The UK market researcher’s report, The power of flex: Rewarding smarter energy usage, outlines the importance of enabling household flexibility, which has the potential to benefit individual households, the national energy system and the environment.

The report highlights four key findings:

• Smart meter-enabled flexibility can cut peak consumption by 3GW;

• Household flexibility could deliver annual savings for consumers and the energy system of £14.1 billion/year ($17.9 billion/year) in 2040;

• Individuals engaged in flexibility could save 52% in wholesale electricity costs in 2040;

• Carbon savings increase 45% with the engagement of household flexibility.

Smart meters crucial for enabling flexibility

According to Cornwall Insight, the research focussed on the system-facing benefits that can be realised by managing and deploying the flexibility potential in household electricity use.

The flow of relevant data between different parties engaged across the energy system is essential to delivering opportunities, states the company, and smart metering infrastructure is a core component in ensuring this information is available to all relevant parties when they need it.

Using the half-hourly data from smart meters, customers can also be rewarded for reducing their use of electricity at certain times, in a way that would not be possible with a traditional meter. With a traditional meter, suppliers typically do not have visibility of consumption at different times of day, states the research, and therefore could not reward customers for making a change in their consumption pattern.

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Enabled by the presence of smart meters, household flexibility was found to support substantial reductions in peak consumption, the equivalent of four new gas-fired power stations.

Specifically, states the research, managing flexible demand technologies like EV charging, heat pump operation and solar and storage activities to market prices and system requirements equates to 3GW of peak demand on the network avoided overall in 2030.

This reduction is equivalent to saving almost £1 billion ($1.3 billion) in spending on the electricity network, including wires and other infrastructure which delivers electricity to homes.

Further savings are seen in 2040, with a 1.5GW reduction in peak demand facilitated by household flexibility, saving £1.7 billion ($2.2 billion) in avoided network upgrades and the building of new gas-fired power stations.

£14.1 billion saved by 2040

According to the study’s comparison between two scenarios, one with enabled flexibility and one without, the flexibility scenario sees consumers and the energy system benefit from £14.1 billion in savings in 2040.

This arises from three key areas, states the report:

• Lowered wholesale electricity prices accounting for £12.3 billion ($15.6 billion);
• Lowered peak demand, reducing the need to build additional power stations, delivering savings of around £1.2 billion ($1.5 billion);
• Reduced need to build additional network assets, equating to a saving of around £500 million ($634 million).

These financial savings relate to single-year scenarios modelled for 2025, 2030 and 2040. The scenarios are stand-alone and are not cumulative for the time periods between the scenarios, states the research.

Also of interest:
EU flexibility requirements to increase significantly towards 2050 finds JRC
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Looking nearer term, in 2030 the research finds overall savings of £4.6 billion ($5.8 billion) and by as soon as 2025, the ability to shift some consumption out of expensive peak periods supports wholesale power price savings, with overall power costs £21 million ($26.6 million) lower.

Flexible households could save 52% in wholesale electricity costs in 2040

According to the research, for households with EVs, heat pumps and other smart-capable assets that are managed in line with flexibility incentives, wholesale electricity costs are 52% lower in the Flexibility Scenario, saving £3755 ($4759) in 2040.

These savings take account of the additional electricity demand required to transition to electrified heating and transport and come from these households being rewarded for moving the flexible parts of their electricity consumption into cheaper periods. This means these customers won’t face additional costs from petrol and gas, states Cornwall Insight.

45% increase in carbon savings

According to the report, engagement with household flexibility results in a 45% increase in carbon savings compared to the no flexibility scenario, the equivalent of planting 630,000 trees, states the research.

By engaging with flexibility, households can have a positive environmental impact, shifting consumption from peak times when gas-fired power stations are often used to meet demand, to other times of day when renewable energy is generating more.

While the rollout has passed the halfway mark with 57% penetration for electricity and 53% for gas at the end of 2022 according to the latest government figures, Cornwall Insight suggests that with realistic installation targets for suppliers, the 100% goal is unlikely to be met within the remaining timeframe.

The analyst says this conclusion is based on the supplier installation figures and the annual tolerance levels by which they may deviate from their targets.

All suppliers are expected to achieve a target coverage of over 50% by the end of 2023, but some have higher levels.

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E Gas and Electricity has the highest target coverage for 2023, as it did also in 2022, with goals of 72% and 64% respectively.

Others with higher target coverages above 60% for 2023 are Utility Warehouse, Ovo Energy – with its increase also due to higher smart meter penetration – Shell Energy and Ecotricity.

So Energy showed a significant increase in its 2023 target coverage, rising from 33% in 2022 to 57%.

Domestic smart meter target by suppliers between 2022-23. Source: Cornwall Insights.

Cornwall Insight comments that in 2022, some suppliers missed their targets as the tolerance levels set did not consider suppliers gaining customers, including those gained through the ‘supplier of last resort’ process for customers of suppliers in insolvency. This will make reaching this year’s targets even harder.

“Smart meters have been shown to decrease bills and reduce peak time energy consumption. Additionally getting to 100% coverage would be an important milestone for other industry workstreams such as market-wide half hourly settlement, helping to support flexible energy use and facilitate the transition to net zero,” comments Mikael Mahmud, Consumer Markets Analyst at Cornwall Insight.

“However, while suppliers have made progress in increasing their smart meter rollout, given the number of variables in play, from the upfront costs through to customer willingness to install the meters, the government must weigh carefully their 100% coverage goal against the acceptable tolerance level.”

He adds that it is important to acknowledge that hitting or missing smart meter installation targets may not always be within the supplier’s control.

