The UK is at much greater risk of blackouts this winter than the National Grid has forecast¹ with market prices showing that expectations of being able to rely on imports from continental Europe to meet demand shouldn’t be taken for granted, according to the analysis of National Grid’s Winter Outlook¹ by Hartree Solutions, with market spreads at times implying a 99.7% risk of blackouts.

Whilst historic flows show that the UK typically imports during the winter, market prices point to a much tighter scenario with the UK likely to be exporting for many of the high demand periods creating a lower margin and thus a greater risk of supply problems as a result. This makes it difficult to see why National Grid is so confidently expecting imports this year without considering the market’s expectation for much of this year.

National Grid’s Winter Outlook¹ states that “the margins on the electricity system are lower than last winter but forecasts are well within the national Reliability Standard’’ resulting in there being “sufficient generation and interconnector imports to meet demand throughout winter 2020/21”. This assumption is based on GB baseload forward prices being higher than those in France, Belgium and the Netherlands and therefore providing net imports via the interconnectors of 3GW, according to the Grid’s base case scenario.

Yet analysis by Hartree Solutions² shows that although the UK baseload price for January has recently ticked over into a small premium against the equivalent French price the majority of the peak hours are still indicating interconnector exports.

Refinitiv² hourly fair value curves for January ’20 working days as of 10.10 am 16th Oct ’20 expressed over a 24 hour day. Hartree average demand forecast for January ’20 working days.

Ever since the end of February, the market has been pricing in France at a premium to the UK this January. Indeed, for parts of the summer, market prices were pointing to Belgian prices also being above the UK for that peak winter demand month.

Refinitiv² FV spreads for 5 pm (the UK’s peak demand hour) as assed each day throughout 2020

If the UK is exporting across the interconnectors, according to the market view and against National Grid’s view, margins will be 3GW lower than forecast in the Winter Outlook¹ giving a revised margin of 1.8GW. This figure includes the start-up of a second interconnector to France, IFA2, that’s due to come online in November which would potentially increase the flow of exports.

Analysis of the UK and continental price spreads for the UK’s peak demand hours this winter shows that expected flows have varied from 4.25GW of imports to 3.75GW of exports over the course of the year so far. This is in stark contrast to National Grid’s Scenario analysis¹ of 2.86GW imports to 0.75GW of exports, leaving a 3GW delta between the market’s view² and the Grid on the likelihood of exports this winter.

Interconnector Implied flows using Refinitiv² fair value 5 pm price spreads for Jan ’20. National Grid’s¹ Interconnector Scenarios overlaid.

Hartree Solutions’ analysis shows that the National Grid’s modelling assumptions do not appear to be robust enough and place the UK at greater risk of blackouts this winter. Rather than the comfortable picture that Grid looks to be painting, the market’s² most extreme forecast Interconnector flows would see the UK’s margin shrink to -1.95GW giving a 99.7% likelihood of a blackout using National Grid’s Loss of Load Probability³ (LoLP) calculation.

In a follow-up Market Insight, Hartree Solutions will delve into National Grid’s Covid-19 demand assumptions this winter along with our own analysis that warns there’s a demand shock in store.

Real-time insights such as these show the value of partnering with Hartree Solutions and benefitting from our trading and risk-management expertise. We give businesses the freedom to concentrate on what they’re best at and turn a potential liability into a dynamic asset.

More Market Insights

^{Footnotes  
1} National Grid Winter Outlook
² Refinitiv Fair Value Curves
³ National Grid LoLP

On Tuesday 15^th September National Grid issued only its second Capacity Mechanism (CM) warning¹ indicating a lack of margin on the system whilst also publishing the probability of a blackout was 36.9%² via its Loss of Load Probability (LoLP) calculation. (See our Market Insight covering the events of this day in detail). However, if we rewind the clock to 6^th May, National Grid contracted Sizewell Nuclear power plant³ to half its generation in reaction to Covid led lower demand.

