Over the past few months we have been inundated with claims from interested parties that more renewables are the (only) solution to the energy crisis. They also claim that renewable energy is cheap, deflationary, and will deliver lower bills to consumers. They tend to ignore questions about managing intermittency and the cost of back-up, pointing to “studies” that show a near-100% renewables energy system is “possible”. Some are actually quite rude when challenged on the subject (I have been invited to educate myself and told I may as well work in a shop, which seems offensive both to me and to retail workers…). In this post I will explore the actual cost of renewable generation for consumers. Anyone who finds actual data inconvenient or offensive should look away now…
Setting the scene
I think it is important to remember what we had before we began the energy transition. In Britain, we were just finishing the decade-long process of privatising and un-bundling the electricity market. At the turn of the century, we had an electricity system that was heavily fossil-fuel dominated, and arguably over-supplied as a result of the “dash for gas”. The decade since 1990 had seen electricity bills falling, so privatisation was largely seen as a success. Electricity was generated in large power stations connected to the high voltage grid, and demand was for the most part passive. Balancing supply and demand in real time was relatively simple – demand fluctuated based on the weather in largely predictable ways and output could be dispatched to match. Capacity margins were healthy, and blackouts were only thought of in the context of industrial action (memories of the 1970s being still fresh) or acts of God such as lightning hitting key infrastructure.
The beginning of this century saw two major changes: the first was the final separation of the “last mile” of the electricity market with the creation of suppliers and their separation from network companies under the Utilities Act 2000. Now consumers had proper choice over from whom to buy their energy. The second major change was the introduction of the Climate Change Levy in 2001 and the Renewables Obligations in 2002 (yes, it is now 20 years since we started subsidising off-shore windfarms). The years since these changes have seen end user electricity costs rise steadily, while wholesale prices have shown no such trend.
Costs of renewables are (not) falling
“Renewables” is a broad church, and in some respects the costs have been falling. Small-scale solar schemes are no longer eligible for subsidies in Britain, but they continue to be built, albeit at a slower rate. Most new solar projects are large-scale, and overall 1 GW of new capacity has been added since the subsidy schemes ended. However, costs have been rising in the past couple of years due to supply chain issues.
This illustrates the difficulty of the falling costs narrative: as technologies mature, the experience curve dictates that costs will fall, but they are not immune to global supply and demand dynamics. As technology costs fall, demand might increase, and if supply cannot keep up, then prices will rise, irrespective of any gains from the experience curve. This has certainly been seen in the case of solar panels, with constraints in the polysilicon supply chain (setting aside the ethical issues of buying materials tainted by claims of forced labour use).
Renewables advocates point to declining Contracts for Difference (“CfD”) strike prices as evidence the costs of renewables are falling. It is certainly a fact that CfD prices have been falling, but it is less easy to understand why. It is also reasonable to question why, after 20 years, subsidies are still required – 20 years should be long enough for a technology to mature to a level where subsidies are not needed, so perhaps the need for CfDs at all for technologies such as off-shore wind should be scrutinised.
I have previously referenced the work of Professor Gordon Hughes at the University of Edinburgh which shows that the capex and opex costs of offshore wind are not falling, contrary to the popular narrative that they are. I have also validated his work with my own research – most large UK wind projects are incorporated as SPVs and as such their accounts are publicly available at Companies House. These accounts show, for anyone with the patience to go through them, that the much vaunted price reductions are not happening in practice.
“The actual costs of onshore and offshore wind generation have not fallen significantly over the last two decades and there is little prospect that they will fall significantly in the next five or even ten years… Far from falling, the actual capital costs per MW of capacity to build new wind farms increased substantially from 2002 to about 2015 and have, at best, remained constant since then…the operating costs per MW of new capacity have increased significantly for both onshore and offshore wind farms over the last two decades,”
– Professor Gordon Hughes, University of Edinburgh
It is difficult to square this with falling CfD auction prices, but the CfD only needs to support cashflows for debt repayment – it is likely that once the subsidies expire many schemes will be uneconomic unless high power prices persist, which undermines the “renewables provide low cost energy” arguments.