In the research study for Smart Energy GB, the national smart meter campaign body with responsibility for helping consumers to understand smart meters and their benefits, market intelligence company Cornwall Insight focusses on two key ways that households and their smart meters can support energy security.

According to the report, Energy Security and Smart Meters, one way is by reducing their overall energy consumption, while the other is by increasing flexibility to manage electricity consumption through the day by shifting some usage to times where demand is lower and times when more renewable generation can be used.

These support energy security by reducing the need to operate some of the country’s most carbon intensive generating stations as well as by reducing the reliance on imports and facilitating more renewable generation.

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They may also enable money saving and they contribute to emissions reduction.

Currently, a large share of the energy consumed in Great Britain comes from fossil fuels imported from other countries. While just under 40% of the electricity generated comes from renewable sources, just over 40% is generated using gas, of which more than half is imported.

British households directly consume around a third of all gas as well as around a third of the electricity each year. They contribute to the daily peaks in electricity demand, which occur on weekdays, usually between 4pm and 7pm when there is a crossover between industrial, commercial and household usage.

Cornwall Insight states that smart meters are likely to be a key enabling tool for helping customers to reduce their overall consumption or move it away from times of peak demand.

“Using the half hourly data from smart meters, customers can be rewarded for reducing their use of electricity and gas at certain times, in a way that would not be possible with a traditional meter.”

The report concludes by stating that customers can be pointed to their smart meter in-home display to help them manage their energy costs.

While there are three potential hydrogen heating solutions including hydrogen ready boilers, H₂ hybrid heating (heat pump + hydrogen boiler) and hydrogen blending in the natural gas network, the latter was identified as the likely solution for Ireland.

While the other hydrogen heating solutions are technically feasible, they are restricted by connectivity to the gas network and the availability of more efficient heating solutions such as heat pumps.

The process, which involves blending up to 20% hydrogen with natural gas in the gas network, provides a non-disruptive solution to the consumers and generates substantial CO₂ savings. We estimated that there would be ~1 TWh of hydrogen demand annually to supply the hydrogen needed in the domestic sector.

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Deva Devaraj, Modelling Analyst at Cornwall Insight, said: “The residential sector accounts for 29% of Ireland’s total CO2 emissions, which is significantly higher than the UK’s 14%. Hydrogen blending could be a tool in curbing the residential CO2 emissions in the short term as it is cheaper when compared to other low-carbon heating solutions.

“A tonne of CO₂ emissions can be avoided annually by switching just seven Irish households to 20% hydrogen blended gas, which can be a significant saving. However, only a third of the households are connected to the gas network which greatly limits the implementation of hydrogen-based solutions.

“If the Irish Government’s soon-to-be-released Hydrogen Strategy identifies hydrogen as a solution for residential decarbonisation, several hurdles need to be overcome to create confidence in progressing hydrogen in the domestic sector in Ireland. This includes assessing the Irish housing stock to determine feasibility of hydrogen solutions, ensuring government low carbon targets are met through state funding to cut the price gap between wholesale and renewable gas, and increasing hydrogen supply.” 

Find out more about the report.

Cornwall Insight’s Benchmark Power Curve, which looks at energy investment and operational decisions over a 30-year period, forecasts that from 2026 prices could become increasingly volatile, jumping by £95/MWh between the summer and winter and the seasonal differential will increase to nearly £120/MWh by 2030. 

A combination of just-in-time energy procurement, an overreliance on insecure energy imports, increased weather risks and a reduction in nuclear and coal power stations will leave the UK energy prices vulnerable to instability into the next decade, unless action is taken, the forecast suggests.

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Tom Edwards, senior modelling consultant Cornwall Insight, said: “With all the focus of the recent energy crisis being on wholesale prices for the short-term and the imminent price caps, you would be forgiven for thinking that volatile energy markets are simply a problem for the present, not the future. As our research shows, without significant changes to the way we procure, supply, and consume energy, we are likely to see many years of boom-and-bust energy pricing in the UK.

“Looking ahead to the start of the 2030s, we can see that once the nuclear power stations start to retire in greater numbers and the coal fired power stations have closed for good, there is a new period of volatile pricing coming to the UK energy market.

“Our overreliance on imported energy will also leave us vulnerable to variable pricing, with supply chain disruptions, geopolitical tensions and economics shifts, all having the potential to spill over into our market.

“Increasing the UK’s longer-term energy storage facilities could go a long way to reducing seasonal variations, helping to harness the locally generated energy from high renewable output periods for use when it’s still, cold and dark.

“It will also be important to deliver change on the demand side, with investment in energy-efficient housing and electric vehicles having the potential to considerably reduce the level of power plant capacity needed.

“Looking further ahead, policymakers must understand that the market designs of the next 20-30 years cannot rely on stable economic, geopolitical, or ecological systems. A greater focus on resilience and risk above efficiency and low costs across our economy is needed. This will include a significant role for the state, especially if they are to guide us through the enormous technical and sociological changes required to deliver the net-zero ambitions industry and government have promised to the electorate.”

The gap which is significantly smaller than the £171/year seen in December 2020, stayed stagnant between October and December 2021, further confirming predictions that the forecasted 50% rise in the Default Tariff Cap from April will impact the majority of consumers, with cheaper deals simply unavailable.

James Mabey, Analystat Cornwall Insight said: “Over the past year the gap between the Default Tariff Cap and the cheapest market deals has been slowly decreasing. Our figures from the last quarter of 2021 have shown competition between suppliers has stagnated, with ever-increasing wholesale prices leaving suppliers unable to offer competitive deals below the Ofgem set price.

