, whatever that happens to be. Solar may indeed overcome its value cannibalization problem in the market in the future, but that has little to do with the analysis in this article and everything to do with the extent to which the market brings forward the more flexible supply- and demand-side investments needed to underpin the value of increased solar penetration. That in turn depends on the market’s ability to reflect the full marginal cost/value of energy and ancillarly services implied by our prevailing standards for security of supply, not (as this author appears to think) simply the short-run production cost of the last kWh of energy generated.
Is this a long way of saying we need more demand response to match the growth of RES in all markets?
Yes, that, as well as the closely associated issue of making sure energy and balancing market prices fully reflect the value of doing so and provide the business case for doing so – meaning full shortage and surplus pricing, as ERCOT is doing, allowing wholesale prices to fluctuate as necessary from negative prices during periods of surplus to something approaching the full value of lost load (north of $10,000/MWh) during periods of shortage, and step-wise adoption of time-varying retail tariffs for larger and larger shares of customer loads. They are of a piece – you won’t realize the potential of demand response without the revenue opportunities to pay for it (and the idea of doing so through separate auctions for “flexibility” is impractical for reasons we won’t go into here), and conversely the volatility of supply and demand and the associated volatility in what should be the wholesale price will become increasingly difficult to manage without the emergence of a demand curve reflecting greater implementation of demand response (including end-use energy storage).
Poyry did a good analysis years ago of exactly what you are saying. Right here:
http://www.poyry.com/sites/default/files/intermittency_-_march_2011_-_energy.pdf
(summary, full report was never made publicly available)
Great article, except for this part:
“these downwards price impacts will limit solar’s penetration levels to near its capacity factor (solid critique of this argument here).”
Solid? The critique behind that link makes two arguments: both of which are old, incorrect and misleading:
– it argues that nuclear is subsidized just like wind and solar (it is not).
– it argues that nuclear causes the same problems for electricity prices that solar and wind do (it does not).
Well, nuclear certainly can cause the same – or very similar – problems for electricity prices that solar and wind do, if nuclear is at a comparably high level of penetration. The French had to build out a very large system of various energy storage facilities – from pumped storage hydro (including the funding of much of the Swiss pumped storage capacity) to a national network of electric hot water storage systems – to be able to balance their nuclear-intensive power system. The best mix of resources that very much dislike being turned down and despise being turned off, such as nuclear, and intermittent generation such as wind and solar, is going to be specific to different regions, but both sources of generation present similar if photo-opposite balancing challenges that are very real but also very manageable.
The challenges are as different as could be.
Managing nuclear at 80% penetration is cheap and easy, as the French demonstrated decades ago. Managing solar and wind at 80% is extremely expensive and practically impossible.
Pretending that the challenges of managing baseload and intermittent energy sources are ‘similar’ is not helpful to the discussion. It is certainly not ‘solid analysis’. Far from it.
Baloney. We have not been discussing a specific level of solar penetration (solar, not wind) much less 80% solar/wind. I’ve been in the power industry for nearly 40 years, some of that time in the nuclear industry. I know a little bit about what I’m talking about. The cost of managing a system that really has 80% of annual energy from nuclear is anything but “cheap and easy,” starting with the fact that the French nuclear fleet operates, of necessity, at about 78% capacity factor, vs for instance the US nuclear fleet, at a more modest share of the total system, operating at about 90% capacity factor. The impact of that difference to the levelized cost of a technology like nuclear is enormous and is rarely taken into consideration in these discussions. Then consider the fact that while “France” is about 80% nuclear it is in reality part of a synchronized, reasonably well-interconnected continental grid in which the overall share of nuclear is far lower than 80%, so whatever the costs are of integrating the French nuclear fleet into the system are costs associated with a far lower share of system energy than 80%. Finally, no one knows how much it cost in capital investment and continues to cost in increased operating costs to manage the inflexibility of the nuclear fleet, just as no one really knows how much it costs Areva/EdF to build a new nuclear plant in France, because so much of the cost is socialized, though we’re beginning to get a clearer picture now in the case of Flamanville. The fact is that the solutions to the balancing issue are the same in both cases – a combination of demand response and energy storage, along with other sources of flexibility in the balance of the system. The only material difference is on the issue of system inertia, where a nuclear-intensive system has enough (too much) inertia, whereas a system with over 50% from wind and solar would, based on the current state of the commercial technologies, face issues with inertia. However in most cases (Ireland excluded, for instance) we have time to pursue the various promising technological solutions to relieving that constraint. Your urge to demonize renewables is no less damaging and no less unfounded than are the attempts by renewables advocates to demonize nuclear. It’s high time the two communities start working together, as we’re beginning to see in New York State, for instance. Neither is going to be able to solve this problem on their own, and the claims of both have tended to top over into unwarranted hyperbole.