Hughes postulates that three factors may explain falling CfD prices: the dominance of large, often state-controlled companies in the off-shore wind sector that can deploy large cash flows from existing businesses, and which are under little pressure to return cash to either customers or shareholders; the operators may expect to be able to sell a large portion of their shares in the projects to over-optimistic investors while projects also rely heavily on debt provided by equally naïve lenders; and operators / financial investors may expect to be bailed out, since once the financial consequences of the underlying economics become undeniable there will be pressure to pass the full costs of these projects to either electricity consumers or taxpayers.
I’m doubtful that operators or investors are thinking that deeply…I suspect that as long as they can get deals done they are happy to buy into the falling costs narrative, particularly since the day of reckoning when the subsidy schemes expire is 15 years away at which point the individuals concerned will most likely have moved on.
In fact there is now a consensus that rising prices of materials such as steel and copper will have to be passed on to customers, driven in part by the war in Ukraine, so all new infrastructure investments including renewable generation will be subject to higher costs and possible supply chain disruptions. This may well change bidding behaviour in future CfD auctions, reversing the downwards trend, while some energy companies have already booked impairments on renewables projects under construction.
Renewables do not provide cheap electricity
Renewables supporters also claim that the energy they provide is cheap, an argument which has widespread appeal since it is clear to everyone that wind and sunshine are free. Unfortunately, this fact isn’t that relevant when considering the cost of renewable generation, because what matters is the cost of reliable electricity which includes the electricity that has to be provided when it isn’t windy or sunny.
This study published in February by US-based think tank American Experiment highlights to costs of renewable generation to end users. This study assesses how the Virginia Clean Economy Act (“VCEA”) would increase costs for consumers and make the grid more fragile. It also assesses an alternative scenario, the Reliable Resource Scenario (“RRS”), where reliability and affordability are prioritised.
“Offshore wind dramatically increases the cost of providing the electricity Virginians rely upon. This energy source will cost $154 per megawatt-hour (MWh) when the often-hidden transmission costs, property taxes, utility returns, and battery storage costs are accounted for. The VCEA will reduce the reliability of the grid by making the state more reliant upon weather-dependent energy sources like wind and solar, and energy imports from other states. This is the same strategy California has pursued, with unenviable results.”
The VCEA proposal would see an electricity mix free from fossil fuels by 2050, with around 30% of electricity coming from nuclear and hydro, 15% from imports and the rest from intermittent renewables and batteries. The RRS alternative has a similar amount of nuclear, hydro and imports, but has half of electricity coming from natural gas.
The conclusions are not specific to Virginia, they are generically true for all markets where fossil fuel based generation is being displaced by subsidised intermittent renewables. The study points out that the LCOE (Levelised Cost of Energy, which reflects the cost of generating electricity from different types of power plants, on a per-unit of electricity basis over an assumed lifetime and quantity of electricity generated by the plant) for renewables is higher than for fossil fuel generation once the costs of backing-up their intermittency is included, something many analyses including the ones used by BEIS, fail to include. Cost comparisons should reflect the costs of delivering reliable electricity to end users, ie the cost to meet demand, so ignoring intermittency invalidates these comparisons.
The key inputs in the BEIS LCOE calculations are pre-development costs, construction costs, fixed and variable operations and maintenance costs, the load factor and the operating period. So while the costs are adjusted to reflect periods of intermittency they do not include the cost of the technology required to fill the gap. This means that comparisons with conventional generation are flawed since conventional generation will provide electricity whenever it is needed and does not depend on unpredictable external factors such as the weather.
Another recent study by the University of Nottingham has shown that a wide-scale deployment of small-scale renewables can reduce grid resilience and may lead to failures. They studied smart meter data to track changes in grid composition over time and found resilience varies over the course of a day and that a high uptake of solar PV can increase the vulnerability of the grid. They also found that the addition of domestic batteries, while supporting consumer self-sufficiency, does not significantly reduce these risks.
