2021, A Year in Review: The Twelve Days of (energy) Christmas

The pandemic may yet again have dominated the headlines in 2021 but it’s also been a year to remember for the UK energy industry; from the highs of record levels of renewable generation and Glasgow playing host to the most high-profile climate change conference in the world, to the lows of soaring wholesale prices seeing a mass exodus of energy suppliers. As for the flexibility market, its importance for the transitioning energy system has never been clearer, owing to the growing penetration of intermittent generation and the development of new products by National Grid, opening up yet more opportunities. Here, we’ve summarised twelve key takeaway messages from the last 12 months and what the implications, challenges and opportunities may be for the next year.  

1. Wholesale prices have been rising dramatically

Wholesale prices have been rising dramatically (Fig. 1) and this is driven by the fact that the marginal source of generation in the UK is often gas (and gas and carbon prices have been rising too). In this year alone, wholesale prices have increased by 200%. 

Figure 1. Rising wholesale prices over the past twelve months. Source data from EPEX. 

The impact of rising wholesale prices has pushed almost 30 energy companies out of business, leaving over two million customers dependent on the safety net provided by the market regulator, Ofgem, to maintain their supplies and protect their credit balances while it moves them to a new supplier.

2. Revenues for dispatchable technologies are flourishing 

System tightness has led to exceptionally high prices. In September, low margins were caused by falling wind output and planned and unplanned outages at major thermal and nuclear power stations. The twenty highest system prices over the past twenty years have occurred this year (table 1). Furthermore, examining the top 100 day-ahead prices this year reveal the dramatic increase in price and also volatility compared to the previous five years which is driving the business case for dispatchable technologies (Fig. 2). This trend is likely to continue as the UK is heavily reliant on fossil fuel assets that are operating at lower load factors for the majority of the year and therefore bidding into markets at prices much higher than their marginal cost of dispatch in order to recoup lost costs. 

Table 1. This year's highest ten system prices compared to last year.

Figure 2. The top 100 day-ahead prices over the past five years. With the exception of 2017 where the highest day-ahead price was just under £1000/MWh, the most recent three years highest prices were below £500/MWh. 

3. Energy trading has become a lucrative revenue stream for batteries 

A battery in 2020 employing a trading strategy across only the day-ahead, intra-day and NIV chasing could have made up to £50,000/MW compared to a battery this year that would have achieved closer to £120,000/MW, an increase of 140% (Fig. 3). 

Figure 3. Perfect foresight of monthly revenues from day ahead, intra-day and NIV chasing for a one hour battery with an 88% RTE. Note that December 2021 revenues only include up to Dec 13th.

4. Gas generators are also profiting significantly

CCGTs and coal have played a huge role this year when renewable generation has been low and this has led to exceptionally high day-ahead and system prices – highlighting the need for cheaper sources of short term flexibility at scale and also clean dispatchable baseload generation. In total revenue from gas generators was over three times higher in 2021 than 2020 (Fig. 4). So what does this mean for decarbonisation? It is likely this trend will continue until a higher volume of low carbon dispatchable technologies such as longer duration energy storage, CCUS, hydrogen and BECCs come online. This is necessary to reach net zero at a cost lowest to consumers.

Figure 4. Monthly revenues from gas generators were consistently higher in every month in 2021 compared to 2020. This does not include revenues achieved through the balancing mechanism.  

5. Wind generation has reached new record levels

Since 2010, the share of coal and oil fuelled generation has declined dramatically - to be replaced by wind and solar (Fig. 5). This year wind generation set three records. In May, wind generation peaked at 17.7GW meeting approximately 55% of UK demand and surpassing the previous record of 17.6GW earlier that month and the record of 17.5GW set in February. On May 21st, wind generation broke another record by delivering its largest ever share of electricity demand in Britain. In the middle of the night, wind generation met 62.5% of demand beating the record set in August 2020 when, during Storm Francis, wind generated 59.9% of demand. With the Government targeting 40GW from offshore wind by 2030 (compared to the current installed 10GW) this trend is expected to continue, however it is unlikely given the pace of development that the target will be reached. 

Figure 5. Proportion of installed capacity from 2010 to 2021.

6. Average grid carbon intensity has reached a new low

This rise in renewable generation has reduced the carbon intensity of the grid. As a result, on April 5th, GB electricity was at its ‘greenest’ ever with only 39 gCO2 / kWh. Wind power made up 39%, solar 21% and nuclear 16% at 1pm, meaning zero carbon sources comprised almost 80% of the GB generation mix. This compares to last year’s record on August 17th of 49 gCO2 / kWh.  However, our annual average is still above the 50 gCO2 / kWh target for 2030 (Fig. 6). Assuming decarbonisation of the generation mix continues at the same rate the 2030 goal appears possible, however, this does not account for the expected slow down as we decarbonise the final parts of the system. Nevertheless, we take encouragement from how far we have come in comparison to 336 gCO2 / kWh back in 2015. 

Figure 6. Carbon intensity of the grid (gCO2/kWh) between 2015-2021 compared to the 2030 target. Source: carbon tracker and National Grids carbon intensity API. 

7. But coal consumption has been higher

Last year, the system ran without coal for 67 days straight, the longest hiatus since 1970. In 2019, it only achieved 18 days (Fig. 7). That record was propelled by lower demand as a result of lockdowns and high renewable generation. This year has been different. Demand has rebounded, coal plants have been pushed into the merit order more frequently, but lower wind levels meant that renewables have struggled to keep up, highlighting the severe need for low carbon dispatchable technologies. For context, in the first 3 weeks in September, wind generation was 60% lower than the previous five-year average.  

