Unrealistic plans for the CCGT fleet

In its Clean Power 2030 plan, system operator, NESO, states that materially all of the existing fleet of CCGTs will be required to run approximately 5% of the time in order to meet demand on days when renewables output is low.

“Around 35 GW of unabated gas (broadly consistent with the size of the existing fleet) will need to remain on standby for security of supply. This requirement for gas capacity will remain throughout the early 2030s until larger levels of low carbon dispatchable power and other flexible sources are able to replace it,”
– Clean Power 2030 Report, NESO

This strikes me as difficult to achieve both operationally and economically. I reached out to some CCGT experts for their views, and they confirmed some of the things I was thinking.

Can CCGTS reliably run for only 5% of the time?

There is precedent for super-peaking plant to run very small numbers of hours: oil-fired plant such as Fawley, Littlebrook and Isle of Grain ran on this basis in the 1990s and 2000s. These plants were minimally staffed, and the operations staff that were employed undertook repeated simulator training to maintain competence.

However, CCGTs are inherently more complex than the simple steam cycle oil-based machines that operated on this basis in the past. The engineering of GTs is less robust and more “finicky” than STs. Some of the physical challenges associated with very low utilisation include:

• Corrosion and oxidation: prolonged idle periods can lead to corrosion of critical components such as turbine blades, combustors, and piping due to moisture or ambient air contaminants;
• Gas path fouling: even with protective measures, dust, oil, and other deposits can accumulate in the compressor and turbine sections, affecting performance during startup;
• Fuel system issues: long periods of inactivity can lead to clogging, varnish buildup, or microbial growth in fuel storage and delivery systems, especially in older systems without advanced filtration;
• Start-up reliability: ensuring the turbine starts reliably after long periods of dormancy requires rigorous maintenance of ignition systems, control systems, and auxiliary equipment;
• Lube oil degradation: lube oil can degrade or develop moisture contamination over time, leading to improper lubrication of bearings during startup;
• Sealing systems: mechanical seals, especially in older designs, may dry out or degrade during periods of inactivity, potentially causing leaks;
• Rotor bowing: prolonged stationary periods can result in rotor bowing due to uneven cooling or settling, especially in older turbines. This can cause vibration issues when restarting;
• Thermal insulation degradation: heat retention systems like insulation blankets can deteriorate during long idle periods, affecting thermal cycling stability upon restart;
• Battery and electronics failure: auxiliary systems (including control system batteries, sensors, and actuators) may fail due to inactivity, requiring replacement or recalibration before restart;
• Preservation of rotating equipment: extended dormancy requires specific preservation strategies, such as turning the turbine manually to prevent rotor bowing, using desiccant systems to maintain dryness, or nitrogen blanketing to avoid oxidation;
• Preservation of Heat Recovery Steam Generators (“HRSGs”) and auxiliary systems: HRSGs can suffer from corrosion in idle periods if proper lay-up procedures (wet or dry preservation) are not rigorously followed. Auxiliary equipment such as pumps and valves may seize up if not exercised periodically.

“Some stakeholders raised the importance of understanding the challenge of operating and maintaining an aging gas fleet that is running less frequently. This also includes workforce considerations…. Some stakeholders also noted the notice periods needed to turn on the gas generation fleet and the importance of ensuring these assets remain fit to run with a very different operational profile,”
– Clean Power 2030 Plan

Some of these challenges can be mitigated by the implementation of robust preservation plans which could include:

• Use nitrogen blanketing or dehumidifiers for turbines and HRSG systems;
• Regularly turning over or exercising critical systems (eg manually rotating shafts, testing auxiliary pumps);
• Conducting periodic startup drills to keep the system “warm” and prevent major issues from dormancy.

Enhanced inspection and monitoring would also be advised, including non-destructive testing for key components, and advanced monitoring systems (such as vibration analysis and thermal imaging) to identify degradation before failures occur.

The type of preservation would depend of the length of layup that is expected, and the ambient conditions which may affect corrosion. Most guidelines and industry practice attempt to define these periods – the following is a common approach:

• Standby – unit shutdown is overnight or for up to 72 hours depending on the ability to keep unit warm and under pressure;
• Short-term – unit shutdown is for up to one week and a rapid return to service is required;
• Long-term – equipment put out of service for more than 1 week and there is usually at least one-day notice for restart;
• Mothball – equipment is permanently removed from service, maintained in a preserved state for possible return to service if ever required.

Other factors that influence choice of layup practice include:

• Operating water chemistry and water treatment plant capabilities, availability of nitrogen or dehumidified air;
• Piping layout and materials used in steam/water piping and tubing;
• Condition of unit, particularly cleanliness of heat transfer surfaces;
• Local environmental regulations concerning disposal of chemicals;
• Local climate: humidity and likelihood of freezing over the year.

For example, nitrogen blanketing might be considered for layups of between one and three months where the environment is humid and prone to contamination, but would generally be advised in all environments for layups over three months.

Many of these processes would involve cost, and the use of additional equipment (eg for nitrogen blanketing).

Can CCGTs be staffed to run for only 5% of the time?