“The increasing proliferation of small, intermittent renewable power sources is causing a rapid change in the structure and composition of the power grid. Indeed, the grid’s effective structure can change over the course of a day as consumers and small-scale generators come on- and off-line. Using data from smart meters in UK households we tracked how grid composition varies over time. We then used a dynamical model to assess how these changes impact the resilience of power grids to catastrophic failures. We found that resilience varies over the course of a day and that a high uptake of solar panels can leave the grid more susceptible to failure,”
– Oliver Smith, researcher at the University of Nottingham
There are just over a million small-scale domestic solar systems in the UK. They are low-output, intermittent and tend to be distributed across power grids in large numbers. The power they supply to the grid in export mode is unpredictable with generators going on and off-line intermittently – households adopt the role of consumers or producers, as usage and weather conditions vary both throughout the day and across the year. The Nottingham analysis shows that microgrids spend most of their time operating in the least favourable conditions for grid resilience, across all ranges of PV uptake due to a supply-demand discrepancy. This means microgrids are alternately dominated by either consumption or generation and are therefore unable to exploit the robustness advantages that increased distribution would be expected to provide.
Domestic batteries are designed to support consumers in being self-sufficient, and are rarely configured to export to the grid in a domestic setting, meaning they do little to mitigate the effects that domestic solar has on the grid. While new technologies such as V2G (vehicle-to-grid) services may help to meet this need, appropriate power control systems will be essential to capturing this potential benefit, as well as a willingness on the part of consumers to relinquish control of their assets to third parties.
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End user prices have risen steadily over the past 20 years, in line with the subsidisation of renewable generation. While correlation does not necessarily indicate causation, no such trend is evident in wholesale prices, and with the increased deployment of renewable generation, consumers have faced not only the costs of subsidies, but also the costs of building new grid infrastructure to connect these renewables, as well as the costs of balancing their intermittency and providing back-up for when wind drops or there is no sun (it is depressing how often people need to be reminded that the sun sets before the winter evening peak, meaning solar contributes absolutely nothing to the periods of highest grid demand).
The past few months have seen a significant increase in wholesale prices. When added to the other cost increases, this is making electricity increasingly unaffordable for many consumers. As fuel poverty rises, it is time to recognise that renewable electricity is not cheap. This does not necessarily mean it is wrong to develop it, but it is time to be honest about the costs, and consider pausing new subsidies while issues of affordability are addressed, particularly as the cost of new projects is set to rise.
So, like your previous blog on the energy strategy, what’s the best answer to:
– Energy Independence (for the UK)
– Low cost and reliable electricity
– Saving the planet
I’m attracted to;
– Small Nuclear, more local – (like the rolls royce subs ones)
– Local storage and generation – whether thats pumped storage or the hydrogen thingy, supporting solar, wind etc
But I can’t make a technical justification
In the short term the solution has to be keeping coal open (the climate impact would be minimal but we need it as insurance) and more gas. Longer term we need nuclear (large and small) and more storage. I’m not convinced the economics of hydrogen stack up as a storage only mechanism, but new technologies such as cryogenic and compressed air show promise.
And we need to address the demand side and tackle energy waste which will support all three aspects of the trilemma: susainability, affordability and security of supply.
The energy stored in compressed air is roughly PV, so at 500bar that’s 50MJ/cu m. Methane is about 39MJ/cu m at s.t.p., so even at 100bar you are getting 3910MJ/cu m. Not many sites for compressed air: the Larne salt cavern is the notable one.
The bankrupt firm behind plans for a large-scale compressed air energy storage (CAES) plant in Northern Ireland has withdrawn its planning application for the project.
Gaelectric, which entered administration proceedings in 2017, has withdrawn a planning application for its proposed 330 MW Larne project through KPMG, its liquidator.
Gaelectric submitted plans in December 2015 to Northern Ireland’s Department for Infrastructure for the CAES project in Islandmagee and in 2017 won €90 million of EU funding as an EU project of common interest (PCI).
KPMG has been running a sale of Gaelectric assets and had hoped to find a buyer for the Larne CAES.
The project would have required the development of three 230 000 m3 salt caverns approximately 1.5 km below ground level to store compressed air and provide between six and eight hours of energy.
Highview’s LAES is getting some funding, but it isn’t really suited to longer term storage, because you keep having to re-liquefy the boiloff to maintain capacity, eating into round trip efficiency – and it isn’t all that efficient to begin with unless you ignore “free” heat or coolth, albeit it can use low grade heat and coolth as part of the gasification and liquefaction processes. It is developing up to 2 GWh of “long duration”, liquid air energy storage projects across Spain for an estimated investment of around $1 billion.
