Good afternoon everyone. I’d like to say I’m delighted to speak today about the CCGT retirement risks we face, but that would be a lie, because while it’s always nice to be with Institution of Power Engineers, it’s far from a delightful topic. However, it’s one that’s increasingly keeping me awake at night, because my analysis to date suggests we face real risks of rationing later this decade and into the early 2030s.
The shape of today’s power grid
In the past 25 years we’ve been racing to build more renewables. We now have 32 GW of wind and almost 20 GW of solar. This is backed up by 32 GW of gas generation, and another 12 GW of nuclear and biomass, just under 5 GW of hydro and pumped storage, and just under 7 GW of batteries.
Current interconnector capacity is 8.8 GW, but imports can’t be relied on if continental systems face the same weather pattern, causing corresponding stress events….with the exception of France and Norway our connected markets both share similar weather to us and are following a similar wind-led energy strategy.
France relies on an aging nuclear fleet and has a more temperature sensitive grid than us – during cold spells, we often export to France rather than import from it. And Norway is going off the idea of exporting electricity altogether since it has seen increases in power prices and power price volatility. Some in the Norwegian parliament want to cancel the interconnectors it has with Britain and Germany.
So we have roughly 64 GW of dependable firm capacity against 48 GW of peak winter demand.
Of course, no form of generation is 100% available so even if a technology is firm and dispatchable, it will still have maintenance outages and the occasional unplanned trip. This is accounted for through de-rating factors, and after applying these adjustments the current amount of available firm capacity is 50.5 GW, which gives a spare margin of just 2.5 GW based on firm power.
In reality there is generally some contribution from wind, but this can be very low – on several occasions this year, the actual output of the installed 32 GW was below 1 GW and at times as low as 200 MW (which, amusingly is Grok’s estimate of the amount we could generate if everyone in the UK blew very hard into all the wind turbines!)
Despite higher amounts of wind on the system, in 2025 wind output is down, not just in Britain, but across Europe. Solar of course contributes nothing to the winter peaks which are always at night. After the sun sets. A depressing number of people still need this explaining to them!
NESO, Ofgem, DESNZ and just about anyone with an opinion on this says we need to hang on to all of that 32 GW of gas to keep the lights on, on those cold still winter days when demand is higher and renewable output low to non-existent.
So it’s pretty unfortunate that a third of the fleet was built in the 1990s and is getting a bit long in the tooth. My analysis shows that it’s not in fact 10 GW of gas capacity that’s nearing retirement, but 12 GW.
We may gain a couple of GW of smaller units, particularly open cycle turbines, and 3.2 GW of new nuclear at Hinkley Point is expected to open in the early 2030s, but by then almost 5 GW of AGRs will have closed. The net retirement risk is therefore about 12 GW of firm, dispatchable capacity in the late 2020s and early 2030s.
Let me repeat that – firm power equivalent to over a quarter of current winter peak demand could be off the grid in the next few years. And there is no concrete plan to replace it.
Not only are we sleep walking into a capacity crisis, we’re trying to make it worse. The Government wants to decarbonise everything, and as it’s now widely accepted that hydrogen will play a minimal role, and many, including the Climate Change Committee are sceptical about the role carbon capture will play.
This means electrification is seen as the primary route to decarbonising heating, transport and whatever industry we have left. Indeed de-industrialisation, in power grid terms, is something of a blessing in disguise, taking some pressure off tight margins.
The Government also wants to AI data centres to be built in Britain, having designated them as critical national infrastructure – that could add another 6 GW of demand by 2030 according to recent Government analysis.
So in this presentation, I will go through the scale of the CCGT-retirement challenge; why the winter risk and demand control issues escalate; how this plays out in different demand-scenarios (status quo, electrification only, AI only, electrification + AI) to 2030; and finally to offer commentary on why technological solutions such as hydrogen or CCS are unlikely to scale in time, and why grid and equipment lead-times are a serious obstacle.
Condition of the CCGT fleet
Let’s examine the numbers. Britain’s gas-fired CCGT fleet includes many units commissioned in the 1990s, now approaching 30 years of operation, and reaching the end of their design life. This means increasing maintenance costs, decreasing reliability margins while facing market, regulatory and environmental pressures. In my analysis, I have identified about 12 GW of net at-risk capacity by 2030 if we factor in new small OCGTs and nuclear.
A further 6.3 GW is at risk from 2030 – 2035.
This is not just about quantity but quality. As those units age we can expect to see increased forced-outage rates, higher maintenance downtime, and perhaps de-rating due to wear, less flexibility to ramp down/up, and less ability to provide ancillary services.
So the retirement risk is not simply in lost MWs, but in the reduction of system resilience.
Anyone who has read my recent work on voltage control should find that concerning. Scotland is facing particular challenges as once Torness closes there will be only one synchronous generator – Peterhead – left to stabilise voltage in the country.
The Spanish grid operator recently requested emergency powers to stabilise voltage in the south of the country over similar worries – a very uneven distribution of conventional generation has left the grid in the south of the country so weak it is concerned about further blackouts.
Peterhead commissioned in 2000 and does not appear to have had any meaningful engineering upgrades since. In the past year it has had an unusually high number of unplanned outages, according to REMIT transparency data.
It logged 30 distinct unplanned incidents in the year to 12 November 2025, of which ~4 appear to be full trips and ~26 were partial derates. The incidents cluster in November-24, May-25, July-25 and October-25. Using last-published timestamps as a conservative proxy for duration, the cumulative unplanned downtime could be as much as 2,800 hours.
More worrying is that Langage, which was built a full decade later, has seen even higher levels of unavailability. In the past 12 months there were 58 distinct unplanned incidents, of which around 17 appear to have been full trips and 41 partial derates.
Although individual events were generally short – averaging about 12 hours – the sheer frequency meant that Langage experienced roughly 700 hours of unplanned downtime in total.
Industry sources suggest turbine-vibration issues which is consistent with the REMIT data. This underlines a wider point: even the more modern plant is being stressed by cycling and grid conditions, so simply relying on newer CCGTs to carry winter security is optimistic.
Winter risk – why is this retirement problem particularly acute in the winter?
In winter, demand peaks due to shorter days, more lighting needs, highly variable wind speeds impacting wind generation, little to no solar, and higher heating loads. As demand rises while dispatchable capacity falls, the margin shrinks. Under a cold spell, even modest variation in demand or supply can trigger stress.