Figure 7. Percentage of coal as part of the generation mix with white spaces illustrating coal free days. Source data from gridwatch. 

8. Dynamic Containment is helping to stabilise frequency

An effect of higher renewable penetration is declining levels of inertia which the NGESO has had to manage. Last year, in response, NGESO launched Dynamic Containment (DC), the first of three new and faster acting frequency response products. 

The decrease in inertia has meant over the last 5 years, the energy throughput required to perform Dynamic Firm Frequency Response (DFFR) has nearly doubled (Fig.9 - see blog on the evolution of frequency). This is a result of thermal plants that produce mechanical inertia have been operating less as more asynchronous generation have been replacing them (renewable generators). Since the launch of DC, there has been a noticeable decrease in the energy throughput required to carry out a DFFR contract (Fig. 8). This could suggest that the strict tolerances and rapid response required at 49.8Hz and 50.2Hz are helping to manage the Rate of Change of Frequency (RoCoF) within a smaller envelope and therefore resulting in legacy products like DFFR working ‘less hard’.    

Figure 8. Daily energy throughput for a 1C storage facility supplying a 24x7 DFFR service from 2015 to October 2021.

9. However, the DC market has become saturated with providers

The volumes NGESO planned to procure over winter have decreased significantly from the 1GW+ anticipated earlier this year (Fig. 9). Procurement targets tend to be higher overnight when inertia is expected to low and lowest during peak demand. For the next few years it is also likely to vary seasonally with summer months having a greater requirement due to embedded solar generation.  As a result, the market has become rapidly oversupplied during certain EFA blocks and prices have fallen from the stable  £17 /MW / hr seen over the past 12 months (Fig. 10). In October, NGESO introduced the reverse service to DC-Low (DC-L), DC-High (DC-H) as well as moving from daily 24 hour contracts to closer to real-time procurement, 4 hourly contracts (EFA blocks). This allows for more intelligent bidding strategies that optimise across multiple markets within day. The introduction of closer to real-time procurement, has caused a divergence of DC-L and DC-H prices throughout the day, with some EFA blocks clearing as low as £1 / MW / hr compared to more lucrative prices at £48 / MW / hr (Fig. 10). 

Figure 9. Average weekly accepted and rejected volumes in the DC market. Volumes bidding into the market have increased by a multiple of three since the beginning of the year.

Figure 10. Average daily contract prices for DC-L and DC-H. 

10. Ancillary services have been the primary source of revenue for battery owners, but this is predicted to change.

Battery owners presently see frequency services as the main source of their income. This is likely to change over the next 12 months, due to market saturation and the factors that drive NGESOs volume requirements. The next two products to be launched in 2022 are Dynamic Regulation (DR) and Dynamic Moderation (DM). Given the increased energy throughput requirement for DR, the longer service duration, and the limited ability to simultaneously stack across these services, it is unlikely that DR will be an attractive product for battery owners.

11. Balancing the system has become more costly than ever before

National Grid often ends up paying significantly more to balance the system when wind is high and transmission costs are highest, or when renewable generation is high, demand is low and RoCoF costs are highest.  Balancing costs are usually around £2-3m per day, however, they have been increasing (Fig. 11). On November 24th, balancing costs were over £63m for the day, ten times higher than the record day for balancing costs in 2020. These costs are recovered through a mechanism called BSUoS. Last year, BSUoS costs increased significantly during the pandemic when NGESO spent over £700m balancing the low levels of demand on the system during high levels of renewable generation. In October, increased wind generation caused network constraint costs to rise due to increased congestion on the system and the requirement to ramp up synchronous generators to provide voltage support and inertia. Last month, National Grid ESO announced that it would review the costs of the balancing market.  Over the last three months, the total BSUoS cost reached £1.25 billion, more than double the £524 million figure for the same period in the previous year. This trend is likely to persist as we continue to decarbonise the system while using thermal assets for operating reserve and balancing. 

Figure 11. Half Hourly BSUoS costs over the past three years.

12. The UK has a strong pipeline for storage assets 

The build out of battery storage is linked to the current investor confidence regarding the increasing value of wholesale and balancing markets.  Tracking the progress of flexible technologies reveals that the battery storage development pipeline has risen to 24.3GW (double the projected 12 GW required for some of the FES 2021 scenarios and 10GW more than the USA storage pipeline) across 800 projects (Fig. 12). 

Figure 12. Battery storage pipeline and duration of technologies out to 2025.

Summary

2021 has been an imperfect storm for many within the energy industry, from asset owners to suppliers. It has also highlighted that the UK relies on gas generators for power during times of system tights - and this is costly. 

In the future, as these thermal plants retire, the need for low cost firm capacity during periods of low renewable output as well as short duration flexibility that are efficient at short term balancing and offering stability services will be even more pertinent. 

Therefore, the importance of flexibility and digitalisation for the decarbonisation of the UK’s energy system has never been clearer –  something that was reflected in the government’s highly anticipated net zero strategy and National Grid’s Future Energy Scenarios. Moving forwards for 2022, as finite markets such as frequency response become even more saturated the focus for battery owners should be on real-time optimisation across ancillary services, wholesale and balancing markets.