For comparison, Coire Glas is 30GWh/1.5GW of pumped hydro for “over £1bn”.
Finally, a rounded view of the real cost of renewables. The dispatchability component is critical and conveniently left out. Can we change LCOE to SCOE (system cost)?
2022-04-11 @ 9am. Watt-Logic Renewables.
Kathryn,
Well done for blowing a hole in the Renewable craze and reminded the politicians the Sun and Wind only produce a volatile, unpredictable output. In the case of the UK we are fortunate to still have CCGT (Gas) stations which mirror the Renewables and make-up the shortfall on a daily if not hourly basis.
By courtesy of http://www.gridwatch.templar.co.uk/ I quote: –
Starting on Saturday, 19th March 2022, Wind was good with 13GWs from a possible installed 14 or so.
However, Sunday 20th March at 9am this had fallen to less than 4GWs.
Monday 21st March it was about 2GWs and in following days went even lower – often as low as 0.19GWs, until it recovered to 12GWs on Thursday, 31st March – a full 10 day period of basically no output.
It crashed again on Saturday, 2nd April to 2GWs recovering to 13GWs on Monday, 4th April but crashing on Sunday, 10th April to less than 1GW.
Solar was peaking between 7GWs and 2 during this period.
Remember, to use your kettle you need a 24/7 supply of power and without CCGT in the UK, Renewables would not have supplied it during this period.
For the Government to suggest a projected installation of 50GWs of Wind & 70GWs of Solar is plainly silly.
Fortunately, this Winter has been kind to us – I hate to think what would have happened had we have had a 1947, 1963, 1982 etc type Winter or with the state of the European & UK Nuclear situation – the coming Winters.
John Bowen
Your Clifford Talbot chart of wholesale gas and electricity prices should have the scale for gas labelled p/kWh, not p/therm.
✓✓✓✓✓…. Well spotted… that unit rate had me confused as well…I was sure that I was correct…
Thanks – force of habit to label gas in therms. I’ve updated the chart.
I note that at the end of last month Ørsted sold a 50% interest in their 1.3GW Hornsea 2 offshore wind project to AXA for £3bn, hoping to book a profit of DKK9-10bn or over £1bn on the deal, and reflecting the comment you made about naive investors. That reveals a huge disconnect between industry and government expectations of the future cost of offshore wind. The project can expect say 600MW average generation, or 5.3TWh per year, 2.65TWh for 50%. The capital charge cost for amortising the investment plus interest is about 8% p.a., or £240m p.a. over the life of the wind farm. That implies over £90/MWh (240/2.65) just for amortisation. Maintenance costs are of the order of another £20/MWh. The current value of the Hornsea 2 CFD is £73.71/MWh.
It would seem that there is no expectation of taking up the CFD when the project is completed, and an expectation that even allowing for curtailment average revenues will be over £110/MWh. With no CFD protection for curtailment the project can expect perhaps 25% of its potential output to be worthless, so they are expecting production revenue to be over £145/ MWh, supported by capacity shortages and carbon taxes. I also note that Triton Knoll 3 still has not commenced its CFD despite commissioning in January: its CFD is currently worth £94.81/MWh.
It is starting to look like those low strike price CFDs are meaningless, other than for securing the right to build a project. The government are deluded if they are relying on them.
Overly negative
The 13-16MW offhsore turbines that will be installed in UK look to be around £2.5 million per MW capacity installed
Of which the turbine itself is less than £1 million per MW
A 1GW offshore farm will cost £2.5 billion if it lasts 27.5 years it will generate 144 TWh
If you borrow financing at 3% and inflation is 3% it nets to zero so to keep it simple £2.5 billion/ 144TWh = £17.36/MWh
And since the turbine itself is only about 40% of the cost its quite likely that in 25-30 years when these things are end of life a lot of the infrastructure will still be functional so the second time around it might be £1 billion /GW just to replace the turbines as the foundation and offhsore and onshore substations should be good for a lot longer than 25-30 years
I read your blogs with much interest and admiration for your depth of analysis.