Winter stresses the provision of generation as well as increasing demand, reducing both capacity and availability. These risks are amplified when much of the gas fleet consists of aging plant.
- For example there’s a risk of brittle fatigue from thermal cycling. Modern F-class turbines were designed for relatively steady baseload or 1-2 daily start-stop cycles. Today’s two-shifting with its multiple starts per week means thermal stress on turbine blades, rotors, and heat recovery steam generator tubes. In cold weather the metal temperature delta is larger at start-up, producing higher thermal gradients and more risk of cracking or deformation
- Auxiliaries including instrument air, fuel-gas heaters, cooling-water lines, condensate drains, are all points of failure in freezing conditions
- Condenser cooling water and closed-cycle cooling systems can suffer ice formation at low ambient temperatures, especially for air-cooled condensers
- As temperatures drop, lubricating oil becomes more viscous, making it difficult for it to circulate quickly to all critical components which creates accelerated wear on vital parts like bearings and gears, and increased load and strain on oil pumps and starter motors increasing the risk of trips on start-up
- Automated start-up sequence controls can be less reliable during cold weather operations. Minor faults or unexpected data from frozen instrumentation can upset the complex control logic, causing protection systems to engage
- Where cold, dry weather creates low humidity, static charges can build up on non-conductive materials which can discharge to sensitive electronic components, causing operational disruptions or permanent damage
Then there’s fuel supply risk: CCGTs require a specific, consistent gas inlet pressure to the combustion chamber for efficient and stable operation. Lower inlet pressure directly limits the mass flow rate of gas that can be supplied to the gas turbine’s combustion chamber leading to a notable decrease in efficiency. In extreme cases of low gas pressure, CCGTs may have to significantly reduce generation or even shut down to protect equipment.
During cold spells, gas system pressure is lower because of heating demand – more gas is taken off the system than is added. The 2018 “Beast from the East” weather event saw significant impacts on the GB gas grid’s inlet pressure, causing reductions in power output and efficiency in the CCGT fleet.
Even as renewable capacity grows, the experience of wind-lulls in the UK (multi-day periods of very low wind) is well documented. Studies have found that such events are frequent and can last days.
If 12 GW of firm capacity is retired, the head-room – that is, the buffer between available capacity and demand – disappears and a shortfall of up to 10 GW emerges on low wind days. This would inevitably lead to demand control, but raises the risks that unexpected outages of the remaining plant or an interconnector import shortfall would require sudden increases in demand reductions, and in such a scenario, under-frequency or voltage stability risks increase.
Older CCGTs may see more forced outages and maintenance trips. If several ageing units trip simultaneously in more extreme cold winter conditions, the absence of spare capacity means that increased demand control (which is a polite way of saying pre-planned load-shedding) becomes more likely. In short: the larger the “hole” in dispatchable capacity, the greater the probability of larger, trip-induced supply shortfalls leading to further demand intervention and possible blackouts.
Beyond capacity, CCGTs provide inertia, frequency response, voltage-support and other services. As they retire, new replacements (batteries, renewables) provide fewer of those services or do so in different ways. Inverters must use current for all the services they provide – if they use current to support voltage they cannot use it to power loads. Large numbers of inverters, programmed the same way in line with the Grid Code, could respond to the same voltage event by reducing active power creating a drop in frequency and a risk of blackouts.
The CCGT retirement risk is not just a capacity shortfall but also creates risks of system instability, frequency excursions, voltage collapse and so on, all of which carry the threat of blackouts. We’re entering a period in the coming winters where demand stress, supply variability, and capacity retirements converge. The system will be much more exposed than many people realise.
Capacity shortfalls increase under different demand scenarios
We can now consider how this exposure plays out under three demand scenarios to 2030, and a fourth combining two: (i) status quo demand growth; (ii) electrification only; (iii) AI-driven demand only; (iv) electrification + AI.
Under a status-quo demand scenario, we don’t really see any demand growth. In recent years, despite increasing population, de-industrialisation has pushed electricity consumption lower:
- Demand peaks may remain broadly at current levels at around 50 GW (last year it was 47.4 GW, but Amira is currently forecasting 47.5 GW next week)
- Retiring 12 GW of firm capacity means that if that loss is not replaced by equivalent firm capacity, margins disappear into a shortfall on low wind days
– while the system may still function, under regional demand control, any large forced outage or interconnector import shortfall (eg due to cold and still weather on the Continental) could trigger increased demand-control actions or elevated blackout risk - Demand-control would become routine in low wind conditions
- The system operator would need to procure more reserve/ancillary services to bridge the gap, for example paid for demand-side response, increasing cost for consumers
Until a few years ago “triad avoidance” used to deliver around 2 GW of peak shaving, however Ofgem deemed triads were no longer an appropriate way to allocate network costs as it was unfair to households. This 2 GW of industrial and commercial demand response was lost. At the same time, the Demand Flexibility Service was introduced, and it was hoped I&C consumers would migrate to it. They didn’t so we went from 2 GW I&C demand response under triad avoidance to 200 MW domestic response under DFS. Getting back to GWs of peak shaving would need much higher prices which would feed through to bills.
Now imagine a scenario where heat-pump and electric car deployment accelerates and, industrial electrification progresses, causing demand to increase – a 7-10 GW increase would be a credible scenario. This would mean:
- Peak winter demand would rise to perhaps around 60 GW by 2030, widening the cold still weather supply gap
- The probability of multiple risk events (eg cold snap, wind lull, interconnector import drop, CCGT trip) increases materially
- Demand-control would be inevitable on low wind days and would likely affect more consumers
Next we consider a third scenario where electrification stalls but we see increased demand from AI data centres.
Here we assume that data‐centre growth, AI computing loads, and high‐performance computing create an additional demand load for electricity of some 6 GW. Here the impact is essentially the same as in the electrification scenario but the low wind shortfall is 1-4 GW smaller
Finally, if we consider a scenario where both electrification and deployment of AI data centres boost demand, clearly we end up in a far more stressed condition.
- Peak demand could plausibly rise by around 15 GW to around 65 GW
- Higher numbers of people would be impacted by still weather demand control with even higher system costs as NESO has to buy even more services to try to support the grid
However, my view is we’re not going to see material increases in electrification to 2030 and whatever we do see will be offset by de-industrialisation. While I do think there will be AI data centres, I think they’re going to rely on behind the meter generation, so impact on the grid and the capacity margins will be minimal. So the status quo demand scenario is the most likely in my opinion.