I’m not demonizing anything.
I’m saying that the notion that nuclear and renewables face similar management challenges is unfounded. It’s bogus.
The French nuclear costs have been audited in great detail a number of times, by the French independent Court des Comptes. The total cost is less than €50/MWh. This is very cheap, despite the high penetration of about 80%.
file:///C:/Users/NL0286/Downloads/Costs_nuclear_power_sector_summary.pdf
Your claim that these costs are somehow unknown or unknowable is in fact a form of demonisation of nuclear power. It is a standard element of the antinuclear FUD (Fear, Uncertainty and Doubt) campaign.
On the contrary, it is the cost of renewables which is in fact unknown and unknowable, since the renewable energy market is completely distorted with all manner of direct and hidden subsidies.
I’m only interested in solving the climate/energy challenge. I’m for all technologies which help solve that challenge, including renewables and nuclear. But we have to be clear on the advantages and disadvantages of all options. As said, the notion that nuclear and renewables face similar management challenges at high penetrations is blatant nonsense, plain and simple. It’s antinuclear FUD.
Something went wrong copying the link to the Cour des Comptes report on French nuclear cost. Here is the correct link:
https://www.ccomptes.fr/content/download/43447/694946/version/1/file/Costs_nuclear_power_sector_summary.pdf
don’t you get tired of playing the same record over and over again?
no need to drag nuclear into this discussion
If you read carefully, I dragged in nothing. Others did this.
Nuclear cheaply and comprehensively decarbonised French electricity supply. Some here would have us believe intermittent renewables can this as easily as nuclear did. To use a word already used by someone else: Baloney! 🙂
You appear to be referring to the direct, variable operating cost of existing nuclear plants, which is of course quite easy to assess and is in most cases between $30 and $50/MWh. That has nothing to do with the levelized cost of nuclear at high penetration. Of course you ignored the points about the impact on nuclear load factors in a high-penetration scenario as well as the fact that, in reality, the penetration of nuclear in the system in which France sits is nowhere near 80%. The costs of critical energy storage investments are ignored in the analysis, as are the costs of pumped storage systems built in the US to integrate nuclear plants into local systems. You demonize renewables by using distorted facts about the costs and challenges of integrating large, central station, inflexible nuclear plants. You can claim all you want that there are no comparable challenges in integrating high shares of nuclear and high shares of intermittent renewables, but the facts say otherwise. And you don’t even appear to be familiar with the one dimension of system integration that tends to support your point – system inertia – though that is a constraint we’re well on the way to relieving. Fanatics on both sides of the nuclear-vs.-renewables divide are all the same – the energy equivalent of Birthers – with their cherry-picked nuggets, their tenuous grasp of the subject about which they’re raving, and their impenetrably rosy version of their own favorite solution. It’s all so tiresome – nuclear needs knowledgable, realistic advocates, not cheerleaders cherry-picking data that appears to support their obsession but in fact illustrates the challenge we face.
Let me get this straight. Are you calling a French Cour Des Comptes financial audit report a “cherry picked nugget”?