Clearly, more energy storage is needed to accommodate the problem of increasing intermittency: but I haven’t noticed your taking into account the possible/probable technical advances that, potentially, could make a significant contribution to solving this problem. There are several unused mine cavities in the north of England which could be converted to pumped hydro facilities provided surface storage could be arranged. More promising is the RheEnergise technology, now being developed, which could, potentially, provide energy storage more amenable to control by grid management than small-scale solar generation. Another technology being developed, by FuelPositive in Canada, would have the potential to consume surplus energy as it became available and release it as a green fuel, ie ammonia or hydrogen.
You may find this interesting
https://www.current-news.co.uk/blogs/a-new-generation-of-pumped-hydro-rheenergises-high-density-hydro-solution-opens-up-geographies
The reality is that these are small scale operations, really designed around shifting solar from midday. 10-50MW with 4-8 hour duration, provided you can find a convenient hill: E=mgh is still the underlying physics, even if V can be cut because ρ=2.5 in m=ρV. I get the impression that the design is for enclosed reservoirs. It’s not going to begin to touch the interseasonal storage requirements of a high renewables grid.
The ammonia project is basically high cost green hydrogen plus standard nitrogen extraction fed to a small scale proprietary process replacing the high pressures and medium temperatures of the Haber process. To be competitive it needs subsidised or free power for electrolysis. Free power is in fact subsidised by the power that people pay for. TANSTAAFL.
The UK would function fine with the following
50GW CCGTs = £40 billion
50GW offshore wind = £100 billion
That would get ~263 TWh from wind power
The same £140 billion could only buy you ….
17GW nuclear = £115 billion
33GW CCGTs = £26 billion
You would get 134 TWh nuclear
So £140 billion buys you twice as much offshore wind than it dies nuclear. In both examples you have 50GW firm supply
The economics of offshire wind in the UK has won. Its just taking time for the anti wind crowd to accept reality
Lots of holes in your numbers. Demand is a variable, especially if you aim to include heating. Wind is not going to yield 60% capacity factors, and it will often be producing when demand is low, so the useful output is way below the total because of curtailment: capital cost is “ambitious”. Costs need to include fuel and maintenance and other elements such as grid costs, and recognise you’ll be replacing the wind farm after 20 years or so along with supporting batteries every 10 years. Your nuclear costs assume we build expensive plant. The RR SMR costing would be £65bn for 17GW.
Lets not overlook the vast amount of CAPEX NG is proposing its needs to invest in the grid to transport the renewable energy to where its needed as well the millions being invested in battery projects to provide frequency response services. All of this will be added to our bills particularly the standing charge. So even if you turn every thing off you will still be on the hook for £100’s a year.
“Let’s not overlook the vast amount of CAPEX NG is proposing its needs to invest in the grid to transport the renewable energy to where it’s needed ….”
And that’s before Greens and enviros object, and so attempt to add £multi-billions to the transmission costs ….
https://www.edp24.co.uk/news/23052367.row-cost-running-pylon-route-offshore/
https://www.nationalgrid.com/electricity-transmission/document/146091/download
In a sale of interest the original cost of the asset is largely irrelevant. Indeed, Ørsted expect to book a profit of over £1bn from the sale. The price is essentially defined by the expected revenues, and that’s the key point here. Ørsted are only offering a 20 year maintenance contract, so your life looks to be on the high side.
Looking at the CFD payments now we have the uprated April indexation in place I note there is as yet no sign if Hornsea 2 which started generating in December, on top of the absent 3rd phase of Triton Knoll. Are these CFDs ever going to be exercised? The average CFD in payment weighted by production is paying £150/MWh, and now Drax and Lynemouth are finally faced with a Baseload Market Market Reference Price of £168.25/MWh for the next 6 months. Intermittents average strike price is now back over £160/MWh.
I nite that the Energy APPG that you talked to previously are holding a meeting on April 26th. Are you contributing or attending? They could do with a dose of your common sense and sharp analysis.
The problem with the Hughes numbers on offshore wind opex is that they treat the “opex” cost at the SPV level as representing the opex cost of keeping the equipment running at all when this simply isn’t the case. The way that OEM agreements for wind projects are structured is that during the subsidy period (when capture prices are guaranteed to be high) the OEM guarantees that if availability targets are not met, the OEM will pay out substantial compensation. This also has the impact of increasing the amount of debt in the capital structure since deals structured this way are much more bankable.