Why replacing retiring plant is difficult
Of course, the assumption would be that retirements would be offset by the construction of new generation. Historically it has been possible to build a CCGT from scratch in 18 months after breaking ground. But this is impossible in today’s market. Not only have permitting timescales widened, grid connections can take a decade, and there are 7-8 year lead times for delivery of new GTs.
Even a new rotor on an existing plant can take 5 years to deliver, and parts for more modest upgrades to hot gas path equipment can take 12-18 months to get to site.
For a new CCGT to come online to offset retirements to 2030, it would need to be not just sanctioned already, but have taken FID and ordered all the equipment. There are no projects that meet this description.
Even if generation can be built, connection to the transmission system can require reinforcement, network upgrades, possibly new substations, lines, and sometimes local connection issues. These network upgrades often face planning /consent delays and take years – it’s not uncommon for projects to be quoted connection dates in the mid-2030s. Without the transmission ready, a new CCGT cannot reliably participate in the system as firm capacity, unless it can use a pre-existing grid connection.
There is, of course, the narrative that hydrogen-fired gas turbines or CCGTs with CCS will provide the future firm capacity. But realistically by 2030 the scale of hydrogen or CCS in the UK generation system will remain very limited. Some generators have projects they claim to hope will open by 2030 but not having taken FID this is highly unlikely.
In the past year, NESO and the CCC have both adjusted their outlooks to show a minimal role for hydrogen – various hydrogen production and pipeline projects in Europe have been cancelled, and the British hydrogen village trials were terminated due to public opposition.
The CCC has said it sees minimal role for carbon capture.
New CCGT investment is subject to market risk – if investors believe policy is moving away from gas because of net-zero trajectories, they may be reluctant to commit – indeed, Langage and South Humber have 15 year refurbishment contracts under the capacity market for 2028-29 onwards but appear not to have taken the final investment decision – delivery seems unlikely.
The retirement of old plants may accelerate, but the replacements may lag which will make everything a whole lot worse.
Likely reliance on demand interruptions and demand control
Given the emerging capacity gap and the elevated risk of rationing and blackouts, the implications for system operators, policymakers and consumers are significant. Demand interruption and control measures will become central to balancing the grid. These might include:
- Enhanced interruptible demand contracts for large industrial and commercial users
- Dynamic load-shedding schemes (triage of loads in extreme events)
- Greater use of demand-response aggregators offering capacity at short notice
- Price signals and variable tariffs that encourage reduction of peak demand
- Selective load curtailment in low wind, cold weather conditions
In effect the system operator may have to rely more on demand-side action to maintain balance rather than purely supply-side flexibility. That’s really bad news – utilities should serve consumers, not the other way round, and while consumers may be compensated for peak shaving, the costs of this will be added to bills. Economic output would also be adversely affected if industry is forced to reduce activity, potentially cutting total output.
Recommendations for policy-makers
For winter operation, planning needs to be more conservative. Reserve margins need to reflect the retirement of CCGTs and AGRs and potential extra demand. They also need to match cold weather demand with cold-weather generation and de-rate all technologies to cold weather rather than average performance. Growing renewables is all very well – although my views on their usefulness are pretty well known – but the system needs firm, dispatchable, controllable capacity (gas, hydro, nuclear) that can operate at full output when needed.
Replacing dispatchable generation with intermittent generation won’t cut it.
Policymakers will need to decide how much risk they are willing to accept and how much cost they are willing to incur to maintain reliability. Just this morning I was sent a study which showed that in addition to the 11 people who died as a result of direct factors in the Iberian blackout, there were around 160 excess deaths over the 2 days affected, so blackout risks are not to be trifled with.
Given the long lead-times for new firm capacity, policymakers must give clear, consistent signals to investors that firm-capacity is still valued. If the market believes gas is “out” and no firm-capacity revenues will flow, investment will fall short. The potential retirement of 12 GW of CCGT by 2030 requires a replacement strategy that must be started now, not in at some future date.
Given the risks we face, here are some practical recommendations:
- Accelerate and simplify planning for new firm dispatchable capacity with the explicit goal of replacing the retiring 12 GW by 2030
- Prioritise shorter lead-time options such as OCGTs and even coal if necessary to keep the lights on
- Grid reinforcement and network connection programmes must be accelerated – the existing reform process is moving too slowly
- Winter-stress scenario planning must assume lower head-room, higher demand and elevated forced-outage risk
- Realistic demand-response programmes with much larger capacity must be developed, including interruptible contracts and dynamic tariffs to ensure that large-scale demand-response is ready to deploy
- Avoid over-reliance on unproven technologies (hydrogen, CCS and long-duration storage)
- Send long-term investment signals that firm capacity is still needed and will be remunerated
- Explain to businesses and households that increased demands (heat pumps, EVs, AI data centres) require corresponding investment in reliability and may impose cost or behaviour change
- While interconnectors and storage will help, they cannot be the only answer – storage can’t currently provide multi-day capacity and interconnectors depend on continental supply which may also be stressed in cold snaps
- Condition-monitoring and maintenance of the ageing CCGT fleet must be maximised: any avoidable forced outage in the remaining units worsens the margin. Asset-owners may need incentives to invest in life-extension and this needs to be delivered as soon as possible
In conclusion, the retirement of approximately 12 GW of 1990s-built CCGTs in Great Britain by 2030 represents a major transition risk for our electricity system. Combined with variable renewables output, long lead-times for new firm assets, and the potential growth of new loads through electrification and AI, the margin for error is thin.
If we do nothing, we may find ourselves in a situation where the lights remain on, but only through more frequent demand-intervention, higher consumer cost, and increased system risk. If we act now, accelerate firm-capacity investment, prepare demand-side programmes, and maintain the flexibility and robustness of the system, we might be able to minimise the impact, but there is little recognition from NESO, DESNZ or Ofgem of the scale of the challenge.
That complacency increases the risks that the first time we actually see a shortage results in a blackout, because the control room may be caught unprepared. NESO has a poor track record of forecasting the size of wind output and the size and timing of peak demand. Getting this wrong on a marginal day, could put us at increased risk of blackouts.
We saw this on 8 January this year: NESO over-estimated wind output, under-estimated demand and incorrectly predicted the timing of the peak. It made a risky decision to replace Rye House (CCGT) with Dinorwig (pumped hydro) through the peak because the former was seeking very high prices in the Balancing Mechanism. To save money, Rye House was ramped down to zero just before the demand peak.
