Each guise reflects a design-engineered running strategy, based on an assumption of market demand.
As the share of renewable energy generation in the UK increases, the market requires more flexibility in response to variations in supply and demand, and generously rewards plants that can offer it.
Providing ancillary services to National Grid is becoming an increasingly valuable revenue stream in its own right, as the wholesale market price stays low and the share of intermittent capacity on the system increases.
Peaking plant specifically targets pockets of high demand, and only operates for short runs to capture temporarily high prices.
Typically, this is early in the morning, and late afternoon or evening, particularly on days with low solar irradiation and low wind.
As peaking plants are not designed to operate for prolonged periods, it does not make sense to design them to maximise their efficiency rating (as the higher capital cost would not be compatible with shorter run times).
Combined cycle gas turbines (CCGTs) can achieve thermal efficiency of around 62% in baseload operation, compared to a single cycle peaking efficiency of up to only 40%.
However, the purpose of peaking plant is not to run for long enough periods to capture the benefits of efficient operation.
Often with much smaller in capacity (typically less than 50 MW and generally around 20 MW), peaking plants are generally connected to the distribution network, rather than the transmission network.
Baseload plants are typically CCGTs, designed to operate for long running periods.
It is possible for CCGTs to operate flexibly, if market conditions require a different running profile (if they have a sufficiently attractive ramp rate).
However, the consequence of load-following and cyclic operation (e.g. double two-shifting) is that, in addition to fuel inefficiencies, the extra start-ups put more pressure on turbines and ancillary equipment.
This affects the schedule programme (i.e., requires more frequent maintenance outages) and warranties for the plant under associated long-term service agreements (LTSAs) (normally, both starts and running hours are considered under a LTSA).
Operators commonly find that cycling or load following in plants that were not designed for that purpose causes stresses associated with varying temperatures and pressures, leading to fatigue-related damage and other issues.
A CCGT has a second steam turbine in addition to its gas turbine, which accounts for the improved efficiency figures (and some barriers to operating more flexibly).
The energy in high-temperature exhaust gases from the gas turbine is recaptured by passing the exhaust gas through a heat recovery steam generator.
This generates a number of steam cycles that are passed over high and low-pressure turbine blades, before being condensed and recycled.
In comparison to peaking plants, CCGTs (being primarily designed for baseload) are large, generally consisting of a number of units – e.g., three units of a 270 MW gas turbine coupled with a secondary 130 MW steam turbine.
Their size and efficiency means they produce far less CO2, SO2 and NOx than coal, open cycle gas turbines (OCGTs) and energy from waste (EfW) plants.
Gas-fired generation, in any guise, continues to be an incredibly important part of the UK energy mix – currently accounting for approximately 40% of generation and 33 GW of installed capacity.
Along with interconnectors, demand-side response and energy storage, gas power is also a key mitigant to the intermittency of renewable generation.
The Capacity Market impact
The Capacity Market (CM), as a cornerstone of the UK government's Electricity Market Reform (EMR) initiative, was intended to encourage a new cohort of gas-fired generation.
As it turned out, however, the increasingly low price of CM contracts could not compensate for falling wholesale power revenue.
Compounded by the imminent closure of the UK's remaining coal plants by 2025 and the collapse of two of the three nuclear new build programmes, this has put considerable pressure on the UK's capacity growth and carbon reduction targets.
There are two key reasons for the CM not delivering new build gas capacity.
The first is supressed market prices and insufficient spark spreads (the difference between the wholesale market price of electricity and its cost of production using natural gas) to justify investment.
This has effectively forced plants to compete for ancillary services, or in the balancing mechanism, as a way of supplementing their income under power purchase agreements (PPAs) or the wholesale market.
The second is competing government incentives and policies. Almost every other form of generation was subject to government intervention at or around the same time as the CM was introduced, which has ultimately prejudiced gas' competitiveness.
For example, coal-fired power was given the option of "burning out" under a running hours permit, and then closing, while also benefiting from low coal prices, due to increased shale gas production in the US.
Nuclear benefited from the strong carbon price top-up to the EU Emissions Trading Scheme (ETS).
Renewable generation benefited from a variety of attractive subsidies, including under the Renewables Obligation (RO), the Feed in Tariff (FiT) and the Contracts for Difference (CfD) regime, all of which offer significantly more attractive subsidies than the CM.
Ultimately, the combined effect has been to shift investor interest into renewable generation, rather than gas-fired projects.
What next for gas?
The CM has ultimately failed in one of its primary purposes – to deliver a new wave of baseload gas-fired power plants.
However, the increased share of intermittent renewable generation on the grid has created an opportunity for smaller peaking plants, which can exploit short-term market price spikes driven by falling renewable production in cloudy or still conditions.
Large CCGTs face additional planning costs (primarily for obtaining Development Consent Orders (DCOs), but also policy-driven costs, including the need for >300 MW plants to accommodate the carbon capture readiness policy and for >50 MW plants to consider combined heat and power (CHP)).
Such plants would also be required to pay a hefty total carbon price, in whatever form that takes in a post EU-ETS regime.
Aside from CCGTs and OCGTs, more interesting opportunities for gas have arisen from other technologies, such as:
Syngas is a by-product yielded when biomass or waste is heated with low oxygen in gasification processes, or no oxygen in pyrolysis processes.
Biogas is a mixture of carbon dioxide and methane, produced by microorganisms when they digest organic feedstock at low temperatures in anaerobic conditions.
The speed and scale at which green hydrogen can displace natural gas in the UK gas network has attracted significant interest.
Green hydrogen is produced from the electrolysis of water using electricity from renewable sources.
The production of syngas and biogas is well-advanced technically, although not operating at significant scale yet.
Green hydrogen has more potential to operate at scale, but renewables-driven hydrogen production is still at an early stage.
It is hoped that hydrogen can fill gaps in the energy market by:
Being cheaply and cleanly produced from renewable sources (through water electrolysis, as opposed to through steam reformation of hydrocarbons, which is how well over 99% of hydrogen is currently made) in remote areas where grid constraints are an issue;
Becoming an efficient store of energy once produced (e.g., if effectively stored in liquid form, such as through liquid organic hydrogen carriers (LOHC), rather than gaseous form, which requires extremely high pressures or low temperatures); and
Becoming easier to transport in large quantities through existing gas infrastructure.
The ambition to transition to green hydrogen is significant, especially given the fuel's potential role in meeting the UK government's "Net Zero" emissions by 2050 target.
The success of green hydrogen relies on significant further technical breakthroughs on the production and transportation side, but it remains one of the main contenders to replace at least some of the UK's conventional gas-fired power generation in the future.
Hugo Lidbetter is a partner specialising in energy and natural resources at European law firm, Fieldfisher. For more information on our renewables, oil and gas and wider energy expertise, please visit the relevant pages of the Fieldfisher website.
Sign up to our email digest