It is outdated, there is a new report which staes costs for the existing plants (so no investment costs in the calculation) at 65€/MWh and rising.
Nuclear has knowledgable, realistic advocates. Yet nuclear is shrinking in the USA, has been wiped out in Germany and is under threat in Belgium and some other countries. Apparently, something is trying to kill nuclear power, even while the IPCC in its latest report has concluded that nuclear is included in virtually all assessed scenarios consistent with limiting global warming to 2°C.
The crisis of nuclear power is real. Nuclear power is under constant attack by groups who claim to be environmentally concerned, but who appear to be little more than antinuclear activists. The crisis for nuclear is not just about the nuclear sector, but about the fight to address AGW. The same people who say they are concerned about climate, are the people gleefully cheering the demise of nuclear power in some countries. That’s a problem which should concern us all.
It’s not all bad of course. Nuclear is very popular in developing countries, understandably due to it’s low cost and high reliability. But the antinuclear movement is already mobilised in those countries to stoke fear, uncertainty and doubt among the population. If this movement succeeds in fanning the flames of fear and hatred of nuclear in developing countries, like it did in developed countries, then the remaining hope of limiting global warming to 2°C will be dashed.
There is a new study on the market from the cour des comptes, now calculatintg the costs of electricity from_existing_ nuclear power plants with 65€/MWh, about two times the wholesale price, and on par with new utility scale solar in less sunny germany.
Which is why france has scrapped all plans to build new nuclear. (one Flamaville is enough) and looks for other possibilities to produce power. Carbon free.
Very much enjoying the robust discussion between Michael and Joris 🙂 I think you are both correct and have a lot of common understanding.
My take is that the problem of providing swing capacity to support Nuclear verses Renewables differs by an order of magnitude. Whereas nukes have very limited swing capacity and require storage to match supply and demand – with a predictable load profile, renewables have massively negative swing capacity and are highly unpredictable.
By that I mean that swing capacity needs to be provided not only to even out the swings in the load curve of a base load heavy system, but also the daily swings in generation and pick up the slack when the wind doesn’t blow and/or cloud obscures the sun – sometimes for days at a time. Additionally, when this will happen is highly unpredictable, which means that even larger storage and re-generation capacity is required if the swing capacity is to be provided by Pumped Storage Hydro (PSH).
I contend that if we are to roll out large scale solar (which I strongly support), we also need to build commensurate capacity in PSH. I strongly disagree that we can even out supply verses demand through diversity and transmission lines. This belief seems to me to not acknowledge one of the fundamental laws of physics – Murphy’s Law.
Large capacity of PSH would address the issues raised in this article – putting a floor under the price and easing supply shortages. The obvious problem – how do we pay for this capacity?
the benefit for a mix of renewables is, that Wind and PV in a 1:1 mix e.g. in germany or similar areas approximate the load function better than a flat line of baseload – especially when the grid in consideration is big enough to smooth out wind power close to baseload. Which requires a continental size grid – but this is something which already exists in europe although not yet strong enough for this task. So the task changes with the grid in consideration for renewables, while it changes less for nuclear in this aspect. (load also smoothes out with grid size, but the effect is smaller since it is already smoother in smaller grids, and remains less constant in really big grids, unless the grid extends over the whole earth.
Helmut – this is what I mean by failing to acknowledge Murphy’s Law.
When you say “that Wind and PV in a 1:1 mix e.g. in germany or similar areas approximate the load function better than a flat line of baseload” – this is true MOST of the time. But there will always be times when the wind doesn’t blow and the sun doesn’t shine over a vast area of Europe (or any major grid) – most of the time is simply not good enough to maintain reliable supply. So then we have to rely on fossil fuel swing capacity and adequate transmission capacity to keep the lights on and the trains running.
But – as this article explains – the business model of these generators is destroyed by any significant amount of intermittent renewables. Most of the time they are not needed, so most of the time they are not being paid. In order to stay in business, they would need to charge very high rates for their power when they are needed.