This was against a backdrop of various system margin warnings and a request made by NESO to Energinet to return a bipole of Viking back from maintenance early. Plant is particularly unreliable when returning from maintenance so at a time of system risk, NESO took the decision to run its only GW scale fast response asset instead of holding it in reserve, just so it could swap out an expensive CCGT for an hour or so.
This type of complacency significantly elevates blackout risks. Of course NESO must take account of costs to consumers, but it needs to do so sensibly. What it did on 8 January was not sensible.
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The picture is bleak, and time is running out to materially reduce the risks. Without action the costs both in terms of economic output and consumer hardship will be significant.
I’m in discussions about a commission to write an in-depth report into these risks. If anyone has any insights they would like to share, perhaps about assets you’re familiar with, I’d welcome all input.
Thank you.
Q&A
Thank you Kathryn for publishing your speech.
Why is gas powered electricity generation (CCGT) on such a long lead time compared with even a decade ago?
Is this due to manufacturing demand dominated by other regions / countries?
If so, what can be done to match planned replacement schedule to supply of CCGT plant?
It’s a very worrying situation. How long would it take to build a new coal-burning power stattion? Would fleets of diesel generators help, or are they too expensive?
Do you know of ANYONE in government that can understand these issues?
Mr Lammy. Oh yes.
Thanks Kathryn – one of your best articles yet. If this is a transcript of a talk, it would be good if the video were available.
I think there is one huge elephant in the room here (and it shares its name with a certain Bond Villain..) Drax.
Pretty much everyone agrees that a) it should be shut down, and b) we can’t possibly shut it down.
So, it can hold the UK to ransom over its ludicrous subsidies.
It’s far more polluting than even the coal that it replaced, its BECCS claims are utterly bunk, it is destroying ancient forests (ironically one of the world’s only carbon sinks that actually work), and it is exacerbating a shipping / port capacity crisis with its 20,000 tonnes of dried wood pellets per day imported from the US and Canada (https://www.drax.com/sustainable-bioenergy/5-incredible-numbers-worlds-largest-biomass-port/). Yet due to the reasons in your excellent article, we couldn’t possibly turn it off.
Perhaps it could be persuaded to go back to burning “good old Welsh Anthracite”?
Add to this already fragile situation a possible Coronal Mass Ejection event, plus the disaster that is Geoengineering and even looming global war and I would say the UK grid is precarious to put it mildly.
Practical recommendation 11:
Buy a decent size battery with home backup (e.g. Tesla Powerwall) and keep it topped up !
You can only use electron once either use it in house or charge battery but the grid has to have surplus power to charge you. Perfectly sited southern facing house with solar in Southern California desert with Tesla powerpack, pulls power from grid all but 3 days per month and battery is drained to zero over 50% of days Dec & Jan. In UK, most of which is 500 miles north of Montreal Canada, you will be without power at least part of the day every day and likely several days Nov. thru Mar. if the retirements go forward regardless of such batteries..
I didn’t say anything about solar, just that it was very practical to have a “decent size battery with home backup” (the last 3 words are key) to avoid the consequences of blackouts.
However, mine has saved me twice in the last year. I top it up every night at the cheap rate, unless we are in the summer months and the forecasts are good so we can rely on the sun. When there is little risk of blackouts with small consequences anyway (i.e. not now), I sell about 10kWh back to the grid during the peak period. I make a profit that way even if I charged from the grid and taking losses into account.
Yes, I have had to invest some capital to do this but I will repay it well within 10 years and my peace of mind is worth the interest I am losing.
My system wouldn’t save me in a multi-day blackout, but if I battened down the hatches, no appliances, cook on the log burner etc, we could probably last for a couple of days.
We have 14 panels on a 45 degree, SW facing, unshaded roof in Bedford. We are a retired couple with a modest insulated detached house, gas CH with a combi-boiler and only normal appliances (no tumble-dryer) on Octopus Flux. With the strategy outlined above our Direct Debit is £30/month and that includes the gas too which is on most days – we only light the log-burner on the coldest days.
For you and I this works but, your point as a general “recommendation 11” is not practical for many/most in UK which is my point. Your gas CH is a big plus as is no EV(?). Throw either one of those into the mix, as per government’s recommendations and this is not a solution, for you or general UK public for better part of 4 months.
Thankyou for this and all your work which is obviously hard.
chris Bennett cllr
Kathryn, while you are right that UK needs to replace retiring CCGT and nuclear plants, the connection is mostly a red herring.
If a plant on a generating site is being retired, there is already a connection to the site which can be used for the new generating plant. And most sites have room to construct the new plant in parallel with the last of the generation from the old plant. Then there can be a cut over period where both are connected in parallel, but not operational at the same time, before the old plant is decommissioned.
The nuclear plants being decommissioned, but not planned for replacement also have existing grid connections such as
– Dungeness 1,040 MW
– Hunterston 830 MW
– Hartlepool 1,190 MW
– Heysham 2,400 MW
– Torness 1,364 MW
I make that nearly 7 GW of old nuclear connections available for the 12 GW of new gas plants you are suggesting. Plus the replacement of old gas plants on the same site. The occasional site connection may require reconductoring.
So it looks very much like the need for new grid connections is minimal, by re-using the old connections. Thus the lead times for installing new CCGT plants are the critical thing, not the grid connections.
Kathryn, while you are right that UK needs to replace retiring CCGT and nuclear plants, the connection is mostly a red herring.
If a plant on a generating site is being retired, there is already a connection to the site which can be used for the new generating plant. And most sites have room to construct the new plant in parallel with the last of the generation from the old plant. Then there can be a cut over period where both are connected in parallel, but not operational at the same time, before the old plant is decommissioned.
The nuclear plants being decommissioned, but not planned for replacement also have existing grid connections such as
– Dungeness 1,040 MW
– Hunterston 830 MW
– Hartlepool 1,190 MW
– Heysham 2,400 MW
– Torness 1,364 MW
I make that nearly 7 GW of old nuclear connections available for the 12 GW of new gas plants you are suggesting. Plus the replacement of old gas plants on the same site. The occasional site connection may require reconductoring to increase the connection capacity.
So it looks very much like the need for new grid connections is minimal, by re-using the old connections. Thus the lead times for installing new CCGT plants are the critical thing, not the grid connections.
