Thank you for your continuing exposing of the scam that is 'renewable energy'. The piece on interconnectors was excellent. Financialisation of the energy market has clearly distorted input costs to an extreme, an anathema to the 'free market' obvious for all to see. One minor question, are we still referring to all hydrocarbons as 'fossil fuel' because that concept, pursuant to discovery on Saturn's moons of the aforementioned, implies that hypothesis (of limit and control) has gone the way of the dodo unless we're postulating space dinosaurs and vacuum ferns... Rgds.
I pointed out on your interconnector analysis article that the NGESO data you used only applies to the balancing trades that NGESO themselves conduct. I did a fuller analysis of each interconnector using the data from BMReports/Elexon and IMRP day ahead hourly prices (which are a bit more favourable than NGESO's balancing trades, although those will be included in the overall volume of flows). Summary:
Our trade last year with France included some 160GWh of counterflow on Eleclink and IFA1, with one exporting while the other imported, sending electricity round in circles, and adding 160GWh to exports and imports. These events were frequent – almost daily, and often lasted up to several hours. The worst case saw the entire 1GW capacity of Eleclink being used in counterflow, though usually such flows were 500MW or less.
Trade with France valued at hourly day ahead prices was
In addition, the not inconsiderable costs of connecting these new wind and solar farms to the grid have not been included in this analysis.
The costs of connecting all these renewables has been estimated as having to add 5 TIMES the grid cabling at a cost of 54bn which is all going to be added to bills and is directly attributable to Renewables, and of course 5 times the cabling comes with 5 times the maintenance costs which will also be going on your bills.
AND we haven't even started to cross the Rubicon of trying to build the infrastructure and back up kit necessary to remove gas from the grid, and that's a whole new world of costs and pain for bill payers which will costs multiples of the cost of sticking with gas.
How long before the public start to ask the question - if renewables is so cheap, why are my electricity bills going up year on year well ahead of inflation?
That day will come, and those that pushed this narrative will have to answer when the music stops.
And why do the countries with the most wind and solar have the highest energy prices? and of course energy prices as the biggest issue to economic competitiveness, no wonder growth has slowed to a standstill.
I have also analysed the value of generation output at hourly day ahead prices by type for 2023, with the following results:
Demand £98.99/MWh - calculated as grid connected generation per BM reports/Elexon plus solar estimates from Sheffield Solar plus net interconnector flows and net pumped storage (i.e. treating pumping as not being part of demand, while PS generation is treated as part of supply and therefore demand). This is a premium to the straight time average of hourly prices (£94.14/MWh) as might be expected because prices tend to be higher when demand is higher, and vice versa. It is a better benchmark when comparing values.
BIOMASS £100.58/MWh This is higher than might be expected for pure baseload, and indeed it doesn't operate that way entirely. Plants do tend to get turned down when day ahead market prices are lower, since the ROC subsidy (1ROC/MWh) may not be enough to make operation viable. For those plants operating under CFDs the economics are dominated by the Basleoad Market Reference Price, set for six months at a time based on thinly quoted long duration forward baseload contracts. That has meant that the summer price was set by winter trading conditions when it was unclear whether French nuclear would be adequately restored, so prices were defensively high. This chart shows the extent of the disincentive (effectively a tax) and the consequences for CFD generation, restricted to conditions where day ahead prices were at a premium to BMRP - i.e. extremely tight markets.
CCGT £105.91/MWh - Obviously at a premium to demand, since it is the prime source of flexibility for filling in when wind and solar fail.
COAL £114.81/MWh Since coal was mainly used for peak shaving, its average value was at a substantial premium to demand. Use for baseload was discouraged for much of the year by high UKA Carbon allowances that are a tax on coal generation. However, since those prices collapsed RATS (our remaining coal station) has often found it profitable to operate as baseload unless the underlying weather is windy.
NPSHYD £104.28/MWh Regular hydro is mainly used to balance wind in Scotland, and so earns a similar income to CCGT
NUCLEAR £93.47/MWh Nuclear clearly suffers from not being able to turn down when wind surpluses drive prices to low and negative values - even wind manages to do that a bit, and get paid for doing so! Wind cannibalises baseload prices, and has contributed to the ongoing demise of nuclear and coal shown by the long term generation profile charts in the article.
OCGT £130.41/MWh Being very rapid response, OCGT gets the highest market value overall, although utilisation is very limited
OIL £77.73/MWh This seems an oddity, since AFAIK all oil fired power stations were closed and no longer even available on a standby basis: possibly a data glitch.