“These are turbulent times for energy suppliers, only this month we saw Together Energy become the first victim of 2022, following on from nearly 30 suppliers leaving the market in 2021. The Default Tariff Cap, once a protection for customers, with increases matched by cheaper competitive deals as recently as April 2021, has now become the only option available to most, as energy companies try hard to keep their heads above water.

“It is hard to determine whether the gap between delivered costs will fall below the Default Tariff Cap once more. Our current projections show this is unlikely to happen anytime soon, with high wholesale prices showing no evidence of coming down. In the short-term the government has a number of options available through the tax and benefit system to shield consumers from the significant hikes. However, if we want to get a handle on this ever-volatile market, some serious long-term decisions on the future of the Default Tariff Cap, pricing in the wholesale market and where the UK sources its energy from will need to be made.”

The government has committed to increasing low carbon power generation, and with a 2050 target date for net-zero, a significant increase on current production levels will be needed. Despite relatively high procurement expectations, tough competition between developers (which will weigh on bid prices) means many are exploring other routes into the market in case they prove more attractive.

Auctions will happen later this year with applicants bidding for funding from one of 3 pots. Pot 1, newly reinstated established technologies including onshore wind and solar, has a 5GW capacity cap. Cornwall Insight’s own analysis has shown there is over 25GW of Pot 1 technologies in the pipeline; however, eligibility criteria for the auction including a confirmed grid connection, as well as planning permission being granted, has left much of this unable to apply in this round.

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Pot 2 is earmarked for less established technologies with ringfenced budgets for both floating offshore wind and tidal stream technologies, whilst offshore wind is separate in Pot 3. With no capacity cap, a £200mn budget, and amid a government target of 40GW of offshore wind by 2030, the Pot 3 auction is poised to secure the largest amount of capacity. However, with Cornwall Insight’s own Renewable Pipeline Tracker estimating upwards of 65GW of offshore wind is in development, developers without both planning and grid connections will be hoping the ambition of future allocation rounds meet or exceeds that of AR4.

Tim Dixon, Lead Analyst at Cornwall Insight, said: “With the applications for Contracts for Difference now closed, developers will be turning their attention to the bidding process. A more inclusive funding round from the government has also come with high levels of competition, likely to push down bids. Newly reinstated wind and solar is practically certain to have clearing prices lower than the last auction in 2015, whilst it will be interesting to see if previous record low bids for offshore wind will be broken. The added ongoing reforms to network charging regimes complicate things even further, and the uncertainty about future costs and revenues will also no doubt affect the price of bids.

“Developers will need to bid competitively in order to secure a contract. Many will be pushed to seek alternative routes to market, whether this is selling electricity subsidy-free to a utility via a long-term power purchase agreement (PPA), or to an end-user via a Corporate PPA. Some may even hedge their capacity across more than one route to market.”

The GB household supply market has been on a journey of customer engagement since privatisation.

Market intervention and increasing rates of competition have pushed consumers to engage in supplier switching in the last 20 years. However, while we have seen an almost doubling of the electricity switching rate (to 20% annually) over the last decade, we continue to talk about “weak consumer response”.

The first major market intervention was Ofgem’s Energy Supply Probe, which found that competition was not working in customers’ best interests, partly driven by a lack of engagement and “poor decision making by consumers”.

This article was originally published in Smart Energy International Issue 4-2021.

Read the mobile-friendly digital magazine or subscribe to receive a print copy

The Energy Supply Probe remedies first saw the light of day in 2009 and aimed to improve the conduct of sales and marketing activities and the information provided to consumers.

They were tabled at a time when the annual switching rate was similar to today’s at about 20%, but there were concerns as to the barriers in making “effective choices” – a feature still relevant in today’s market. Just four years later, and with switching rates on the decline, further measures were introduced through the Retail Market Review. This time, amongst other measures, a maximum limit was enforced on the number of tariffs that suppliers could offer to limit customer confusion and price differentiation.

New measures

Over the following years, the conversation around engagement became more nuanced, as the baton was picked up by the Competition and Markets Authority (CMA). In its Energy Market Investigation 2014-2016, the CMA highlighted disengagement in the retail markets.

It attached “particular significance to the fact that [gains from switching] are available at such levels to customers for domestic gas and electricity”, and yet those savings went unexploited. The issue was carried forward by the then Business Secretary Greg Clark, introducing the Domestic Gas and Electricity Tariff Cap in 2018.

Today, measures of engagement and switching are among the indicators used by the regulator to determine whether the cap should be removed.

Following the introduction of the new measures and a concurrent step back from doorstep sales by all the then Big Six, switching rates dropped to around 13% in 2014.

This trend was then reversed and switching hit historic highs in 2019 of 22% in electricity (see Figure 1), following a steady upward trajectory with some seasonal variation.

Making the switch

So how has switching fared in the past year?

Unsurprising in the COVID-19 pandemic, the monthly switching figures trended downwards, reflecting several factors, including a step back from face-to-face sales during lockdown periods and the mixed impact of the default tariff cap.

The default tariff cap has seen electricity switching peak when the cap has been adjusted in price (April and October).

According to Ofgem’s Consumer Survey 2020, 30% of those engaged in the market were prompted to do so by receiving a price increase notification from their supplier.

But the cap has had other unintended consequences in the switching market. During the winter period of 2020/21, switching rates were lower than usual. The default tariff cap had fallen by £84 to £1,042, and the level of savings made by switching from a cap level tariff to the cheapest tariff in the market had halved to just over £200 from a peak of more than £400. Despite the fall in the cap, the average price of the cheapest direct debit tariff from each supplier across the market had been rising.