Our analysis at Hartree Solutions concludes that these actions, through higher power prices led to:

• increased costs to consumers of £72.7m,
• additional wholesale costs of £3.8m on the 15^th September,
• a 24% increased risk of a blackout,
• an increase to the Reserve Scarcity Price of £1,442, and
• the issuance of a CM notice

On the 6^th May 2020, the market had just observed a 14% demand loss⁴ for UK electricity as a result of the Covid-19 lockdowns. As a result, National Grid announced it had contracted with EDF to reduce the generation of its Sizewell nuclear power plant to 50%, a reduction of 600MW, to counter periods of low demand and oversupply⁵. Additionally, National Grid created a new product ‘Optional Downwards Flexibility Management’ (ODFM)⁵ that reduces embedded generation resulting in increased demand during these challenging low demand periods.

As the summer progressed and the observed demand loss directly associated with Covid decreased from 14% to just 1% by August⁶, National Grid decided to extend the Sizewell contract on 6^th August out to 24^thSeptember⁷.

During this time, National Grid had only utilised its ODFM service a total of 5 times with the last date of usage on 5^th July⁸, possibly an indication of the reduction of system stress from lower demand. Below we have highlighted the Covid-19 demand destruction alongside National Grids usage of ODFM. As the demand destruction eased the requirement to use such products diminished and arguably their value. As a result, some may view the decision to extend the Sizewell contract a puzzling one.

Assessing the value of such contracts is complex and requires the consideration of several factors such as the impact on market prices, the costs of balancing the system and the cost of the Sizewell contract itself. Due to lower demand and the increased oversupply of electricity generation, National Grid’s balancing actions have both increased in volume and costs⁹. In such low demand periods, balancing costs will have been reduced by the lower generation levels of Sizewell. The realised benefits of this can only be valued by National Grid, numbers that are not readily available at the time of publishing this Market Insight.

However, at Hartree Solutions, we use our in-house models to analyse the impact of the Sizewell contract on wholesale power prices. To do this we enabled both Sizewell units to be fully operational in our model and then compared this power price forecast with that of our base case forecast (using just one unit available as contracted by National Grid). As you would expect, removing a baseload 600MW generation unit from the market results in higher power prices. Below we express these as both a daily cost to consumers as well as the cumulative cost from 1^st May to 16^th September. This cumulative increase in wholesale power prices resulted in additional consumer costs of £72.7m⁴. (See chart ‘Cumulative Industry Costs’)

Whilst National Grid contracted Sizewell off to avoid the risk of blackouts in low demand periods, on 15^thSeptember this blackout avoidance contract had the opposite effect leading to an increased risk of a blackout by 24% from 12.9% to 36.9% as the UK experienced low winds and high generation⁴.

The 1-hour LoLP as published by National Grid² on this day was 36.9% at its high, representing the likelihood of blackouts. As we know, National Grid had contracted 600MW of Nuclear generation not to run during this period. The LoLP calculation is a dynamic hourly calculation. Hartree Solutions have modelled this calculation and estimate that had Sizewell not been contracted off this probability would have dropped to 12.9%, a 24% reduction of a blackout risk as demonstrated above.

The LoLP calculation also feeds into the imbalance price calculation as it is multiplied by the Value of Loss of Load (VoLL) of £6,000 creating the Reserve Scarcity Price (RSP)¹⁰. This value was £2,213 for period 37 on 15^th September. Using Hartree Solutions calculated LoLP assuming no Sizewell contract leads to a reduced RSP of £1,442 to £771 MW/h.

Further, from our modelling (as shown below), we demonstrate the market power price impact on this day from the Sizewell contract⁴. As a result, wholesale power prices were significantly higher leading to increased consumer costs estimated to be £3.8m.

We also analysed the rules of issuing a CM notice concerning the events of this day. Our analysis shows that had Sizewell not been contracted off no CM warning would have been issued due to the greater margin available.