Excellent point, US is doing same with retiring coal gen sites but none of those locations have natural gas connections or pipelines. UK refuses to develop its own natural gas reserves both onshore or offshore, although both are plentiful. Gas turbine delivery for GE, Siemens or even Solar Turbines are beyond 2030 at this point. Only hope is giving those CCGT’s extra-care and getting their retirement dates out to 2035. Then you might have a chance if you UK was willing to develop gas reserves and pipelines, which would require a change in current government. It might well also take some modification of local population around gas wells and pipelines.
Kathryn, while you are right that UK needs to replace retiring CCGT and nuclear plants, the connection is mostly a red herring.
If a plant on a generating site is being retired, there is already a connection to the site which can be used for the new generating plant. And most sites have room to construct the new plant in parallel with the last of the generation from the old plant. Then there can be a cut over period where both are connected in parallel, but not operational at the same time, before the old plant is decommissioned.
The nuclear plants being decommissioned, but not planned for replacement also have existing grid connections such as
– Dungeness 1,040 MW
– Hunterston 830 MW
– Hartlepool 1,190 MW
– Heysham 2,400 MW
– Torness 1,364 MW
I make that nearly 7 GW of old nuclear connections available for the 12 GW of new gas plants you are suggesting. Plus the replacement of old gas plants on the same site. The occasional site connection may require reconductoring to increase the connection capacity.
So it looks very much like the need for new grid connections is minimal, by re-using the old connections. Thus the lead times for installing new CCGT plants are the critical thing, not the grid connections. They are already bad enough at ~5 years.
Sorry, Pater, I didn’t quite catch that.
This is not a trivial comment and observation but a hard nosed and objective perspective. Please take a look at this link to an eBay
offer: https://www.ebay.co.uk/itm/266462309941. For £166,620 a 1500kVA/1200kW brand new diesel generator can be purchased. Which, if a couple of thousand were bought, presuming bulk sales were a realistic option, would probably round down the sales price to less than £150,000/MW. Therefore, two thousand times that would give a 2GW capacity for ~ £300m. Quite possibly, for about £1Bn, as
much as 8GW could become available. As an emergency, and commercially viable option, power supply, it is difficult to see any immediate and realistic alternative.
Thank you Kathryn. You are the canary in the coalmine (to quote a slightly ironic old saying). It scares me why no one else seems to understand such a key issue or are so blinded by the obsessive ‘net zero’ agenda, that they have their collective heads in the sand. Please keep promoting this critical topic.
The British Govt. is in the process of procuring multiple nuclear powered submarines. Apart from the obvious questions as to the necessity of these vessels, there are apparently RN submarines in the fleet now that are tied up because of lack of crews.
Surely a far better investment would be the construction of SMRs that would ensure the security of Britain’s electricity supply?
A great synopsis Kathryn. Just demonstrates to me politicians have no perception of systems thinking as this challenge has been emerging for at least a couple decades. With political party of both colours being the culprits.
Further to Peter Davies comment wrt connections mostly a red herring!!
I wonder how he expects windfarm onshoring interconnects to actually be connected to the NG hubs.
Currently, where I live, North West England, there are 4 wind farms planning onshore inter-connects. Two wind farms in particular, Morgan & Morecambe, are planning to onshore at Starr Gate, Blackpool to connect to NG’s hub at Penwortham’s, defunct coal power station, 18.75 miles (30 Km) away. This will mean constructing a cable corridor 100 metres wide, with 2 huge sub stations along the lines over this distance through prime farming land. This construction, if sanctioned to go ahead, is scheduled for up to 11 years and adversely impact the area’s; travel, farming, business, tourism & biodiversity.
As I suspect, the above will be a typical solution for wind farm onshore interconnect, it’s adverse impact on affected areas will be a major risk to construction cost and schedule modelling and may even prevent such projects being sanctioned. Especially, as there would appear to be a growing backlog of such projects being approved.
and once again the sad part is all the money spent on transmission lines and substation that will rarely be fully loaded and sometimes almost unused. So what actual value is returned to stakeholders/taxpayers vs same infrastructure for CCGT, coal or nuclear gen plant?
My interpretation of Peter Davies!s comment(s) was that the grid connection for retired plants could be repurposed to connect in new Open Gas turbines which is the only type of kit that can be delivered and operational by the earl 2030s
Great insights! Could SOX fuel cells such as from Bloom Energy bridge the gap in the turbine lead time?
A very useful paper – and not before time. Let’s hope the
Government takes notice.
You don’t mention ReEnergise. They now have a small pilot
plant soon to start up and which actually makes use of
intermittency. If this proves successful, it should be given
massive backing,
The problem with RheEnergise is their “Proprietary High-Density Fluid R-19” which they won’t say even which elements are involved (Iron? Barium? surely not Lead), lest anyone speculate on details like safety, materials availability/scalability, cost etc. It’s going to be hard to beat the abundance, cost, safety, non-abrasiveness and density of water, for a pumped hydro LDES. They claim that they have it beat on density by 2.5x, but what about all the other factors?
Given that Dinorwig uses about 400 tonnes of water per *second* with a head of 500m to produce its ~2GW output: Even with a denser material they’d still need a similar mass-flow rate if they want the same power with less elevation. So that’s an awful lot of “proprietary magic slurry” they’d need to manufacture. 1.4 million tonnes of High-Density Fluid, per hour of operation, for a 2GW plant.
A very useful paper – and not before time. Let’s hope the
Government takes notice.
The problem with RheEnergise is their “Proprietary High-Density Fluid R-19” which they won’t say even which elements are involved (Iron? Barium? surely not Lead), lest anyone speculate on details like safety, materials availability/scalability, cost etc. It’s going to be hard to beat the abundance, cost, safety, low-viscosity, non-abrasiveness and density of water, for a pumped hydro LDES. They claim that they have it beat on density by 2.5x, but what about all the other factors?
Given that Dinorwig uses about 400 tonnes of water per *second* with a head of 500m to produce its ~2GW output: Even with a denser material they’d still need a similar mass-flow rate if they want the same power with less elevation. So that’s an awful lot of “proprietary magic slurry” they’d need to manufacture. 1.4 million tonnes of High-Density Fluid, per hour of operation, for a 2GW plant.
My guess would be that it’s an iron oxide slurry. Like the sludge that comes out of my radiators. But that is a viscous non-newtonian fluid (so would suffer much worse efficiency problems than pure water pumped hydro) and forms a hard crust on inside pipes over time. Maybe they have a special lubricant additive. But then even the mildest of chemical lubricants would raise grave safety concerns given the quantities involved.