OTHER £104.94/MWh National Grid are very coy about what is included under other. Such candidates as anaerobic digestion and even diesel STOR are not usually grid connected. However, production profiles indicate it is probably mainly diesel sited at major power stations for startup
Pumped Storage made a gross margin of £54m redelivering 1,750GWh to the grid at 76.3% round trip efficiency. It will, in common with some other generators, also have earned an income from providing ancillary services such as spinning reserve - called into action on 22nd December to prevent a blackout - and inertia based frequency stabilisation, where it also competes with batteries, for which we have no data. The low margin indicates how hard it would be for storage to earn enough to pay for itself in a net zero world, where the need is to hold in store for months at a time, not just a few hours.
SOLAR £85.32/MWh shows how low is the value of midsummer midday surpluses and the effect of contributing next to nothing in wintertime when demand is high.
WIND £90.26/MWh again shows the effects of producing unwanted surpluses, and not being at the match when supply is really needed.
N.B. - these are market valuations using day ahead prices, which is probably as good as any method of measuring real market value over time. Using the balancing mechanism System Sell/Buy clearing prices (which are based on an average of costs of balancing actions) would produce somewhat different results. They do NOT reflect what we actually pay because not all electricity is traded on a day ahead basis with some traded well in advance as a hedge, and the balance later, up to and including the Balancing Mechanism and because they do not include the subsidies for renewables, most of which are paid against actual generation: these can be very substantial being worth currently around £65/MWh for onshore wind and biomass and £120/MWh for offshore wind on ROCs, while CFDs average a strike price of around £160/MWh across all CFDs currently operating - a substantial premium to current market prices.
Thank you for your continuing exposing of the scam that is 'renewable energy'. The piece on interconnectors was excellent. Financialisation of the energy market has clearly distorted input costs to an extreme, an anathema to the 'free market' obvious for all to see. One minor question, are we still referring to all hydrocarbons as 'fossil fuel' because that concept, pursuant to discovery on Saturn's moons of the aforementioned, implies that hypothesis (of limit and control) has gone the way of the dodo unless we're postulating space dinosaurs and vacuum ferns... Rgds.
I pointed out on your interconnector analysis article that the NGESO data you used only applies to the balancing trades that NGESO themselves conduct. I did a fuller analysis of each interconnector using the data from BMReports/Elexon and IMRP day ahead hourly prices (which are a bit more favourable than NGESO's balancing trades, although those will be included in the overall volume of flows). Summary:
Our trade last year with France included some 160GWh of counterflow on Eleclink and IFA1, with one exporting while the other imported, sending electricity round in circles, and adding 160GWh to exports and imports. These events were frequent – almost daily, and often lasted up to several hours. The worst case saw the entire 1GW capacity of Eleclink being used in counterflow, though usually such flows were 500MW or less.
Trade with France valued at hourly day ahead prices was
GWh Eleclink IFA1 IFA2 France
Import 4,648 7,159 3,803 15,610
Export -813 -1,265 -675 -2,753
Net Import 3,835 5,894 3,128 12,857
Import £95.07 £96.78 £98.37 £96.66
Export £93.53 £83.98 £87.46 £87.65
Utilisation 62.3% 48.1% 51.1% 52.4%
The other Continental links:
GWh BritNed NEMO NSL Viking
Import 4,262 3,983 8,942 64
Export -1,587 -1,003 -414 -12
Net Import 2,675 2,981 8,529 52
Import £104.09 £99.15 £99.27 £68.07
Export £79.19 £79.63 £37.33 £70.45
Utilisation 66.8% 56.9% 76.3% 0.6%
Ireland
GWh E-W Moyle Ireland
Import 239 422 661
Export -1,915 -2,454 -4,369
Net Import -1,676 -2,032 -3,708
Import £107.72 £103.45 £105.00
Export £86.80 £91.21 £89.28
Utilisation 49.2% 65.7% 57.4%
Overall
GWh Total GB
Import 33,522
Export -10,137
Net Import 23,385 =4,984MW on average
Import £98.70
Export £84.16
Utilisation 59.3%
Great article! Did you include the cost of constraint payments in the balancing costs?
As you said
In addition, the not inconsiderable costs of connecting these new wind and solar farms to the grid have not been included in this analysis.
The costs of connecting all these renewables has been estimated as having to add 5 TIMES the grid cabling at a cost of 54bn which is all going to be added to bills and is directly attributable to Renewables, and of course 5 times the cabling comes with 5 times the maintenance costs which will also be going on your bills.
AND we haven't even started to cross the Rubicon of trying to build the infrastructure and back up kit necessary to remove gas from the grid, and that's a whole new world of costs and pain for bill payers which will costs multiples of the cost of sticking with gas.
