Related Articles
Forward article link
Share PDF with colleagues

Flexible gas is key to the energy transition

The increasing volume of intermittent renewable energy on the grid means that gas peaking plants will provide an answer

The results of the UK’s latest capacity market auctions—where the owners of existing and planned generation assets compete for contracts where they receive payments for ensuring capacity remains available if and when needed— provided some clues as to how the UK’s energy mix will evolve. Its trend may also play out more globally. 

In the T-4 auction—that is, for four years out—43.7GW of capacity won agreements, of which 78pc was from existing assets (81pc in T-3) and 12pc from interconnectors (13.2pc in T-3). So, 10pc will come from plants not yet built. 

But there was also an interesting shift in the make-up of the successful existing capacity. Just 1.3GW was won by coal, all by Ratcliffe-on-Soar, likely to be the UK’s last coal plant standing. Perhaps more notable still, 1.9GW of nuclear capacity declined to take an agreement for 2023/24. 

And T-4 pricing surprised to the upside. The previous two auctions clearing at £6.44/kW/yr and £8.40kW/yr respectively, but the provisional clearing price in the T-4 auction hit £15.97/kW/yr. 

The higher price and the 15-year UK government-backed agreements—providing an important revenue stream to new non-intermittent assets—are good news for flexible energy generation, such as gas peaking plants, which are likely to be increasingly influential in the country’s transition to a lower carbon economy. The flexible generation sector has found investment hard to come by in recent years in a market beset by uncertainty, so the fillip is much needed. 

Market dynamics 

Certainty is very much at a premium in today’s energy market. Globally, there is, of course, huge volatility resulting from the implosion of the alliance between the Saudi Arabia-led Opec cartel and Russia, as well as the energy demand fallout from Covid-19. And we have yet to see whether the US reacts to try to shield its major producers by helping to support global prices.

“Now is the time big generators need to move more seriously to cleaner and more innovative technologies”

In the UK itself, the direction of travel may be clear—most obviously illustrated by the government’s decision to ban the sale of all new diesel and gasoline powered vehicles from 2035, moving the target forward five years from 2040. 

And the country’s largest independent power producer, Drax, which once operated the UK’s, and one of Europe’s, largest coal-fired plant is also moving ahead of target. It announced in February that it would stop commercial operations at its remaining coal-fired turbines in March 2021 and close them entirely when its existing capacity obligations expire in September 2022, well ahead of the government’s 2025 cut-off date for stopping coal-fired generation. 

The firm has already converted much of the Drax plant’s capacity to burning biomass in the form of wood pellets, as well as investing in a hydropower and gas plant portfolio and planning further flexible gas capacity. Drax is also looking at bioenergy with carbon capture and storage (BECCS), capturing the emissions from its biomass boilers as well as using sustainable supply, as part of a commitment to being ‘carbon negative’ by 2030. 

Wind rush 

The UK government has also abandoned its opposition to subsidising new onshore windfarms. This is over four years after ministers scrapped support for new projects, which effectively put an end to developments. Only one new onshore windfarm started under current UK policies, in 2019. 

Now, the government has agreed to re-open subsidies for onshore wind projects by allowing schemes to compete for financial support alongside other renewable energy technologies. This seems to be exciting news, but the devil may yet be in the detail. 

£15.97/KW/yr Provisional clearing price in UK T-4 capacity market auction

We are assuming that this will be some sort of contract for difference (CfD). But the exact details of how onshore wind will interact with other sources, whether there will be any cap on how much capacity can contract or how unintended consequences such as potential negative market prices will be managed will influence the size of any dash for onshore wind. 

Required change 

Old fossil fuel and nuclear plants will close down, and their replacement by intermittent renewables will put a greater onus on back-up generation, particularly once existing, fully amortised capacity finally shuts down for good. But reflection of this change in the UK capacity market has been relatively slow. 

The prospect of the removal of Triad charges—where energy consumers were charged for the use of the transmission network based on their average consumption over three peak half hour periods between November and February each year—from 2021, thus discouraging demand-side response, was seen as a blow to moving towards a more flexible system. And the capacity market has struggled to shake off the influence of the remaining coal-fired capacity. This, plus two mild winters, has kept prices benign. 

But the T-4 auctions results are a sign that this will change. Now is the time big generators need to move more seriously to cleaner and more innovative technologies to help provide replacement capacity as old fossil fuel and nuclear plants close down. There is now a stronger business case for investment in these assets. 

In the reserve market, awareness will grow of the role of small-scale, fast-responding gas generation in facilitating renewables. There is a lot of intermittent energy on the grid, but there is also a realisation that more flexibility is needed when unpredictable wind does not show up. 

Our view is that small-scale, flexible gas generation will play an increasingly important role in supporting the structural energy transition, both in the UK and globally. With the electrification of everything from transport to home heating, demand for power is clearly going to increase. But, while battery storage will likely become important over the longer term, the technology costs for storage as a major contributor to the grid do not currently appear to stack up. 

Where there may be opportunities is in peaking plant/battery hybrids, with the battery providing a short-term supply boost before gas takes over, enabling operators to respond quickly to capacity demand and price spikes. 

Grid imbalances 

The UK market provided a strong remainder in March of the value of having reliable, flexible generation on hand—and the cost of having not having it. On 5 March, UK energy cash-out pricing reached levels that had not been seen since 2015. System pricing in the 6pm to 7pm window (periods 37 and 38) reached £2,242/MWh and £1,708/MWh—almost £2,000/MWh above where the day-ahead and within-day power markets had valued the settlement periods. Why did this happen? 

New Stream Renewables’ systems showed a ‘net imbalance volume’ of around 475MWh short, which is not a significant level. On the supply side, generation capacity was similar to recent days with no big changes to plant availability and demand was around the seasonal normal. 

It would be too simplistic to say that the short system alone created the issue and spike in prices. In fact, the spike and high imbalance pricing was a result of the reserve scarcity pricing (RSP) mechanism, the methodology used to try to correctly price-in the value of demand disconnection from the grid, combined with unexpectedly low wind generation. 

The RSP is measured as the value of lost load (VoLL) x loss of load probability (LoLP). The VoLL is set at £6,000/MWh. If we look at LoLP in period 37, this was showing a figure of around 37pc, which resulted in cash-out pricing of up to £2,250/MWh. On the supply side, we had most of the large units running so there was little margin or flexibility to manage the short system. Short-term operating reserve (Stor) units were then called on and system pricing was set relative to the RSP. 

LoLP is a transparent figure and is forecast and published so this should act as a price signal, but the market did not price in the RSP event. On the day, we only saw market prices of around £350/MWh, which is well below the VoLL and imbalance pricing. 

RSP was only introduced in 2015 and, at the time, there was lots of discussion about making imbalance pricing more sensitive, but this is the first time we have seen this play out in terms of a price spike. 

 

Also in this section
PE Live: Hydrogen storage to boost offshore wind
3 August 2020
The ability to store and transport energy as hydrogen means that far more locations in the North Sea and elsewhere become viable for wind generation
Canada to announce blue hydrogen blueprint
30 July 2020
The federal and Alberta governments are seeking to build on existing hydrogen and natural gas production, with longer term plans for green hydrogen
PE Live: Local hydrogen policies may shape global industry
25 July 2020
EU member states and US state governments may have more impact on the development of the hydrogen economy than EU institutions or the US federal government