After the subsidy period ends, the operator has a range of options, including taking asset management decisions back in-house and simply paying the OEM for repairs and scheduled inspections as and when required. This is a very substantial saving.
Therefore simply extracting opex numbers from SPV accounts doesn’t work because it doesn’t get you the “naked” opex cost without the cost imposed by the OEM for providing a very high availability guarantee. Hughes assumes that these opex costs are really the marginal opex costs and therefore when the marginal revenue from power sales falls below these costs, the turbine becomes uneconomic to operate. This also has the obvious effect of increasing the capex component of LCOE since the operating life is now curtailed well before its technical end of life and the value of the foundations etc. is assumed to be zero since the project is assumed to end.
Actual estimates of marginal opex, built bottom-up from inspection and component replacement costs, are much lower, in the single digits £/MWh which justifies an extended economic lifetime for offshore wind assets. The capex for (at least) the foundations is also expected to be recovered over at least another generation of turbines since the lifetime of these civil structures is longer than the tower itself (due to aeroelastic fatigue loading) which in turn is longer than the generator and moving parts on the nacelle. The gearbox (if any) and blades have the shortest life and will need replacing on average during the CfD lifetime.
However it’s also important to understand the effect on the LCOE of high capex / low opex technologies like renewables and nuclear of low risk free rates. Since basically all the cost is up-front, dropping the reference from which debt and equity costs is derived is going to have a big impact on a discounted metric like LCOE. Compare with a gas turbine where on-going fuel expenditure is a much bigger component of costs and therefore financing costs are less impactful. We have had an extended period of low and dropping RFRs and the effect this has had on LCOE shouldn’t be discounted.
This is a really interesting and detailed comment. Like many interested in UK energy policy the details of how offshore wind remains economic at these low CfD rates is of some interest to me, so this insight is much appreciated.
My assumption has always been that the CfD price bid would as a minimum essentially be the price required to break even over the timespan of the CfD, in which case the Hughes methodology is very reasonable. Of course the fact that companies were committing bids at levels below what this would appear to be indicates that more factors were in play. I think the real interest is that we still don’t have a full grasp of exactly what the model is that these companies are using for these bids – though most would agree that securing the agreement for the seabed resource is probably key – which I think your comment fits with quite nicely.
Thanks for sharing the thoughts on the above. Very thoroughly described. Talk soon.
Could someone please explain how the CFD system works and why you consider it a subsidy?
I have come late to this post but let me thank you for such a concise and evidence based piece. It is refreshing that a at least a few people are looking at the facts rather than the prevailing narrative.
15 years?
“The crisis now unfolding, however, is entirely different to the 1970s in one crucial respect… The 1970s crisis was largely artificial. When all is said and done, the oil shock was nothing more than the emerging OPEC cartel asserting its newfound leverage following the peak of continental US oil production. There was no shortage of oil any more than the three-day-week had been caused by coal shortages. What they did, perhaps, give us a glimpse of was what might happen in the event that our economies depleted our fossil fuel reserves before we had found a more versatile and energy-dense alternative. . . . That system has been on the life-support of quantitative easing and near zero interest rates ever since. Indeed, so perilous a state has the system been in since 2008, it was essential that the people who claim to be our leaders avoid doing anything so foolish as to lockdown the economy or launch an undeclared economic war on one of the world’s biggest commodity exporters . . .
And this is why the crisis we are beginning to experience will make the 1970s look like a golden age of peace and tranquility. . . . The sad reality though, is that our leaders – at least within the western empire – have bought into a vision of the future which cannot work without some new and yet-to-be-discovered high-density energy source (which rules out all of the so-called green technologies whose main purpose is to concentrate relatively weak and diffuse energy sources). . . . Even as we struggle to reimagine the 1970s in an attempt to understand the current situation, the only people on Earth today who can even begin to imagine the economic and social horrors that await western populations are the survivors of the 1980s famine in Ethiopia, the hyperinflation in 1990s Zimbabwe, or, ironically, the Russians who survived the collapse of the Soviet Union.”
https://consciousnessofsheep.co.uk/2022/07/01/bigger-than-you-can-imagine/