Back in late 2020 we had a look at the impact that an electric vehicle (EV) charging investment would have on the network costs for a 24/7 retail business
UK Market Winter Outlook 2023
As the temperatures plummet and we all bring out the winter coats, we thought it would be interesting to look at some relevant market developments that will impact Winter 2023 in UK and European power markets.
This time last year the prospect of blackouts was in the mainstream media in the UK, the forward curve was at times approaching over £300/MWh for baseload monthly power and there were new regulations across Europe regarding mandatory power savings. This was largely a result of the Russian invasion of Ukraine and subsequent dramatic increases in gas prices due to scarcity across Europe.
Fortunately, the prospect of rolling blackouts did not eventuate in the UK, although we did observe unprecedented power price levels placing a huge burden on consumers despite support from the government. This situation also triggered innovation from the industry including the NGESO Demand Flexibility Service, which allowed residential consumers to participate in, and be rewarded for, demand turn-down when market conditions were at their tightest.
In late September, NGESO published their 2023 Winter Outlook, a report that outlines Grid’s expectations for system margins and preparations for the winter ahead. In this year’s winter outlook the system margin in the base case is 4.4GW, which is more than last year though there is still a likelihood that Grid will need to use other operational tools including Demand Flexibility Services and System Notices to manage peak demand periods.
In the next section of this blog we explore some key changes impacting Winter 2023 and things we think will be interesting to watch as we get into the colder months.
Why does this matter? In 2022 38.5% of the UK’s electricity was supplied by natural gas, making it the marginal fuel and therefore the price setting fuel a large portion of the time. The UK produces some of its own gas in the North sea but also imports a large amount via LNG and also by pipeline. This means that the UK is susceptible to global gas pricing and availability.
What’s happening? After the Russian invasion of Ukraine in early 2022 gas prices surged globally both due to sanctions and then again following the destruction of the Nordstream gas pipelines. In late 2022, Centrica partly re-opened the Rough gas storage facility and subsequently bolstered capacity earlier this year; Rough can now store enough gas to heat 2.4 million homes over winter and provides about half of the UK’s gas storage.
Across Europe gas storage is sitting at over 95% of capacity, exceeding the EU target of 90% by 1 November. As we have had a generally warm start to winter these supplies are not yet being drawn down. More gas storage means more energy resilience when natural gas is still a key fuel source across the continent, though gas prices are still high relative to pre-2022 levels.
New renewable generation and price volatility:
Why does this matter? As we transition to a zero carbon grid, we will see more intermittent renewable energy such as wind and solar on the system. Renewable generation does not have a fuel cost so will often run at £0/MWh prices and below (usually down to the level of any subsidies and certificates they receive). This means in periods of high renewable generation we will see lower prices and then often spikier peaks during days where expensive peaking plants or storage is bought on to manage peak demand. Overall, this means more intraday price volatility.
What’s happening? In the last week the first megawatts started being produced from the Dogger Bank offshore wind farm. Dogger Bank A (1.2GW) is now online and connected to the UK transmission system. Once Dogger Bank B and C are completed the asset will total 3.6GW in capacity and be the largest offshore wind farm in the world.
With more renewables on the system, we’re likely to see increased intraday price volatility both in the coming Winter and in the seasons that follow. We’ve seen this in the Netherlands in recent weeks, another market with very high renewable penetration, with balancing prices swinging between -€1500 and €1800 within a day. As we see more renewables come online the requirement for flexibility both from large front-of-meter storage, which has huge momentum across the UK and Europe, alongside flexibility from other sources including DSR and fleets, will play an ever-increasing role.
Demand Flex Service Expands:
Why does this matter? Demand side flexibility typically means consumers or load responding to price signals to turn up or down. Often this can be loads like refrigeration, heating and pumping which do not need to run 24/7. As we move to an increasingly intermittent and renewable grid, demand side flexibility will be key to managing periods of peak demand.
What’s happening? National Grid’s successful Demand Flexibility Service (DFS) is set to expand in 2023, with the service going live from 30 October. Launched in 2022 this service allowed households with smart-meters to participate in energy saving periods by turning down their consumption.
The extent of their turndown was measured relative to their baseline generation on ten equivalent days over the last 60 days, and consumers were paid £3000/MWh of turndown they provided, those participating in the turndown events get notified by their Supplier/Aggregator. National Grid have announced that the service is returning in 2023 and also expanding into the Industrial and Commercial Sector.