These trends illustrate the counter-intuitive nature of the cap due to the lags in its wholesale price setting. The 1 October 2020 cap was based on wholesale prices from February to July 2020, when they were at the trough of their COVID-19 slump.

Subsequently, they rebounded, taking marketled fixed tariffs with them. Political messages around the cap continue to be led by its perceived money-saving capabilities, despite capped prices remaining some way above the market and potentially disincentivising at least some of those teetering on the edge of engagement from bothering.

Prices on the rise

On 6 August 2021, Ofgem revised the price cap for October 2021, increasing the level by £139 to £1,277 and reflecting the sharp rise in wholesale gas and electricity markets due largely to the economic rebound in response to an easing of lockdown conditions.
The jump in wholesale prices and the expected rise in the price will have a clear and material impact on domestic bills. It would be expected that due to this the coming winter may lead to a resurgence of engagement by customers as they look to switch suppliers in search of lower-cost alternatives.

However, despite these expectations, the record highs in wholesale prices have resulted in the removal of many tariffs from the market, with some suppliers stopping customer onboarding completely. This seems certain to reduce the switching rates in the period up to October, a time when switches are historically high.

Customers on the move

The latest electricity switching figures from Energy UK showed under 3 million customers switched electricity suppliers in the first half of 2021, a 1% increase on the same period of 2020 and a 0.02% fall in 2019. June saw a 2.6% fall in switching compared to June 2020, with 433,868 switches made during the month (Figure 1). As a result, the annualised domestic electricity switching rate has fallen below 20% (19.6%), similar to that recorded in 2018.

As to where these customers are moving to, half of the domestic electricity switches were between large suppliers (Figure 2), and 30% were customers switching from large to small and medium suppliers (SaMS) (118,042).

Due to high wholesale prices and suppliers exiting the market, the tariffs available to customers have been significantly reduced.
However, the switching figures do not currently show this impact, with a lag in contract offer and starting the industry process.

Mix it up

Looking across the supplier groups, some suppliers have felt the impact of consumers switching away more than the others, for SaMS churn rose alongside the increase in new competitors until mid-2017 when it began to decline. Churn for this group is now around 30% but has fallen from a peak of almost 33% at the start of 2020. Large suppliers have also seen increases in the churn rate, up from 12.5% in 2015 to around 18% recently.

It is expected that there will be a higher level of customers switching away from SaMS, as they do not have a legacy customer base. Alongside this, the very nature of the customers signed to smaller suppliers – they have had to make an active switch at least once – demonstrates some market engagement that is likely to be repeated.

The variation of customer churn across the market is due to the significant number of newer suppliers growing their customer base relying on one-year fixed-rate tariffs.

As a result, their churn will be limited until the customers reach their renewal period.

However, churn is not limited to these suppliers, with churn varying between customer groups and demographics as they all have varying tendencies to engage with the market. For example: End of a fixed-term tariff, increase in price, house move, looking for a different choice of offering, recommendation from a friend or poor customer service experience.

Round and round Engagement will continue to be a big focus going forward, taking a front and center role in Ofgem’s Retail Market Strategy for the 2020s.

Here, the regulator accepts not everyone will engage and plans for it through measures like opt-in and opt-out switching, which have been trialled during the last year.

However, high customer churn creates a challenge for all suppliers, not just SaMS, looking to maintain and build a customer portfolio. Trying to mitigate churn in an environment where suppliers are being hit from all sides is undoubtedly difficult, but managing these risks will be increasingly important to maintain and grow a business, as the cost of customer acquisition can be high.

About the author

Anna Moss is Head of Consumer Markets at Cornwall Insight. Moss manages and develops the research in the supply sector, supporting the analytical team in their day-to-day activities. She works with a range of market participants across the domestic and non-domestic sectors, including energy suppliers, providing support in analysing key developments in the supply market.

At the start of the year, we had 47 domestic energy suppliers – 5 large, 12 medium, and 30 small. Today, that has fallen by over half with only 25 suppliers remaining in the market.

So far, the majority of customers have been moved to larger energy suppliers, growing the market share of the large supplier group from 68.5% at the start of the year to 70.1% today.

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Anna Moss, Head of Consumer Markets at Cornwall Insight, said: ”Suppliers are likely to face tough times ahead. Credit calls on suppliers for electricity balancing are due to increase markedly. The Credit Assessment Price (CAP) will increase further to £259/MWh on 4 November – a record high and the tenth increase in the CAP in 2021.

“This is further compounded by high futures prices for the remainder of winter, consistently over £230/MWh for monthly baseload power and 240p/th for monthly NBP gas on 1 October. As a result, trading arrangements with wholesale trading parties are critical to the retail parties’ survival to reduce exposure to uncapped imbalance prices.

“Terms which the suppliers will find acceptable may not be forthcoming as wholesale counterparties will be concerned about the long-term viability of businesses whose input cost is higher than their incoming revenue. Those without longer-term deals in place may be forced to pay up-front, offer additional collateral (either in cash or equity), or buy on spot markets, increasing pressure on cash flow management.

“The very high wholesale prices have caused significant distress even before winter begins and how suppliers fare is in the hands of wholesale trading parties, and how suppliers can manage their costs through the winter months ahead.”

The insight paper examines industries that currently consume hydrogen or have the potential to increase the use of low-carbon hydrogen.

Key findings of the report

• UK industry could see a low-carbon hydrogen demand of ~10TWh in 2030
• This could increase to 37TWh by 2050
• The largest demand (36TWh) is expected from high-temperature industrial processes hydrogen will substitute natural gas and other fossil fuels.