This analysis demonstrates that in times of system stress, relatively small volumes and events can have a large impact on prices. To manage these risks, it is essential to have a detailed real-time understanding of the mechanisms and drivers of pricing. At Hartree Solutions, this is our day job. Using these skills, we can partner with large energy consumers to mitigate these risks for them and guarantee energy bills up to 30% lower.

 

^{Footnotes  
1} National Grid CM warning message
² National Grid LoLP message
³ National Grid Sizewell contract
⁴ Hartree Solutions Analysis
⁵ National Grid Announces new low demand tools
⁶ Hartree Solutions internal demand forecast accounting for expected wind and solar installations and non-Covid-19 year-on-year demand destruction
⁷ National Grid Extension of Sizewell contract
⁸ National Grid Usage of ODFM
⁹ Ofgem review of balancing costs summer 2020
¹⁰ Reserve Scarcity Pricing calculation

Yesterday, Tuesday 15^th September 2020, low wind paired with high demand created system tightness, prompting intraday prices to spike over the evening.

The market had priced tightness at the day-ahead stage, with Monday’s 11 AM auction for delivery Tuesday pricing at £64.9/MWh baseload^[1], the highest since January 2019. This was a result of low wind and high demand forecasts.

The highest hour, starting 6 PM, priced at £171/MWh^[1] as suppliers looked to secure their customer demand ahead of time, simultaneously allowing generators to lock in a profit. The bullish sentiment increased throughout Monday with the later half-hourly afternoon auction edging higher at £68.3/MWh baseload^[1].

With Hartree’s proprietary forecasting models and analytical expertise, we anticipated tightness in the system and high prices as a base case, with significant upside over several of our sensitivity scenarios.

Coming into Tuesday, it quickly became clear that the system was tighter than previously forecast on Monday. Firstly, demand was out turning ~2GW higher than the prior day, and wind generation in the UK was underperforming against forecasts. National Grid De-Rated Margin forecasts were decreasing as the day evolved, increasing the possibility of a strong Reserve Scarcity Price over the evening peak. In way of an example, the 8h horizon Loss of Load Probability (LoLP) forecast for the half-hour 18:00-18:30 stood at 0.71^[2], which multiplied by the Value of Lost Load (VoLL) £6,000/MWh^[3] gives a Reserve Scarcity Price of £4260/MWh. Any short-term operational reserve (STOR) volumes called on by National Grid would be re-priced at this Reserve Scarcity Price, increasing the likelihood of this becoming the final imbalance price. This warning signal kicked the intraday continuous market into overdrive, as market participants looked to position themselves in preparation for high prices at delivery.

At 1:04 pm National Grid issued a Capacity Market (CM) Notice for 5:30 pm, quoting the low De-Rated Margin. This was the first time such a warning had been issued since November 2016. This had a slight cooling effect on prices, as any CM contract holders were highly incentivised to fire up generation to help cover the anticipated shortfall in power. CM actions have no direct effect on the imbalance pricing mechanism. That being said, by 2 pm the 2-hour period starting 5 pm was trading at £440/MWh^[1], far above the day-ahead auction.

At 2:05 pm National Grid subsequently cancelled the CM notice. This re-kindled the fire in the intraday market, with volumes stepping up alongside prices as delivery approached. By 5:30 pm, the 6:00 pm contract had traded north of £1,000/MWh^[1] as the possibility of a £2,160/MWh Reserve Scarcity Price looked ever likely. Although National Grid had published volumes marked as Balancing Services Adjustment Data (BSAD), they were not STOR flagged, meaning that the Reserve Scarcity Price would not come into play in the imbalance price calculation. Instead, it would be the BSAD and Balancing Mechanism actions which set the price through the PAR-1 pricing structure.

This nuance of the pricing mechanism highlights the need for in-depth expertise and understanding of the UK electricity market rules, a market which Hartree has operated in for over a decade. With our experience and market access, we can optimise generation, both grid-embedded and behind-the-meter, to navigate volatile times such as these and deliver both income and savings to our customers – no matter the situation.