The long term reliability of plant generally relies on the accumulated knowledge of plant staff – these machines are designed to run for decades and over this time, staff build knowledge about the quirks of the machinery and how to manage them. In addition to staff running the plant, expert support staff are also needed to ensure the plant operates reliably. This includes an experienced grid compliance engineer, a pressure parts assurance engineer with 30 years steam plant experience, and a generator expert all of whom are required to ensure the plant remains reliable and operational.

“There is an increasing dearth of talent in the industry, as anyone trying to hire experienced operations staff or an engineering manager will attest,”
– Operations Director for a CCGT fleet

However, careers in fossil fuels are no longer appealing to many young people who see gas-generation as an industry in decline, and not unreasonably against these stated ambitions. However, as NESO makes clear, the CCGT fleet will be required as a backup for renewables from at least the next decade, so the industry needs to keep recruiting talent. It would be hard to maintain the fleet with simply existing staff given expected retirements, and the increasing difficulty of replacing these experienced staff will undermine the reliability of the fleet.

Can CCGTs be run economically for only 5% of the time?

The answer to this question is yes, as long as they are paid enough money to cover costs plus an acceptable return for investors and asset owners.

The economic challenge is greater than it was for the old oil peakers. The fact that oil could be purchased ahead of time and stored on site, while gas is bought just-in-time and piped from the grid makes a difference because the oil price would be locked in and the plant could then be run at very high power prices to cover a year’s worth of fixed costs over a small number of runs. For most of the period that the oil peakers operated there was no carbon cost to consider.

For CCGTs, the gas price tends to be high when the power price is high, compressing available margins in a way that was not the case with oil, and carbon costs must also be considered. While the capacity market is intended to help cover fixed costs, as utilisation rates fall, capacity prices will need to be higher to provide adequate returns to asset owners, otherwise they will simply close and release their capital.

The current plan appears to be to use the Capacity Market, but this would be a very expensive solution. To provide sufficient income to these CCGTs, capacity prices would need to be much higher, and since the Capacity Market is paid as cleared to all technologies, the whole market would then be remunerated at the level needed to maintain the 35 GW CCGT fleet. This will be extremely expensive.

“Reform of current market mechanisms, such as the Capacity Market, could help enable the continued operation of unabated gas for security of supply,”
– Clean Power 2030 Plan

A better solution would be to create a bespoke gas reserve. There could be challenges with EU State Aid rules, with which the UK must still comply, but all Member States will be grappling with similar challenges, so there may be exemptions to be had. However, the costs would still be high, and under current market mechanisms, would be fed directly to consumer bills.

It may be preferable to nationalise the fleet. This would make the reserve cost question redundant, but the acquisition by the state of 35 GW of CCGTs would cost £billions, and require higher taxes, which would also be unpopular. There are no obvious solutions to the economic challenge of keeping such a large asset base as insurance against bad weather, but one way or another, if CP2030 succeeds, this money will need to be found.

Current CCGT high utilisation is a further cause for concern

In recent weeks, the utilisation of the CCGT fleet has been 97.5% based on REMIT availability. Despite the weather not being particularly cold, demand for gas-fired generation has meant that almost every CCGT that could run, has run.

The chart analyses CCGT output versus CCGT availability based on REMIT reporting, and indicates that CCGT utilisation above 90% is not unusual in winter. In 2024, this has occurred earlier than in the past couple of years – 2022 had consistently high utilisation.

Industry experts believe this trend of tight CCGT margins will continue and spare capacity will shrink as plants close and are not replaced. Very little new plant is being built – there is only one new CCGT in the pipeline, 2 x 850 MW units due to be built at Eggborough, with capacity contracts for Winter 2026/27. I have heard from two different sources that EPC contractors have yet to be appointed, making delivery of these units the winter after next highly unlikely.

Whist this may be good for owners of CCGTs as they will benefit from higher earnings realised from scarcity, it does not bode well for consumers who will be exposed to this higher pricing, which will feed through to bills. The price of renewables looks artificially cheap in comparison since many of the associated costs, including the need for gas-fired backup is socialised directly onto bills. This feeds into the “expensive gas / cheap renewables” narrative, but is a fiction, since many of these socialised costs (also including higher network and balancing costs, as well as constraint costs) would be avoided if the system relied primarily on gas.

It is also worth noting that while the notional size of the CCGT fleet is around 35 GW, over the past 3 years, at no time has more than 30 GW been available according to REMIT availability data. REMIT is a blunt tool, but its limitations tend to understate rather than overstate outages. These data suggest that in practical terms, the CCGT fleet is about a sixth smaller than NESO believes, and this is also relevant in consideration of the extent of the gas reserve that is potentially available to back up low renewables conditions under the CP2030 Plan.

(Huge thanks to Amira Technologies for providing the REMIT data. I recently undertook this exercise for interconnectors and it is extremely time consuming. Receiving these data from Amira saved me a great deal of time for which I am very grateful! I would urge Elexon to offer this service through BMRS to all market participants since understanding availability across the technology types will be increasingly important as the energy transition progresses.)

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The inevitable conclusion is that it will not be possible for all 35 GW of GB CCGTs to be maintained as a reserve from the end of this decade onwards. NESO is providing the Government with a false sense of security in suggesting that this is feasible – hopefully wiser heads will prevail before a future dunkelflaute leads to blackouts when a claim is made on the “low renewables” insurance and we discover someone forgot to pay the premium.