As Nickrl says, they are quoting prices in 2012 money, but also we need to remember that all the earlier wind farms at much higher strike prices are still in business and will be for some years to come: they contribute to what we pay now.
The other thing that is misleading about the chart is that it includes low prices for wind farms that have been cancelled or are yet to be built (and may yet also be cancelled, as the prices are clearly uneconomic).
The graph is correct but If you read the notes you will see that it is 2012 prices ie 13yrs ago and we've had a bit of inflation since then! Its really misleading the govt continues to quote 2012 prices even now and that the media don't pick up on this. Davids item is based on todays prices ie the real cash that goes out the door.
Another key driver going forward is the rate at which CfDs now get actualised. AR3 ASPs were low even with indexation so will drag the average down. Lets see how many actualise although im surprised the solar ones have but presumably are banking on high probability of negative prices through the summer. Are they excluded from negative pricing?
The new solar CFDs will pay no compensation for any hour with a negative day ahead IMRP price. That's bad news for them, as they may struggle to get paid to curtail under the Balancing Mechanism, and the negative prices occur right when their output is a maximum. Pairing with batteries to shift output to the evening helps, but it is a substantial additional cost, starting with the efficiency loss through the battery and its capital cost.
Over the weekend we saw low holiday demand and very high wind potential. On Sunday there was over 6 hours of negative day ahead IMRP, so wind farms like Hornsea 1 curtailed voluntarily, apparently with no curtailment payment. Seagreen, which is behind a grid constraint, did manage to secure curtailment payments for most hours. Because the CFDs were offering no payment it meant that they were first in line to curtail, so ROC generation didn't need to enter into the bidding to curtail and secured its output and subsidies at a net positive revenue. Having said that, on Monday Moray East (now on a CFD) did get a payment at £80.91/MWh which is the highest for a while.
Even so we ended up with a lot of heavily subsidised exports for which consumers will be billed. When we have some metered data I may try to estimate what the real subsidy inclusive cost to consumers was for the day. Both days had balancing costs of ~£15m, which effectively added £25-30/MWh to bills.
Again thanks for clarity. It seems bizarre why solar would want to enter into these CfDs in the long run the mkt is going to be saturated on windless days and surely even the forward mkt are going to start to reflect the impact of solar in the summer months let alone the day ahead market.
Re Sunday NESO had a c19GW transmission connected forecast for Sunday but actual peaked around 12GW and in this weeks Operational Transparency Forum they report that c6GW of wind deloaded in the face of negative pricing although some of it was instructed back on with balancing actions. So they get around the negative pricing on the CfD and get a BM payment instead. Others have warned this sort of behaviour will become prevalent on high renewable days and is another prop pulled from underneath renewables are cheap myth.
Separately with the scale of outages on the Scottish Transmission currently, majority for upgrades or more windmill connections, transfer capacity South is c50-60% below max rating and any windmill in Scotland has high probability of being selected if it pitches it offer price low enough.
I think it depends upon the age of the contract. Generally speaking, I think the older ones don't get paid if day-ahead prices are negative for >=6 hours. More modern ones if negative prices persist for >= 1 hour. If they have batteries they could potentially bid prices up to just positive, collect the subsidy for the solar farm, charge the battery then resell the same energy at a higher price later.
The oldest contracts get paid the full strike price when market prices are negative. They have to absorb the negative element but end up well ahead. Along with wind farms on multiple ROCs per MWh they are last to curtail unless there is a very specific transmission constraint, and then they get a full payout: I've seen Hornsea 1 getting over £150/MWh for example.
Those on the six hour rule also get paid the full strike price for up to five hours of contiguous negative prices. Historically this tended tooccur on windy nights when demand was low, so seeing solar create the conditions is new and will only get worse as more capacity is added. It has been the case that if it was shaping up for 6 or more contiguous hours of negative prices the wind farms would bid up prices in the 6th hour to just positive and accept a loss on reselling that hour after the day ahead prices were set, so ensuring full strike price payment throughout. I drew OFGEM's attention to that gaming of the market which emerged during low demand 2020 under lockdowns, and so now we have the any hour rule for new contracts.
We now have differing incentives for different tranches of renewables which complicate the position. The LCCC require metering of actual output of the renewables generator even when they have storage behind their grid connection point, and the CFD is paid on that basis (with assessed transmission loss knocked off). The economic value of direct storage input from the generator is zero any time market prices are negative, quite independent of the extent of negativity. However the battery could do better by charging up from the grid at negative prices, so it isn't quite as free as you might first think. The income ex storage on discharge will of course be for a lower volume because of round trip losses through the battery. Also, freedom to participate in a number of ancillary markets is curtailed when the battery is specifically tied to a renewables generator. This tends to result in independent batteries though they might offer tolling agreements to local wind farms.
An exception to the rule is for the extremely unstable outputs than come from tidal stream generation. These are very flickery and disturb the small local grids they are connected to in Orkney and Shetland. The result is that they are required to use a battery or other means to smooth output: part charges from the flickery source, while part can be available to supply the grid. At O2 Orbital in Orkney they also use electrolysis for hydrogen to smooth the output but it probably does no good to the electrolyser and its efficiency.
Some great graphical representations of the market revenue and CfD subsidies. The increase in carbon price on SRMC will slightly push up the wholesale price but I think the projected locked in CfD payments going forward is £92.1bn, so only going one way.