More details on the pricing mechanism

Sources
^[1] EPEX Spot
^[2] National Grid
^[3] Elexon
^[4] Hartree Solutions

Since last week, as the weather forecast has become more certain, Hartree Solutions’ in-house models have been identifying potentially high system prices for today’s evening peak. This is, for the most part, a result of total unconstrained wind ramping down from a peak of 16GW to an expected forecast of 1.5GW.

This observed tightness was evident in the Day-Ahead auction results as it cleared at the highest level since 3^rd Dec 2019 with a baseload price of £48.86/MWh and Block 5 (the four hours starting from 3 PM) at £71/MWh. This potential system tightness can be observed in our scenario analysis as generated prior to the Day-Ahead auctions as shown below:

As wind turbines slow over the day, the requirement for thermal generation increases. We forecast almost all the available gas fleet to run, with station utilisation at 92%.

With the UK fully importing from France, Belgium & Netherlands via interconnectors, the remaining demand peak leaves little to no flexibility for the market and ultimately National Grid to balance the UK without looking further up the merit order to incentivise coal station running.

For this evening’s peak, the two key drivers of price action will be wind outturn relative to forecasts and spare thermal capacity which currently sits at just over 3GW. With the risk of power plants tripping, leaving them unable to generate, this margin could reduce even further. If either wind generation delivers lower than forecast or there are unscheduled power plant outages, then the market will be susceptible to high system prices as the balancing mechanism makes up this shortfall. Conversely, if wind generation remains higher than forecast for longer, then we will see National Grid bidding off plants in the Balancing Mechanism, suppressing system prices to some of the more mundane outturns shown in our scenario analysis.

There is further potential for a higher price response when we take into account the details of the imbalance pricing mechanism in the UK. If the low system margin remains then a pricing mechanism can come in to play, the Loss of Load Probability (LoLP), that reflects the probability of a shortfall of power generation to meet demand and thus blackouts. When National Grid activates one of its balancing tools, the Short-Term Operating Reserve (STOR), then these STOR volumes will be re-priced at the higher of their utilisation price or the Reserve Scarcity Price (RSP) of £6,000/MWh multiplied by the LoLP. This is the same pricing mechanism which helped set the latest high price record on 4^th March this year when the system price hit £2,242/MWh triggered by a LoLP of 37% whilst STOR was in action (see Market Insight).

This morning, the system has had excess energy, and so National Grid has been bidding off more power than they have been offering on. This has led to low Cashout prices despite the strong auction yesterday. This large pricing delta from the auctions is largely due to wind out-turning 1.5GW higher than forecast plus Coal Power Stations running close to full-load to ensure it is warmed and ready to be offered on later tonight.

Last month, the UK’s coal-free generation streak came to an end after two months – the longest period since the industrial revolution. This record is in part down to lower power demand, as Covid-19 restrictions hamper travel, commerce and industry. As noted in our previous Market Insight post, we have seen a reduction in this effect as Covid-19 restrictions are loosened with demand returning close to pre-Covid-19 levels for both the morning and evening peaks. More recently, due to the hot weather, we have seen a boost in demand as air conditioning units power on.

As the UK moves away from coal generation and continues to rely on harder-to-forecast renewable generation, the UK is seeing a rise in power price volatility. By investing in decentralised local generation and utilising our market-leading power forecasting we can help protect our customers from the costs associated with this ever-increasing price volatility. This allows Hartree Solutions to guarantee our customers fixed long term power savings over anything else achievable in the market.

The True Impact of Covid-19 on UK Power

Covid-19 caused a drop in both power prices and demand via the induced lockdown that resulted in a loss of income in the UK Power Industry of £1.1b between March and August, our analysis shows.