Hence I maintain that we have to start looking at how to finance PSH. It may be possible to finance it on a revenue stream based on buying power cheap and selling expensive. But like solar and wind, it destroys its own revenue stream as capacity increases. I suspect that the only realistic way to do it is to treat it as nation building infrastructure – like highways.
Well, the difference is that you assume that sometimes there is a situation without wind even in continental size grids, while scientists could not find them yet when a grid exceeds a certain size.
Also you have to keep in mind, that Europe already has significant more than 200GW of hydropower, most of this combined with a significant storage.
It could otherwise also be assumed, that conventional plants can fail, and a ny number of them can fail around the same time, so when looking at murphys law, it would also be required to back ub the conventional power generation with a complete set of secondary generation for such causes.
Because of this discussing on the level of “feeling” does not lead anywhere.
What is neccesary is to define a reliability which is expected from a grid, and then to calculate what is neccesary to get this reliability in the grid. What is not done by “feeling” that there might be no wind at some time, but by calculation based on the known weather pattern.
And for situations which happen once in a decade or a century for a few days, reserves like the >20GW backup power diesel engines, which are installed in germany already come into play, because fuel costs do not matter in such rare cases, and those engines are existing and are maintained already.
And a little more incentive or just value for such systems coul install many GW more without relevant costs. We regulary install some MW of such engines in our projects.
It is well known that large fluctuations in wind power output occur all the time – even when averaged over a large grid. Also, your argument seems to assume that there is no such thing as transmission constraints.
I maintain that we need substantial storage capability if we are ever to provide a reliable power system and workable market system with a large proportion of intermittent renewables in the generation mix.
And there is ample storage available, at least to deal with fluctuation over hours or even a few days – in existing end-use applications that are or could be electrified. Grid-integrated electric hot water systems, ice-storage air conditioning and commercial refrigeration are commercial technologies that can store energy for hours or even a few days very efficiently at a small fraction of the most optimistic projections for the cost of battery storage. They offer more than enough cost-effective potential to deal with the projected penetration of intermittent renewables on the system through at least 2030. That still leaves the challenge of storing over a period of months to deal with longer-term energy shortfalls of a week or two at a time – which is a very rare but documented phenomenon – but there are ways to bridge that challenge (for example, with deep strategic reserves of thermal generation) until zero-carbon technological options can be brought forward. And as has been pointed out, this challenge is not restricted to intermittent renewables, as the extended outage of nearly half of Belgium’s nuclear fleet and all of Japan’s nuclear fleet have demonstrated. The answer, as has been the case for a hundred years, is diversity.
“Managing nuclear at 80% penetration is cheap and easy, as the French demonstrated…”
?
Strange, considering that the French installed recently laws which:
1. target to reduce nuclear penetration to 50% in 2025;
2. target to increase renewable (wind & solar) greatly.
Reducing nuclear in France and replacing with solar/wind backed up with fossil fuels will increase co2 emissions as well as costs, for obvious reasons.
So according to you, French government and parliament chose for a future which:
– increases the costs of electricity and CO2 emissions;
– delivers problems with the unions (their voters) because of the closing of NPP’s (33% reduction of nuclear within 10yrs according to the new law).
Even the French are not that stupid.
Seems you ignore that the Nuclear power plants need a whoöesae price of around 6,5ct/kWh to keep running, according to the french cour des comptes.
Which means keeping a old nuclear poer plant running, or build a new utility scale solar power project ends up with the same price per kWh. Just that the latter pays the construction with this money, and will deliver power at much lower prces after the 20 year period with 6,5ct/kWh is over, while the NPP is even more old and worn out after another 20 years and did not pay a cent of construction costs for anything.
If you take into consideration that the south of france has 50% more sun than germany and a lot of unused landscape, the decision of the french gouvernment looks more logical.