The Institute for Government presents different figures. In here is a graph that shows offshore wind strike prices have dipped to below £50 MWh. https://www.instituteforgovernment.org.uk/comment/wind-solar-power-manifesto-results
Why the discrepancy?
As Nickrl says, they are quoting prices in 2012 money, but also we need to remember that all the earlier wind farms at much higher strike prices are still in business and will be for some years to come: they contribute to what we pay now.
The other thing that is misleading about the chart is that it includes low prices for wind farms that have been cancelled or are yet to be built (and may yet also be cancelled, as the prices are clearly uneconomic).
The graph is correct but If you read the notes you will see that it is 2012 prices ie 13yrs ago and we've had a bit of inflation since then! Its really misleading the govt continues to quote 2012 prices even now and that the media don't pick up on this. Davids item is based on todays prices ie the real cash that goes out the door.
Another key driver going forward is the rate at which CfDs now get actualised. AR3 ASPs were low even with indexation so will drag the average down. Lets see how many actualise although im surprised the solar ones have but presumably are banking on high probability of negative prices through the summer. Are they excluded from negative pricing?
The new solar CFDs will pay no compensation for any hour with a negative day ahead IMRP price. That's bad news for them, as they may struggle to get paid to curtail under the Balancing Mechanism, and the negative prices occur right when their output is a maximum. Pairing with batteries to shift output to the evening helps, but it is a substantial additional cost, starting with the efficiency loss through the battery and its capital cost.
Over the weekend we saw low holiday demand and very high wind potential. On Sunday there was over 6 hours of negative day ahead IMRP, so wind farms like Hornsea 1 curtailed voluntarily, apparently with no curtailment payment. Seagreen, which is behind a grid constraint, did manage to secure curtailment payments for most hours. Because the CFDs were offering no payment it meant that they were first in line to curtail, so ROC generation didn't need to enter into the bidding to curtail and secured its output and subsidies at a net positive revenue. Having said that, on Monday Moray East (now on a CFD) did get a payment at £80.91/MWh which is the highest for a while.
Even so we ended up with a lot of heavily subsidised exports for which consumers will be billed. When we have some metered data I may try to estimate what the real subsidy inclusive cost to consumers was for the day. Both days had balancing costs of ~£15m, which effectively added £25-30/MWh to bills.
Again thanks for clarity. It seems bizarre why solar would want to enter into these CfDs in the long run the mkt is going to be saturated on windless days and surely even the forward mkt are going to start to reflect the impact of solar in the summer months let alone the day ahead market.
Re Sunday NESO had a c19GW transmission connected forecast for Sunday but actual peaked around 12GW and in this weeks Operational Transparency Forum they report that c6GW of wind deloaded in the face of negative pricing although some of it was instructed back on with balancing actions. So they get around the negative pricing on the CfD and get a BM payment instead. Others have warned this sort of behaviour will become prevalent on high renewable days and is another prop pulled from underneath renewables are cheap myth.
Separately with the scale of outages on the Scottish Transmission currently, majority for upgrades or more windmill connections, transfer capacity South is c50-60% below max rating and any windmill in Scotland has high probability of being selected if it pitches it offer price low enough.
I think it depends upon the age of the contract. Generally speaking, I think the older ones don't get paid if day-ahead prices are negative for >=6 hours. More modern ones if negative prices persist for >= 1 hour. If they have batteries they could potentially bid prices up to just positive, collect the subsidy for the solar farm, charge the battery then resell the same energy at a higher price later.
The oldest contracts get paid the full strike price when market prices are negative. They have to absorb the negative element but end up well ahead. Along with wind farms on multiple ROCs per MWh they are last to curtail unless there is a very specific transmission constraint, and then they get a full payout: I've seen Hornsea 1 getting over £150/MWh for example.
Those on the six hour rule also get paid the full strike price for up to five hours of contiguous negative prices. Historically this tended tooccur on windy nights when demand was low, so seeing solar create the conditions is new and will only get worse as more capacity is added. It has been the case that if it was shaping up for 6 or more contiguous hours of negative prices the wind farms would bid up prices in the 6th hour to just positive and accept a loss on reselling that hour after the day ahead prices were set, so ensuring full strike price payment throughout. I drew OFGEM's attention to that gaming of the market which emerged during low demand 2020 under lockdowns, and so now we have the any hour rule for new contracts.
We now have differing incentives for different tranches of renewables which complicate the position. The LCCC require metering of actual output of the renewables generator even when they have storage behind their grid connection point, and the CFD is paid on that basis (with assessed transmission loss knocked off). The economic value of direct storage input from the generator is zero any time market prices are negative, quite independent of the extent of negativity. However the battery could do better by charging up from the grid at negative prices, so it isn't quite as free as you might first think. The income ex storage on discharge will of course be for a lower volume because of round trip losses through the battery. Also, freedom to participate in a number of ancillary markets is curtailed when the battery is specifically tied to a renewables generator. This tends to result in independent batteries though they might offer tolling agreements to local wind farms.
An exception to the rule is for the extremely unstable outputs than come from tidal stream generation. These are very flickery and disturb the small local grids they are connected to in Orkney and Shetland. The result is that they are required to use a battery or other means to smooth output: part charges from the flickery source, while part can be available to supply the grid. At O2 Orbital in Orkney they also use electrolysis for hydrogen to smooth the output but it probably does no good to the electrolyser and its efficiency.
Some great graphical representations of the market revenue and CfD subsidies. The increase in carbon price on SRMC will slightly push up the wholesale price but I think the projected locked in CfD payments going forward is £92.1bn, so only going one way.