How long before the public start to ask the question - if renewables is so cheap, why are my electricity bills going up year on year well ahead of inflation?
That day will come, and those that pushed this narrative will have to answer when the music stops.
And why do the countries with the most wind and solar have the highest energy prices? and of course energy prices as the biggest issue to economic competitiveness, no wonder growth has slowed to a standstill.
I have also analysed the value of generation output at hourly day ahead prices by type for 2023, with the following results:
Demand £98.99/MWh - calculated as grid connected generation per BM reports/Elexon plus solar estimates from Sheffield Solar plus net interconnector flows and net pumped storage (i.e. treating pumping as not being part of demand, while PS generation is treated as part of supply and therefore demand). This is a premium to the straight time average of hourly prices (£94.14/MWh) as might be expected because prices tend to be higher when demand is higher, and vice versa. It is a better benchmark when comparing values.
BIOMASS £100.58/MWh This is higher than might be expected for pure baseload, and indeed it doesn't operate that way entirely. Plants do tend to get turned down when day ahead market prices are lower, since the ROC subsidy (1ROC/MWh) may not be enough to make operation viable. For those plants operating under CFDs the economics are dominated by the Basleoad Market Reference Price, set for six months at a time based on thinly quoted long duration forward baseload contracts. That has meant that the summer price was set by winter trading conditions when it was unclear whether French nuclear would be adequately restored, so prices were defensively high. This chart shows the extent of the disincentive (effectively a tax) and the consequences for CFD generation, restricted to conditions where day ahead prices were at a premium to BMRP - i.e. extremely tight markets.
https://i0.wp.com/wattsupwiththat.com/wp-content/uploads/2024/01/Biomass-CFD-Gen-1705529648.0472.png
CCGT £105.91/MWh - Obviously at a premium to demand, since it is the prime source of flexibility for filling in when wind and solar fail.
COAL £114.81/MWh Since coal was mainly used for peak shaving, its average value was at a substantial premium to demand. Use for baseload was discouraged for much of the year by high UKA Carbon allowances that are a tax on coal generation. However, since those prices collapsed RATS (our remaining coal station) has often found it profitable to operate as baseload unless the underlying weather is windy.
NPSHYD £104.28/MWh Regular hydro is mainly used to balance wind in Scotland, and so earns a similar income to CCGT
NUCLEAR £93.47/MWh Nuclear clearly suffers from not being able to turn down when wind surpluses drive prices to low and negative values - even wind manages to do that a bit, and get paid for doing so! Wind cannibalises baseload prices, and has contributed to the ongoing demise of nuclear and coal shown by the long term generation profile charts in the article.
OCGT £130.41/MWh Being very rapid response, OCGT gets the highest market value overall, although utilisation is very limited
OIL £77.73/MWh This seems an oddity, since AFAIK all oil fired power stations were closed and no longer even available on a standby basis: possibly a data glitch.
OTHER £104.94/MWh National Grid are very coy about what is included under other. Such candidates as anaerobic digestion and even diesel STOR are not usually grid connected. However, production profiles indicate it is probably mainly diesel sited at major power stations for startup
Pumped Storage made a gross margin of £54m redelivering 1,750GWh to the grid at 76.3% round trip efficiency. It will, in common with some other generators, also have earned an income from providing ancillary services such as spinning reserve - called into action on 22nd December to prevent a blackout - and inertia based frequency stabilisation, where it also competes with batteries, for which we have no data. The low margin indicates how hard it would be for storage to earn enough to pay for itself in a net zero world, where the need is to hold in store for months at a time, not just a few hours.
SOLAR £85.32/MWh shows how low is the value of midsummer midday surpluses and the effect of contributing next to nothing in wintertime when demand is high.
WIND £90.26/MWh again shows the effects of producing unwanted surpluses, and not being at the match when supply is really needed.
N.B. - these are market valuations using day ahead prices, which is probably as good as any method of measuring real market value over time. Using the balancing mechanism System Sell/Buy clearing prices (which are based on an average of costs of balancing actions) would produce somewhat different results. They do NOT reflect what we actually pay because not all electricity is traded on a day ahead basis with some traded well in advance as a hedge, and the balance later, up to and including the Balancing Mechanism and because they do not include the subsidies for renewables, most of which are paid against actual generation: these can be very substantial being worth currently around £65/MWh for onshore wind and biomass and £120/MWh for offshore wind on ROCs, while CFDs average a strike price of around £160/MWh across all CFDs currently operating - a substantial premium to current market prices.
Excellent analysis. Love the graphics.