Total cost

Using the CAPEX values for electrolysers and offshore wind from the Department for Business, Energy & Industrial Strategy (BEIS) and International Energy Agency (IEA), we estimate the investment to establish this infrastructure at ~£23bn

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Deva Devaraj, Modelling Analyst at Cornwall Insight, said: “UK industry, while contributing £331bn towards GDP (17%), also accounts for 18% of carbon emissions, which can be reduced via multiple decarbonisation pathways. For example, industrial processes using fossil-based electricity and heat generation can be switched to renewable sources, and processes requiring fossil fuels for heat generation can also be electrified. However, there is a substantial role for hydrogen in industrial decarbonisation.

“Hydrogen is versatile; it can be used as a feedstock, reducing agent, and to generate heat. Using low-carbon hydrogen in industries would be a catalyst to scale up its production and lead to hydrogen technology adoption in other end-use sectors.

“It should be noted that the low carbon hydrogen intake would be dictated by the rate of decarbonisation and their production capacity. Therefore, even though chemical manufacturers account for less than 1% of the total hydrogen demand, they are definitive offtakers with very little variability.

“The industrial heat process exhibits the greatest hydrogen demand potential (98%); it is greatly influenced by the penetration rate of low carbon hydrogen, thereby subjected to high variability.”

Find out more about the report.

In fact, the difference between the ten cheapest tariffs and the current default energy tariff cap for September 2021 stands at just £11/year, compared to £291/year for September 2020. This is the lowest level this gap has fallen to since the introduction of the price cap in January 2019.

Figure 1 compares the default tariff cap and the average of the ten cheapest available tariffs on the market, showing a sharp increase in tariff prices since July.

James Mabey, Analyst at Cornwall Insight, said: “The record-high wholesale prices and the resulting energy crisis has no doubt taken its toll on the energy tariffs available to customers, with domestic tariffs seeing substantial price increases over the summer months.

“For example, the cheapest ten tariffs on the market in April averaged £906/year for a typical dual fuel user, while the equivalent figure stands at £1,127/year as of 27 September, an increase of 24.3%. While the cheapest tariff available on the market has remained above £1,000/year for the last six weeks.

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“This reduction in potential savings for customers has caused the level of customer switching to reduce significantly. In fact, Electralink’s latest switching statistics found that 399,000 customers changed supplier in August 2021, a 24.7% decrease on August 2019 and the lowest figures seen in August since 2016.

“Usually, a rise in the default tariff cap by Ofgem would widen the gap between the cap and the lowest deals making switching more worthwhile. However, with wholesale prices remaining well above typical levels, it is not clear that the savings gap will reopen.

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“This is compounded by the fact that many tariffs have been removed from the market. The drastic reduction in the number of tariffs available, along with a handful of suppliers stopping customer onboarding completely, suggests that the domestic switching landscape will retain a low level of switching until the gap between delivered costs falls below the price cap once more. This will either be when the price cap is amended in April next year or the current highs in the wholesale market abate.”

How the crisis is affecting investors?

• The large swing in prices catching companies out is unnerving
• Highlights long-term market forecasting tools only focus on general directions and trend-lines
• Market shocks in adjacent segments of the value chain can lead to hiatus in decision making
• How governments and regulators react to global commodity-driven events signals how much implied political protection risk-takers will receive in markets exposed to these risks.

What policymakers can do?

• Continue work on policy mechanisms that remove volatile commodity risks – particularly for flexibility solutions
• Investigate the comprehensive impact of the current situation on the wider energy value chain
• Opt for a case-by-case assessment of why failure has happened rather than a “bad companies fail” approach

Daniel Atzori, Research Partner at Cornwall Insight, said: “The current crisis serves as a sobering reminder of the danger of being exposed to material elements of merchant risk. It reminds people that they can be blind-sided by extraordinary and relatively short-term deviations to their modelled trend line.

“This is a problem for any investor – like a pension fund or a debt provider – who wants a relatively stable return and regular capital repayments. The trouble is that these provide the cheapest forms of capital and have the most money to invest in energy infrastructure.

“To protect against this, the government needs to continue to work on policy mechanisms that remove volatile commodity risk from the energy investment equation. For example, the Contracts for Difference (CfD) scheme has been highly effective in mobilising cheap capital precisely because it takes this risk off the table. A similar mindset needs to be brought to bear on delivering genuinely investable signals in the short term, and long-term flexibility solutions, which recent events show are of paramount importance.

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“Market shocks prompt everyone about to put capital at risk “on notice”. In the worst case, it could lead people to pause whilst risk is crystalised in full across interconnected systems, and the full value chain impacts are known.

“To address this, the government could urgently investigate the comprehensive impact of the current situation on the wider energy (and wider economic) value chain and publish this analysis, including any mitigating actions to insert firebreaks or ring fences to contain fall-out and risks. This should be an immediate priority.

“How governments and regulators react to global commodity-driven events signals how much implied political protection risk-takers will receive in markets exposed to these risks. In making capital investments where certain risks are unhedgeable, actors likely take a view on whether governments would leave their assets high, dry, and stranded.

“If politicians take the view that enterprises should be allowed to fail when exposed to costs outside of their reasonable control, then general faith in “soft political” support starts to be undermined. Governments that wash hands of their private sector partners can find confidence in them is damaged generally.

“To negate this, the government may want to carefully consider whether maintaining the “bad companies fail” general characterisation of the present situation, and a “one-sized” solution is advisable. Arguably, a more case-by-case assessment of why failure has happened and how best to intervene would show that policymakers appreciate that risk-taking and risk management are complex in a complex market.