They know that the existing NPP will close down due to costs when a major repair is necessary at one of the plants, since they already loose money with every kWh produced. So other power production capacity is urgently required in france.
PV is not “power production capacity”. It’s fuel saving capacity. It saves fuel when the sun shines. When it saves natural gas or oil fuel, PV (and wind) makes economic sense. But when it’s used to argue for the closure of nuclear power plants, it makes no sense. Not for climate protection or economically.
Only if you pair PV with enough storage does it become power production capacity equivalent to that of nuclear power plant fleet. But the cost of PV plus enough storage to supply 80% of the market is far higher than just having nuclear supplying 80% of the market.
I’m pretty sure even Michael Hogan can agree.
Well, PV is much more than a fuel equivalent when combined with wind, hydropower and other sources.
Otherwise please explain how it works in a nuclear only power market with peaker and cold reserve plants. You would have to calcculate 110 GW of nuclear plants for a MArket like germany in a nucleear only market, and still rely on piles of batteries for ramping up and down.
Which is as obvious nonsense as your talk about PV.
PV replaces the day peak, with some adjustments fro hydropower and dynamic loads which means in german market that it removes about 40 GW of sumers 80 GW peak noon demand. And this very reliable within the european grid. Wind in larger grids replaces baseload power.
You can see that renewables also replace capacity in the prices of the wholesale market.
Usually for peaker plants to start producing prices above 7ct/kWh such price peaks were usual in a non reneewable environment, often reaching up to 50ct/kWh here.
These peaks are gone.
Which results that peaker plants in germany stand idle now for at least 4 years, with ZERO [0] hours of production, along with most of the midload to peak power CCGT-Plants.
So reality tells that renewables DO replace conventional capacity.
Although we prefere here to keep the existing plants as backup for cases of emergency.
“Which results that peaker plants in germany stand idle now for at least 4 years, with ZERO [0] hours of production, along with most of the midload to peak power CCGT-Plants.”
Erm. Nope.
See the data for Germany. On the 3rd of december 2014, wind and solar produced almost no power the entire day. (Slide 271).
https://www.ise.fraunhofer.de/de/downloads/pdf-files/data-nivc-/stromproduktion-aus-solar-und-windenergie-2014.pdf
This happens regularly. Obviously, solar and wind do not and cannot “replace capacity”. Only nuclear replaces fossil and biomass capacity.
Why refer to a situation from 2014? It suggests that it doesn’t occur often.
Anyway:
– Other renewable also supply power (as well as nuclear).
– Batteries and P2G will take over: http://www.powertogas.info/
I was trying to stay out of this, since you guys are sort of feeling your way through what is a much more nuanced process, but I will simply say that whether wind, solar and other intermittent resources add any firm capacity to a system, and if so how much, is a reasonably well established statistical function, and it will vary from one system to the next and from one resource to another depending on local conditions. In the same way nuclear and other thermal resources have a firm capacity value that is almost never equal to 100% of their installed capacity, since there is a statistical likelihood (usually established based on empirical historical data by resource category or even in some cases by individual resource) they will be unavailable when needed. The firm capacity value of most thermal generation is higher than the firm capacity value of most intermittent renewables, but the former is rarely 100% and the latter is rarely 0%. For example, in Germany PV has effectively zero firm capacity value since the system peak is in the evening in the winter. On the other hand, ERCOT in Texas allots a capacity value to PV of about 80% of installed capacity, since the system peak in ERCOT is during summer afternoons and a high percentage of Texas PV can be expected to be available during those periods. Wind will have some capacity value because a percentage of wind production can be expected to be available as reliably during system peak as is the firm capacity percentage of various thermal resources, and offshore wind’s firm capacity credit will tend to be higher than onshore wind’s capacity credit. So you’re both partly right and partly wrong.
Michael Hogan, this nuance is not lost on me. I’m an energy systems expert too. 15 years of experience. MSc Engineering degree.