If it becomes contaminated or degraded for some reason, what do they do with a million tonnes of waste slurry?
The problem with RheEnergise is their “Proprietary High-Density Fluid R-19” which they won’t say even which elements are involved (Iron? Barium? surely not Lead), lest anyone speculate on details like safety, materials availability/scalability, cost etc. It’s going to be hard to beat the abundance, cost, safety, low-viscosity, non-abrasiveness and density of water, for a pumped hydro LDES. They claim that they have it beat on density by 2.5x, but what about all the other factors?
Given that Dinorwig uses about 400 tonnes of water per *second* with a head of 500m to produce its ~2GW output: Even with a denser material they’d still need a similar mass-flow rate if they want the same power with less elevation. So that’s an awful lot of “proprietary magic slurry” they’d need to manufacture. 1.4 million tonnes of High-Density Fluid, per hour of operation, for a 2GW plant.
My guess would be that it’s an iron oxide slurry. Like the sludge that comes out of my radiators. But that is a viscous non-newtonian fluid (so would suffer much worse efficiency problems than pure water pumped hydro) and forms a hard crust on inside pipes over time. Maybe they have a special lubricant additive. But then even the mildest of chemical lubricants would raise grave safety concerns given the quantities involved.
If it becomes contaminated or degraded for some reason, what do they do with a million tonnes of waste slurry?
(apologies if like Pete Davies, my post ends up appearing in triplicate. I have been getting a lot of HTTP 504 errors on posting)
Very long article. I got to half of it. Saving other half for later:/ It would be better to make it more concise.
I second your request and please apply it to all her articles. She could really benefit from taking a class in writing.
How incredibly rude – and plain wrong.
First of all it’s a transcript of a speech.
Second, it’s written in very clear language, free of sesquipidelian conceits (see what I did there?) and is an excellent exposition of the situation and suggested solutions. This is an extremely serious problem and requires serious writing to explain it and confront it.
There was an earlier article that I struggled with, but that’s because of MY limitations, despite having started a Physics degree 60 years ago. Similarly, if there’s a problem I would suggest it is with the receiver, not the transmitter.
Keep up the good work Kathryn.
How incredibly rude – and plain wrong.
First of all, it’s a transcript of a speech.
Second, it’s written in very clear language, free of sesquipedalian conceits (see what I did there?) and is an excellent exposition of the situation and suggested solutions. This is an extremely serious problem and requires serious writing to explain it and confront it.
There was an earlier article that I struggled with, but that’s because of MY limitations, despite having started a Physics degree 60 years ago. Similarly, if there’s a problem I would suggest it is with the receiver, not the transmitter.
Keep up the good work Kathryn.
We have been seeing instability in the energy supply networks for some time now, but this is a stark warning of the imminent future we face if action is not taken now. There are considerable threats to life from blackouts as noted in your speech Kathryn. We are already seeing considerable calls for investment in Power Resilience from industry which also goes onto customers’ bills along with green levies. There are environmental consequences as well to the transition to renewables as powered assets suffer unplanned outages such as brown outs resulting in polluting material entering the environment with additional costs and fines being imposed.
Kathryn, you say that today we have 7 GW of batteries. But what is their total capacity/energy storage? Earlier in the year I did question NESO about their CP 2030 storage as Table 2 (P47) in their CP 2030 report only quotes 4.7 GW (power) and not GWhrs (energy). They finally confirmed that their CP 2030 plan was for a total of a mere 147.39 GWhrs. This was for the FF&R option.
And may I please have your opinion on this article which says that the power required by AI datacentres “fluctuates thousands of times a second” and can destabilise the grid and requires flow batteries to stabilise rather than Li-ion batteries?
https://www.zerohedge.com/energy/data-center-volatility-batteries-and-electric-grids-new-reality
BTW, I presume such fluctuations, if true, had nothing to do with the oscillations which are thought to be the origin of the Iberian blackout?
Kathryn, you say that today we have 7 GW of batteries. But what is their total capacity/energy storage? Earlier in the year I did question NESO about their CP 2030 storage as Table 2 (P47) in their CP 2030 report only quotes 4.7 GW (power) and not GWhrs (energy). They finally confirmed that their CP 2030 plan was for a total of a mere 147.39 GWhrs. This was for the FF&R option.
And may I please have your opinion on this article which says that the power required by AI datacentres “fluctuates thousands of times a second” and can destabilise the grid and requires flow batteries to stabilise rather than Li-ion batteries?
https://www.zerohedge.com/energy/data-center-volatility-batteries-and-electric-grids-new-reality
BTW, I presume such fluctuations, if true, had nothing to do with the oscillations which are thought to be the origin of the Iberian blackout?
Restoration of Supplies. The UK has never had a grid collapse. Procedures are in place to undertake testing on the very few locations that are capable of performing a black start. Just how far this testing is taken must vary across generation suppliers and would be limited in scale to avoid consumer disruption.
Circumstance of the benign Iberian fault, though bad enough, occurred around midday during midsummer. A blackout for a GB grid failure could well happen at peak times around the year end with urban lockdown of transport, weather constraints, darkness and communication problems. Without notice, call out of personnel to remote locations and control rooms to initiate black start procedures would be hazardous, uncertain and prolonged. The integrity of control room facilities would be absolute. Landline telephones now require a power supply. Mobile use can expect to be congested. When all control room indications fail, the telephone remains the last resort, or should be.
A priority for restoration would be to synchronise all dispatchable plant with limited consumer demand and securely extend to other dispatchable sources that require start up supplies. Avoidance of trips would be critical at this stage needing full staffing. Grid restoration would follow next. Connection of IBR generation should be withheld until EU interconnection sources can be connected. Heavy consumer demand can be expected with heating, once essential services have been restored.
A consumer demand ceiling would soon appear that in all probability could not be met, so some supply reserve is needed and recourse to rolling power cuts on smart meters inevitable. System stress is certain so any distraction from concern with inertia constraints should not be tolerated by ensuring ample reserve. Slow and steady should be a maxim as any relapse only creates delay. One of the best control engineers I have ever worked with on system faults, his first reaction was to fill the kettle!
Restoration of Supplies. The UK has never had a grid collapse. Procedures are in place to undertake testing on the very few locations that are capable of performing a black start. Just how far this testing is taken must vary across generation suppliers and would be limited in scale to avoid consumer disruption.