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“All this matters, given net-zero is going to require billions of pounds of capital in infrastructure. The success of the UK model to date has been the way that it has encouraged risk-taking, with great policies intelligently leveraging private sector investors in a fashion that fairly shares risks and rewards. It hasn’t been all plain sailing, but the thriving and dynamic investment world that has developed around energy infrastructure in the UK is a testament to its broadly positive effect.

This is a triumph of the last twenty years which should be protected from the vagaries of the next six months. Some of the suggestions we have positioned are not straightforward and demand some in-depth work. And like gas, time is another scarce commodity, given interventions need to happen quickly.”

What is causing energy prices to increase and how can flexible energy help to avoid such increases to happen again?

Dan Starman, head of assets and infrastructure at UK research firm Cornwall Insight, said: “Many of the price increases now are driven by underlying market fundamentals such as high gas and carbon prices, as well as demand recovery from COVID-19. To counter these factors, we would need long-term flexibility, such as long-range seasonal gas storage. This can act to suppress prices if summer seasonal prices are at a discount to winter and provided excess gas is available to inject into storage.”

In addition to the high gas and carbon prices, the failure to fill up gas reserves by the majority of European economies including the UK following heavy usage last winter can be blamed for the spike in gas prices, according to media reports. Due to supply chain disruptions caused by the pandemic, utilities have failed to secure enough capacity to meet the growing energy demand that has been witnessed in the past six months as economies re-opened with CODIV-19 restrictions being lifted. In an interview with Bloomberg, Francesco Starace, the CEO of Italian utility Enel, said the increase in natural gas prices is a result of Russia providing less than normal to the European market.

With the majority of natural gas used in the UK imported from Norway, Qatar, and the US, would a backlog from Russia result in such increases in energy prices? One could argue.

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When asked by the BBC about whether the UK is facing shortages in natural gas, UK Energy Secretary Kwasi Kwarteng said it was alarmist and misguided to start talking about gas shortages. He said: “There is no question of the lights going out, of people being unable to heat their homes. There will be no three-day working week or a throwback to the 1970s.”

COP26 president Alok Sharma, added that “We do not see risks of supplies right now and prices are being protected.” He said Ofgem’s price cap would help avoid a further increase in consumer gas prices. The COP26 president made the announcement following reports that the UK government is considering providing utilities with loans to survive the market challenges as well as removing taxes for natural gas imports.

However, some four small utility companies in the UK have been reported to have ceased operations in the past month due to a lack of funds to purchase natural gas at high wholesale prices.

Energy management firm Kaluza and demand-side management solutions company Flexitricity states that demand response is much-needed for the UK energy system to alleviate constraints that have recently caused prices to reach as high as £4,000 ($5,400) per MWh in the Balancing Mechanism.

Where is the UK sourcing flexible energy and how?

Starman explains: “Much of the flexibility we have is very short in duration – operating on within-day cycles, for example, batteries and to some extent pumped storage. More flexibility here could have reduced some of the significant spreads between peak and off-peak prices we have seen over recent weeks, although it would have done little to suppress longer-term prices. Longer-term flexibility, and any shortfall in generation margin, are typically provided by assets that are fossil fuel-fired (gas being the main source in Great Britain). Replacing these marginal generators will present a significant technical challenge.

“Long-duration storage, such as pumped storage or hydrogen, is not well supported through existing mechanisms either because of their first-of-a-kind nature and increased risk or long-lead times and high construction costs. Changing mechanisms such as the Contracts for Difference (CfD) or Capacity Market to reflect better these projects requirements should be considered. Finally, it is worth noting BEIS has a long duration storage competition in progress. We have already seen fertiliser factors shut off demand in response to high prices, and we may see more of this if prices continue to remain high. The future energy system will likely require more flexibility from all demand users.“

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What role will energy flexibility play in helping the UK achieve its net-zero goals?

“Net-zero is most cost-effectively achieved with renewable power sources, and as such, there is a high level of flexibility required to manage the intermittency of these power sources,” said Starman. “Therefore there will be increased future reliance on all kinds of storage (especially lithium-ion battery storage and pumped storage) interconnection, demand Side Response, and Carbon Capture Usage and Storage on thermal power stations.”

To conclude, the role of energy flexibility will continue to increase in stabilising energy markets and simplifying utility grid resilience efforts as the move to low-carbon energy-based grid networks intensifies.

The Benchmark power curve report states that electric vehicles will contribute an additional 71.6TWh of energy capacity by 2040. This is a 25% increase of current annual demand which stands at 299TWh (excluding losses).

The electrification of the economy (electric vehicles & heat pumps) and use of green hydrogen as an energy carrier, all increase demand from 298TWh in 2021-22 to 628.4TWh in the Central Scenario (see figure 1) by 2040 and up to 668.2TWh in the High Scenario, according to the study.

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Tom Edwards, a senior modeller at Cornwall Insight, said: “EVs are widely seen as crucial in reducing emissions to meet net-zero. However, the magnitude of the impact that the technology will have on the electricity system should not be underestimated. If EVs increase according to the National Grid’s Future Energy Scenarios (FES) Leading the Way scenario, the increase in demand for electricity will be substantial.

“However, EVs have the potential to offer the system considerable flexible vehicle-to-grid (V2G) discharging and smart charging, which reduces the level of investment needed in flexible power supply.

“At the same time, greater flexibility may be needed if consumers were to charge whenever it is convenient, and with the wide deployment of EVs needed to meet net-zero, it is clear that this would currently not be possible.

“The electrification of transport remains a significant challenge, particularly if the current market design remains the same. However, to sustain such a growth in demand, it is likely that the market design will need to change to better support the net-zero objectives.”

This is according to energy companies and a new report released by research firm Cornwall Insights.