Headline Figures

• £1.1b Loss of Income in the UK Power Industry
• £488m Loss of Income from Wholesale Power Costs
• £649m Loss of Income in Non-Commodity Power Revenues
• Power prices in April £3.30/MWh lower
• Covid-19 Inflicted 7.5% Destruction on UK Power Demand
• Utility hedges set to lose over £35m
• UK Daily Demand Almost Back to Pre-Lockdown Levels
• Covid-19 Spared More than 3 Million Tons of Carbon

The Analysis

Through Hartree Solutions market-leading analysis we are able to model the UK power market as if Covid-19 and the subsequent consequences hadn’t occurred and compared that with the actual numbers recorded over the same period. For the first time, we can represent the true impact the measures taken to slow the spread of coronavirus has had on the UK power industry.

£1.1b Loss of Income in the UK Power Industry

The UK entered lockdown on March 23, and it remained fully in place throughout April before restrictions began to be eased in early May. This is borne out in each of the charts with April showing the biggest delta from normal operations, according to our modelling. April saw the UK power industry lose £353 million of revenue directly as an impact of Covid-19, with that figure tailing off to a £58 million difference this month.

Power prices in April £3.30/MWh lower

From a wholesale power price perspective, April is again the month which saw the largest impact, with UK power prices on average £3.30 per MWh lower than if Covid-19 hadn’t cut into demand. It is worth noting that the slump in actual wholesale prices continued into May to reach its nadir towards the end of that month with prices entering negative territory. Whilst Covid-19 was the driver of these negative periods, this is just a brief insight into what’s to come in the UK power markets in the next few years. As renewable build-outs continue to grow it will have an offsetting effect on demand similar to Covid-19. Even in an unsubsidised renewable market, we forecast strong renewable growth in the UK and as a result, these negative pricing periods will soon become the new normal.

Covid-19 Inflicted 7.5% Destruction on UK Power Demand

Power demand tracks economic activity and Britain’s service-oriented economy suffered more than any major European nation during the coronavirus lockdown. Gross domestic product plunged 20.4% in the second quarter, the most on record.

Turning to our own UK demand modelling, we calculate demand destruction of 14% in April with the effects slowly reducing to be just 2% this month. Overall, the average monthly drop in demand was 7.5%. While April is consistently the most extreme month, the charts also share the same parabola that sees August’s delta being lower than March, even though the lockdown only came into place at the back end of March.

Utility hedges set to lose over £35m

As shown above, demand came in significantly lower than expected which lead to lower power prices. Utilities, supplying end-users and industrials, will have pre-bought against ‘normal’ pre-covid demand levels only for their actual customer demand to come in on average 7.5% lower. The excess volumes purchased would then be sold back out to the market at these now lower pricing levels causing losses of over £35m.

UK Daily Demand Almost Back to Pre-Lockdown Levels

As we look at the UK demand in more detail, we can see that daily demand trended lower from early March to reach its lowest point in early July. Since then demand has steadily ticked up and this week it reaches its highest level since the impact of the lockdown began to be properly felt on the UK economy. These figures chime with the bulk of businesses allowed to reopen in early July and output consequently ramping up from that point.

Covid-19 Spared More than 3 Million Tons of Carbon

From an environmental view, the destruction in demand resulted in 3.35 million tons of carbon not produced by the generation of electricity that would otherwise have been emitted. April and May alone saw a reduction of 2 million tons, our Hartree analysis shows.

A look forward

While the impact of the first wave of Covid-19 looks to be easing with August showing the power market nearly back to the status quo, attention starts to turn to winter. Here, several unknowns make for an uncertain outlook amid the threat of a second wave of the coronavirus. To date, much of the demand loss has been during the morning peak between 7 am to 11 am, largely as a result of school closures. However, with schools scheduled to return in September and reports indicating limited evidence of widescale Covid-19 infections at schools, demand losses as a result of Covid-19 could well be muted by the time winter kicks in. Our in-house modelling accounts for these uncertain scenarios allowing us to price the impacts for our customer’s benefit.

Hartree Solutions through its market-leading modelling provides this edge to UK businesses via guaranteed discounted energy prices. By partnering with us, large energy users can typically save up to 30% on their bills as well as benefit from the Hartree Verified Emission Reduction scheme to further reduce their carbon footprint.

For more information on this article please

Get in Touch