Circumstance of the benign Iberian fault, though bad enough, occurred around midday during midsummer. A blackout for a GB grid failure could well happen at peak times around the year end with urban lockdown of transport, weather constraints, darkness and communication problems. Without notice, call out of personnel to remote locations and control rooms to initiate black start procedures would be hazardous, uncertain and prolonged. The integrity of control room facilities would be absolute. Landline telephones now require a power supply. Mobile use can expect to be congested. When all control room indications fail, the telephone remains the last resort, o
Sorry, but I think that zerohedge article is a bit silly. I have worked in the IT/routers/switch/servers/data centre business all of my career. Many years ago a singe Google cluster (which is briefly yours to answer your google searches) was built from about 50,000 servers, it’s probably a lot more now and I would suspect an AI cluster is even bigger – likely 500,000 servers or so, all running together, each running its part of a huge program. The load of each server may go up and down a bit as it chunters through its lines of the code, but in effect completely randomly to all of the other servers in the cluster, so I would see the overall load as being pretty stable as they even each other out. What maters absolutely to any data centre is that its power is 100% stable and reliable. Even brief power outages cause havoc, with long service disruption and a complex restart process.
What I’d like to see from NESO/Elexon would be to bring batteries (and diesels) out of the “Other” fuel type in their data. And it should be bi-directional, as it is with interconnectors.
There was a mini-report on this 5 years ago, but nothing was done, despite the massive expansion in battery use since 2020.
https://www.elexon.co.uk/bsc/documents/groups/panel/2020-meetings-panel/306-september/306-02-trading-operations-bsc-operations-headline-report/
Then, it would be easy to estimate the actual capacity of the UK’s energy storage fleet. (assuming relatively few instances of one battery charging while another is discharging)
As for data centre power fluctuations, I’m not sure about “thousands of times a second” – that sort of rate would be smoothed out by the DC capacitors in rack power supplies.
For slower (but still serious) fluctuations, they are developing rack PSUs with built in batteries (or supercapacitors) e.g. the GB300 NVL72 power supply from nvidia.
More serious problems for grids arise when entire datacentres trip over to backup power due to grid voltage fluctuations, they can amplify those same fluctuations, and cause other datacentres to trip, i.e. a positive-feedback, cascade event
e.g. https://www.reuters.com/technology/big-techs-data-center-boom-poses-new-risk-us-grid-operators-2025-03-19/
I’m not sure how flow batteries could mitigate against that..
As Kathryn says, the answer for some datacentres is to not plug into the electric grid at all, and run their own local gas turbines “behind the meter”. The problem then falls to the gas grid to maintain pressure, and apparently that is already becoming difficult in winter, according to Kathryn’s talk.
After reading this and all the comments to date, I think we have a saying here in the US for when folks don’t think something all the way through before they launch on a course of action, that may be a good motto for the UK Grid Operator in 2026 or 2027. It is, “F___ around and Find Out”. Best of luck y’all cause reading your government’s pronouncements in The Times does not fill me with confidence or even give me hope and hope is a horrible operating strategy.
Through political stupidity our generation capacity has been destroyed.
Excellent article Kathryn
Many people seem to be adding comments more than once. I had great difficulty comment using a phone. Multiple comments happen on other posts so think there is something wrong with the Leave a Comment function. It often does not retain my name etc despite ticking the box.
Perhaps the commenting functionality could be reviewed/updated
Many people seem to be adding comments more than once. I had great difficulty comment using a phone. Multiple comments happen on other posts so think there is something wrong with the Leave a Comment function. It often does not retain my name etc despite ticking the box.
Perhaps the commenting functionality could be reviewed/updated
When I click the post comment button I am never sure what has happened so try clicking again
The further issue not discussed is the essential role which Gas generation plays in handling the daily variation in Grid demand, currently varying between 11GW and 17GW each day. The pattern of demand variation is unchanged over the 15 years I have studied it, although clearly the amplitude varies with the time of year. The bulk of this variation is handled by ramping Gas output up and down. Clearly, massive Battery storage could deal with this demand variation in a fossil-free world but the required capacity, reliability and load required for charging seems very problematical.
Whilst the length and frequency of “Wind Lulls” gets some exposure, if rather feebly dismissed, this second feature now covered by Gas generation, appears to be totally ignored in the ignorant pursuit of the “Fossil -Fee World”.
Occasionally, the main TV channels repeat (fascinating) black-and-white documentaries of harsh winters endured by our relatives. Would the UK fare badly if any of the current decade’s winters proved equally harsh?
This speech should be more widely publicized and, despite a negative and unnecessary comment on its length, is perfectly intelligible to anyone who spends time reading it.
As I see it, the greatest obstacle of all is a government that has no scientific training and which favours an ostrich approach to such essential matters.
We face a very serious risk of having to cope with blackouts in the coming years, and, I suspect, in increasing numbers.
I can only imagine the public reaction, but we could see rioting. We ignore it at our peril.
The problems mentioned with operation of CCGT are with the steam turbine systems. I suspect that some of them might be resolved by having integrated heaters to stop de-icing.
There are some interesting possibilities for operation.
One would be to ensure that all generators would commit to providing specific amounts of energy, say 8 hours, in advance – thus requiring some integrated (with generators) storage (and some distributed storage on the grid – to help redistribute energy around the UK). This would, I hope, mean that thermal based generators would operate without undue stresses and extra costs. This is like having cache/buffers on a networked system – common in computers and electronic systems.
Secondly consider the use of including other heat sources (energy storage or hydrogen…) and using external heaters (rather than in-line combusters) – indirectly fired combined cycle (IFCC) systems (see, for example, https://www.ansaldoenergia.com/offering/equipment/turbomachinery/heavy-duty-gas-turbine/ae942 – circa 200 MW ). Indeed such systems might also be used for CHP – with process or domestic heat as the main function). This would offer the opportunity of a closed (working) gas cycle which might mean no-oxidation occurring and the use of homogeneous composites such as SiC-SiC or C-C rather than hard to work exotic nickel super-alloys).
It is not clear to me what the lead time and manufacturing difficulties are for steam turbine systems as compared with gas-turbines or what components (eg cast blades or engine discs) are on the critical path . But it may well be that improving manufacturing processes – eg faster and large blade casting) or alternate designs (eg replacing discs with composite rings) should be researched
I live on the other side of the English Channel in north-west France and despite 57 reactors operating across 18 sites.with a total nuclear capacity of 62.9 GWe plus 2 hydro stations in NW France, we have problems of a different nature to those in the UK – delivery not lack of generation.