Cornwall Insights states that with gas prices currently sitting at 134.1% above the five-year rolling average, price increases will continue due to a decrease in the supply of natural gas (although short-term) and in storage levels.

The previous winter left the majority of natural gas reserves in Europe empty. Since then, the majority of these reserves have not been filled due to disruptions within the supply chain from the pandemic.

This will be coupled with an increase in demand as COVID-19 restrictions are lifted and many European economies reopen and people return to the office. Moreover, building occupants will increase their usage as they seek to warm themselves.

Russia, the biggest producer of gas to the European market has decreased its supply to cater for local demand.

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Joe Camish, Analyst at Cornwall Insight, said: “We have not seen a typical summer for gas prices with the markets seeing prices that we would expect to see in winter. In fact, 18 August saw the day-ahead gas price reach 117.4p/th, the highest price point for this contact since 1 March 2018, during the Beast from the East extreme weather event. 

“These high prices have been caused by historically low gas inventories and efforts to restore stock levels hampered by several factors” including lockdown restrictions.

Carmish, added: “This was compounded by periods of weak wind output, a weaker pipeline from the North Sea gas field due to outages and prolonged maintenance at British and Norwegian sites.” The North Sea gas pipeline transports natural gas from Norway to the United Kingdom.

“Elsewhere, GB and other European nations have struggled to attract LNG cargo with similar conditions occurring in Asian markets. This has led to LNG prices reaching a six-month high, and as a result, many cargoes are heading to more lucrative Asian markets.”

In an interview with Bloomberg, Francesco Starace, the CEO of Italian utility Enel, said: “High gas prices today are a problem for Europe.”

As a result of the continued increase in the prices of gas across Europe, electricity prices also climbed and are expected to continue to increase throughout the winter.

Camish, added: “With gas still at ~40% of the UK power generation mix, increases in the gas market have ultimately fed through to the equivalent power contracts. As a result, we have seen consistent rises since the start of the year, with the day-ahead power contract averaging £108.2/MWh in August, 77.5% higher than the five-year average.”

In Germany, electricity prices have reached their highest level since 2008. Whilst 14 EU member countries saw a decrease in electricity prices in the first half of 2020, Germany recorded the highest increase (EUR 0.30 per kWh) within the household consumer segment, according to the European Commission.

Camish reiterated: “Looking ahead, with storage levels low, LNG spot prices at such high levels and with high Asian demand, prices are expected to remain above the long term average. However, maintenance issues have been resolved in the North Sea, and the anticipated Nord Steam 2 could commence flows in mid-September, helping to alleviate some of the supply pressures.”

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Not only is consolidation expected to continue in the near term, but it will also be combined with a major shift in business models that is set to define the market further. A detailed analysis of the energy supply market was conducted for the report including interviews with leading stakeholders.

Key findings of the report:

• Suppliers will need to diversify their revenue streams to gain sufficient margins to reinvest in their business. Those that fail to go beyond selling energy will not be sustainable in the long term.
• The role of prosumers (households that generate and sell back energy to the grid) in a future energy system will be increasingly important as the heat and transport sectors are electrified, adding to electricity demand.
• Further market exits can be expected through both Ofgem’s Supplier of Last Resort (SoLR) mechanism and mergers and acquisitions.

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Change in supplier offerings

Suppliers that do not focus solely on price but engage consumers on a broader service platform will be well placed to succeed. However, this requires upfront risk capital to be put to work and patience from those that invest in it before returns follow. Consequently, fewer players will win, with earlier adopters/movers acting as magnets for the significant yet finite number of investors. This is a dramatic shift from relatively frictionless and cheap “price and volume” market entry models we saw from the middle of the last decade, with the competitive pressure in the market now seeing these companies most vulnerable to failure.

Tim Jackson-Smith, corporate partner at Shoosmtihs, said: “It has been great to work with Cornwall Insight to explore the dynamics at play and gain a better understanding of what is driving change and the M&A activity we have been seeing. 

“The fact that suppliers are operating within legally enshrined climate change targets means that they, along with everyone else, are going to need to play their part to achieve net zero by 2050. This will undoubtedly shape how suppliers anticipate and respond to the continuing evolution in the market now and in the future, and this market insight will help Shoosmiths better understand how to serve those changing client needs.”

Emma Bill, a lead research analyst at Cornwall Insight, adds: “The UK energy retail market is undergoing significant restructuring, and with the current landscape of rising energy costs and looming supply payment deadlines, there is a real possibility of further supplier exits later this year.

“There is a changing of the guard occurring in the supplier market, and for those that remain in the sector, it is critical to differentiate on more than just price. In particular, those who engage and empower consumers through technology are likely to thrive.  Therefore, suppliers who make this transition early to support a high-quality consumer engagement and reach net-zero targets will benefit.

“However, this will require significant financial support, and those who are unable to secure this or diversify enough will be unlikely to remain in the market.”

This percentage would be even higher if green tariffs from suppliers that also offer standard non-green also or ‘brown’ supply were included. The below graph highlights the growth in green supply.

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Oliver Archer, a senior analyst at Cornwall Insight, said: “This boom in green tariffs is in part being driven by consumers doing their bit to reach net-zero with renewable credentials increasingly being factored into decision making when switching energy providers. For example, Ofgem’s Consumer Perceptions of the Energy Market survey showed that in Q119, 9% of respondents gave green energy as the main reason for switching supplier. In Q420, this had risen to 19%.  

“However, switching trends do not tell the whole story. Nearly 80% of the increase seen between 2019 and 2021 can be attributed to a few large suppliers re-branding as 100% green through 2019 and 2020. It is also difficult to tease out the relative contributions of price, service, and renewable tariffs to the fast growth of green challenger brands such as Octopus Energy and Bulb.