So far, they have stated for the first six test events participants will receive £3000/MWh of turndown but that it will then move to a merit order driven price. DFS was mentioned as a key driver of bigger margins in NGESO’s Winter Outlook, highlighting that Grid sees this as a key lever they have to pull to keep the electricity system in balance. It will be interesting to see how much DFS is called in 2023 and what proportion of this will come from I&C customers. Something many Gridcog customers are exploring are DFS and future DFS type services and what value this could bring to investments they’re making in flexibility; storage, heating and EV fleets as examples.
New Ofgem regulation on inflexible offers (IOLC):
Why does this matter? The Balancing Mechanism (BM) is the tool that National Grid uses for balancing supply and demand in real time. All transmission connected assets in the UK must submit physical notifications in the BM to indicate how much they plan to generate at any given time, alongside the physical notification they submit parameters including how long they must run for and at what price they would be willing to turn up or down. During periods of short supply in recent winters we have seen some very high offers being accepted by National Grid (up to £6000/MWh) from generators who turned off in the early afternoon and then offered to continue generating power in the evening for very high prices and with multi-hour minimum run times.
What’s happening? Coming into effect on 26 October, Ofgem, the market regulator, has effectively banned this practice via the new Inflexible Offers License Condition. This applies to generators who switch their plant off for more than an hour. Breaching this could see fines of up to 10% of revenues. What this means is we are less likely to see very high offers accepted in the BM from large generators that have been running (i.e. in the morning) and then switched off, aiming to get dispatched in the BM as a trading strategy instead of selling that power in other markets prior to delivery. The marginal accepted price in the BM is what sets the System Price in the UK, so this new licence condition is likely to have some effect on this price as well.
Capacity Market system stress events:
Why does this matter? The Capacity Market (CM) is one of National Grid’s ways to incentivise generation to connect to the grid and ensure that they have enough for supply for system stress events. Generators (including battery storage and demand side flexibility) can secure capacity market contracts for either 1 or 15 years, the latter available for new build sites. Sites with a CM contract get paid a certain amount for every de-rated MWh of power. In early 2023 this cleared at £60,000/MWh in the T-1 auction for the delivery beginning October 2023. Sites with a CM contract must be able to deliver power in the event that a system stress event is called, unless they’re already delivering a NGESO ancillary service (i.e. Dynamic Containment).
What’s happening? In recent years we have seen an increase in the frequency of CM notices being issued, with some only being withdrawn minutes before the CM event would have occurred. However, we are yet to see a CM event come into effect; notices have always been withdrawn prior to delivery.
It will be interesting to see how many CM notices are issued across Winter 2023 (with only 4.4GW of margin according the NGESO it is probable we’ll see a couple) and whether we have our first CM event where delivery is required, this would be a huge and probably quite daunting event for the UK market as delivery in a CM event is relatively untested territory.
Why does this matter? Carbon emitting generators in the UK and Europe need to purchase carbon allowances for each tonne of C02 that they emit, this then forms part of the short run marginal cost for these generators, in turn making them more expensive and less cost competitive to run.
What’s happening? Prior to Brexit the UK was part of the European Emissions Trading Scheme and carbon emitting generators would purchase EUA’s to offset their emissions. Post Brexit, the UK has implemented its own Emissions Trading Scheme, and in recent months UK units have started trading at a considerably lower price than their European equivalents. What this means is that it is comparatively cheaper to turn on a CCGT in the UK compared to in Europe. With GWs of interconnection between UK and European markets this may at times impact the export/import balance between the UK and the continent.
Why does this matter? In the UK renewable generators can earn Renewable Energy Guarantee of Origin (REGO) certificates for each MWh of power that they export. Similarly, in Europe generators can earn Guarantee of Origin (GoOs). These are energy attribute certificates that many consumers and suppliers purchase to reference the renewable provenance of their supply and they are an increasingly material revenue stream for renewable generators.
What’s happening? Across 2023 we have seen REGO prices lift dramatically, with Argus reporting REGO current compliance period prices at above £18/REGO and e-power seeing REGO prices near £25/REGO in their most recent auction.
Prior to 2021 REGOs barely traded over £1/REGO so this shift has been dramatic and very material for renewable generators. It will be interesting to see if this elevated pricing can be sustained courtesy of demand for renewable tariffs, whether other factors are at play which have temporarily driven up the pricing and if and when the momentum surrounding 24/7 green provenance gains more momentum - currently REGOs are not time stamped or hourly matched.
There is a lot to consider across UK and European power markets for Winter 2023. What’s positive is that there are real tailwinds for renewable generation and innovative sources of flexibility across the board, including new opportunities to monetise these assets and hence more compelling business cases for investment.
At Gridcog, we’re continually impressed by the diversity of energy projects our clients are modelling and the increasing number of opportunities to commercialise demand, flexibility and renewables.