Living in a rural area in a tiny hamlet of about 20 houses our electricity supply is overhead 3 phase + N on poles along the road, tapped off for single phase to each property.
Stability of supply is great, very rarely does the voltage or frequency vary from 230 volts/50 Hz – except when we get hit with winter storms which topple trees which bring the lines down.
Having suffered a three and half day power cut from a bad storm a few years ago, I decided to invest in a generator and the associated switchgear to connect it’s output safely to the house system when needed.
I did briefly consider a standby battery/inverter/charger system but the cost of that was close to that of a decent silent inverter generator, and doesn’t alleviate the ever present battery storage disadvantage of when it’s discharged and the mains power is still out you are back where you started.
The “puissance” level that we contract and pay for for is there to limit excessive domestic consumption and load on the system, the more the Kva you want you pay more – no power showers in rural France!
That’s an idea for the UK .
When running on the generator which is 3kva we just have to be careful not to have every large load switched on at the same time.
The last power outage scheduled by EDF was caused by upgrade work some distance away and instead of lasting for 5 hours took 12 hours, we get a healthy reimbursement if outages exceed 5 hours which usually pays for the generator fuel.
Kathryn,
I’m very grateful for the pieces you write.
Do you feel the capacity market can sufficiently incentivise gas fired power operators to maintain and refurbish existing plant and build new plant? If not, what would you recommend?
James
Kathryn,
Do you feel the capacity market offers sufficient incentive to gas fired power operators to maintain and refurbish existing plant and to invest in new plant? If not, what changes would you recommend?
James
Interesting column today from Richard Tice… https://www.dailymail.co.uk/debate/article-15322709/RICHARD-TICE-end-Great-Green-Fraud-Drax.html
As someone who believes that the only major beneficiary of Brexit was Vladimir Putin, it’s depressing to find myself agreeing with Reform’s Richard Tice..
(up until the point where he says “[wind turbines] require hundreds of miles of unsightly pylons” – that is a flawed argument. Any electricity transmission system requires pylons whatever the type of generator – and they are not unsightly, in my opinion)
On most of the rest, he’s dead right. Biomass is incredibly inefficient. It takes energy to process and dry the wood and to ship it by road, sea and rail from the US and Canada, and when it arrives it’s still not as calorific as the lowest grade of coal. It destroys ecosystems, it produces more carcinogenic particulate pollution and more CO2 than the dirtiest of dirty brown German lignite coal per MWh of electricity it produces, and the proposed BECCS wheeze would cannibalise 27% of the plant’s electricity output, reducing its overall thermal efficiency from 36% down to 26% (or even down to 20% if the energy input for drying and shipping wood pellets is included in the figure – see https://www.chathamhouse.org/beccs-deployment/03-inefficient-beccs-power-plants-optimal-choice).
So Tice’s claim that Drax “would consume twice as much energy than it would supply to the grid” which at first seems sensational, is actually an understatement.
However, we can’t simply “Axe Drax” without thoroughly thinking it through and building suitable replacement capacity. Otherwise we would not have enough margin to keep the lights on (and the heating – a gas boiler can’t work without electricity, and most won’t work on a floating neutral from a generator or inverter) in cold, dark, calm weeks. If Drax can’t burn wood or coal, we’d be almost solely reliant on gas (so if our gas supply were interrupted by blockade or sabotage, we’d be buggered) and Drax is, so I understand, the only power station left which is big enough to do a “Black Start” to restart the grid if we did have a full blackout.
So again, if we shut it down without thinking, then the only person laughing would be old Vlad Putin.
Offtopic rant:
Apparently the government is cracking down on domestic fireplaces and wood-burning stoves now.. https://www.energylivenews.com/2025/12/01/wood-burning-stoves-face-the-chop/
https://assets.publishing.service.gov.uk/media/6929c774345e31ab14ecf778/Environmental_Improvement_Plan__EIP__2025.pdf
They plan to reduce PM2.5 pollution by.. banning domestic wood-burners and increasing the EV mandate to 80% by 2030 and 100% by 2035.. But it says absolutely nothing about industrial PM2.5 emitters such as Drax (and here in Southampton, the container ships and half-dozen cruise ships berthed which contribute most of our local air pollution)
I fail to see how the EV mandate will significantly improve air pollution either..
Drax produces enough electricity (15 TWh/year) to keep 4 million EVs (3750 kWh/year per car) on the road.. Tell me: What produces more PM2.5:
4 million electric cars powered by Drax (and its pellet production mills and shipping load), or 4 million petrol/diesel cars?
Given that engine standards have improved to the point where the vast majority of PM2.5 emissions from vehicles is non-exhaust (i.e. road wear, tyre wear and brake wear) then the EV mandate is unlikely to improve things. EVs are heavier and produce more torque, so they may even be worse in terms of road and tyre wear (granted, brake dust will be less if regen braking is used, but hybrids have regen too).
And the Government are never going to achieve their EV sales targets anyway, with a per-mile tax on EVs and Hybrids announced in their own budget! So all that will happen is car manufacturers are slapped with fines for not selling a product that people don’t want, because the government is taxing it with one hand and mandating it with the other, meanwhile ignoring the real problems!
A fine rant…
Ohyess!
Electricity, and the grid, are so precious, that we should not use it for heating or vehicles!
Surely we can help our CCGT situation by burning gas in the home rather than using electric HEATING !
It’s not that inconvenient!
And…
a gas BOILER is so much nicer than the usual 10kw electric shower! I’d say they use the same amount of gas overall but the electric one is half as efficient. Half the joy gets lost as heat outside the house! It’s also a far simpler and more reliable system overall, the gas boiler!
Same for CNG compressed natural gas VEHICLES: far simpler than electric, and on a par with overall gas usage efficiency. (see Italy and Germany, Eastern Europe, and especially Argentina etc.) EVERY car maker has CNG & petrol bi-fuel vehicles off the shelf! £1000 more compared to a pure petrol car.
Electricity and heating combined gives us the 90…95% efficiency we get from CHP combined heat and power (Berlin especially).
Even those amazing CCGT turbine systems give 55%, but there’s added grid loss until it heats your home.
No wonder someone blew up the pipeline… like the spoilsport at the beach who throws sand in your eyes so you dont see who trampled your castle.