The nuance is lost on people who believe that a nuclear power plant fleet provides the same kind of reliable power 24/7 as a fleet of wind and/or solar power plants.
Oh wait, it was you who is urging people to believe this….
😉
Erm Yes.
I was not talking about high production of wind and solar in germany, I was talking about the interconnected grids, and their effects.
You tell that at 3.12 2014 peaker plants were operating in germany due to low wind and solar production? Wrong guess. the peaker plants remained offline that days, too. Exports droped close to zero, and some midload CCGT-Gasturbines were able to enter the market. Danmark could sell some Power in germany.
Interesting discussion. My view is that solar PV will simply stabilize wholesale poder prices, especially in the South of Europe, which is my region of interest. With the drastically falling construction costs of solar PV, its penetration in the power markets will continue as long as it remains profitable. It is as simple as that. What one should NOT do is promote certain energy sources by government subsidies. A big mistake that had destroyed the Spanish electricity market over the last 8 years and the consequences of which we are still paying for through extremely high end user prices. See for evidence my blog in jfbakker1963.blogspot.com. All articles related to energy have been published in official Spanish news media.
Well, the misunderstanding usually with solar in the years 2000-2014 is thart some people expect that it was instaled to produce power, and now complain that this power is expensive. No, it was produced and installed to create the industry and product solar power under cuthroat competition, and let the most efficent solution win. This was not cheap, but successful. Today solar undercuts all new generation (nuclear, coal, gas) in price in southern europe. So noone will build any new conventional plant there without big subsidies. So the existing plant will be wrecked without conventional replacement over time, according to age.
I agree with your comments and would observe (as a follow on to Mr Frik’s) that Portugal is now building utility-grade PV systems, with no subsidy. In my view, discussions (in Southern Europe) will now move from subsidy – or not (= not) to matching PV output to demand. The first stop in this journey (and the one with least costs) should be demand response (DR). The problem is making the connection between PV and DR. This is a mix of organisational (regulatory?) and technical (mostly IT kit – which is for the most part, low cost).
Interesting discussion. However, let us keep two objectives separate: what’s required to provide grid-level security and reliability and what’s required to diversify supply portfolio (because of many other reasons) in an area, region or a country. Economic rationale to achieve these two objectives could be very different !
Diversified generation also delivers increased reliability.
Germany deals with its high solar power production by exporting to the Netherlands, France, Denmark and Austria during the day. In the evening exports drop dramatically. This way the surrounding countries absorb much of the solar power production.
That’s normal trade between neighbors. Similar to: Germany absorbs most of the tomatoes we produce in Netherlands.
We (Netherlands) are now tripling the interconnection capacity with German grid. Two reasons:
1- we can import more power when German prices are lower;
2- we can export more (mainly wind) power when German prices are high.
The second reason becomes important when we have our projected off-shore wind capacity up and running.
The main winds come from the west. So the Germans get increased wind speeds (= increased production) 3-6 hours later. Which implies that we can export during those hours as then German prices will still be high.
But this way also follosws the demand function, and looked the same before solar power was installed in germany.
France was always exporting during the night (low demand, high share of infleixible baseloadpower in france) especially during summer, and importing during the day, especially during winter (power plant fleet in france is significant smaller than peak demand) Similar with other countries. The volume did rise, because due to solar power production peaker plants are not needed in germany to provide power during the day, so power prices do not rise any more during the day, as they did several years ago, which provides a incentive for other countries to buy more power from midload stations (or solar power, since they buy mixed power, but the price setting power plant is usually a midload plant, e.g. hard coal or CCGT) and leave peaker plants and inefficient plants switched off.
What is significant reduced or inexistent today is the trade with austrian and swiss hydropower, where a lot of baseload was imported to the alps during the night and sold back during noon. With flat prices all day now this trading model does not work any more. It is likely to work once more if a higher fraction of electricity comes from renewable intermittent sources.