“The low price of REGOs has made it possible to be labelled a green supplier without heavily sacrificing on the main tool for attracting new customers – cheap tariffs. As a result, more than half the suppliers in the market are now green.

“Critics would say the current system makes it hard for consumers to understand which suppliers provide truly additional support for green generation. As green tariffs become more ubiquitous, the government plans to consult this year on reforms to give consumers more transparent information, including quantifying the additional benefit of tariffs marketed as green.”

Funded through customer electricity bills

The costs of decarbonising the power system have mainly been funded through consumers’ electricity bills. In 2020-21 these costs amounted to £10 billion ($14.1 billion) with the expectation that support for low-carbon generation will continue to be necessary.

To maintain a trajectory to net zero carbon emissions by 2050, the UK needs to decarbonise its heat network. That will mean switching away from heating our homes with gas to an alternative low carbon source.

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Policy decisions will need to be made around the scale, timing, cost and means of supporting this transition. The report considers the reduction in the retail price of electricity and outlines three options for policy cost reallocation:

• A transition to or cost partitioning with the gas bill
• A transition to general taxation
• Recovery as a fixed “residual cost”

The paper notes a range of risks and opportunities with each approach and states that policy cost recovery is only part of a suite of tools that policymakers can use to hit carbon budgets.

Dan Starman, Lead Consultant at Cornwall Insight, said: “Given the scale of the challenge that net zero presents, the speed of decarbonisation required to reach the target, and the fundamental shift needed in both the technologies consumers use and how they use them, policymakers will likely need to consider all available tools at their disposal to support the net zero transition.

“There are very good reasons that policy costs were initially applied to electricity bills. However, the underlying economics of powering heat with electricity vs the counterfactual fuel of gas means the government should consider reform in the area.  

“Current cost recovery mechanisms act as a significant disincentive to electrify and transition to newer low-carbon heating technologies. Driving the right financial incentives for consumers to choose low carbon options while managing the impact on the public purse will be key, and this is doubly important in a post-COVID-19 world.

“Inaction would result in a lost opportunity for the government to pull another policy lever to support the net zero transition. Hence, we believe policymakers should utilise an assessment-based framework to disentangle policy costs and the electricity bill.

“There are a range of wider benefits that can be achieved through reform in the area, including simplifying the retail landscape, alignment with the regulatory desire to reform the Supplier Hub and reducing the impact of supplier failures.

“We believe removing these costs from the electricity bill will support the government in meeting its targets, resulting in stronger electricity pricing signals, and supporting consumers in making more appropriate choices for the net-zero transition.

Find out more about the whitepaper.

The study states that 40.6GW of the renewable energy and storage projects are classified with a development status of ‘scoping’. This is where sites are yet to submit a planning application but have a grid connection option confirmed through National Grid’s Transmission Entry Capacity (TEC) Register. These scoping sites have been added to Cornwall Insight’s analysis to account for the major increase in activity seen for early-stage projects, particularly offshore wind sites.

The research firm’s Renewables Pipeline Tracker has found that a further 13.5 GW of pipeline capacity are currently classified as “application submitted” and awaiting planning approval, capacity classified as “awaiting construction” totals 24.5 GW. Capacity classified as “under construction” stands at 7.8 GW.

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Lucy Dolton, analyst at Cornwall Insight, said: “We are currently seeing increased activity in sites classified as scoping, with recent developments in the offshore leasing rounds being undertaken by the Crown Estate and Crown Estate Scotland.

“As such, Cornwall Insight’s Renewables Pipeline Tracker now accounts for these sites in its analysis, helping us assess the potential trends from the next Scotwind Leasing round and future Contracts for Difference (CfD) Allocation Rounds.

“While the auction parameters are yet to be announced, the fourth Allocation Round (AR4) of the CfD scheme is firmly on the horizon in 2021. With AR4 set to offer the first Pot 1 auction since 2015, it is also unsurprising to see an increase in the number of onshore wind and solar PV sites entering the development pipeline with the aim of accessing the CfD.”

Learn more about the study findings here.

This phenomenal growth in output has significantly displaced fossil generation – especially gas. In the evenings (5 PM – 11.30 PM) – outside solar hours – gas contributed 5% to the state’s generation mix in 2020, whilst wind made up 14%. For the same time-of-day period in 2017, wind was 6% against gas at 9%.

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Lumi Adisa, head of energy market analytics at Cornwall Insight Australia, said: “Whilst the displacement of gas by wind at night time is not particularly surprising, the shape of wind output in Victoria displays a unique characteristic; an afternoon bump. Victoria is the only state to show this remarkable shape and have wind contribute more to the generation mix in the afternoons (14%) than in the morning (13%).

“In addition, the overnight average wind contribution to the generation mix in the state (15%) was only 1% higher than the afternoon contribution (14%). Overall, wind in Victoria – specifically from western Victoria – has the most complementary market impact to solar in the NEM, making renewables in Victoria particularly impactful.

“This outstanding shape has also made wind in Victoria play a vital role in replacing the afternoon contribution (23%) from the retired Hazelwood power station and further impacting thermal generation.

“In 2017, gas and wind equally contributed an average of 8% to the generation mix in the afternoon. Fast forward to 2020, gas has dropped to 3% whilst wind has increased its afternoon share to 14%.

“These unique trends have fundamental impacts across the broader market through time-of-day pricing, constraints, and arbitrage value throughout the day.”

When asked whether we need an energy system architect or is it better to leave the initiative to the market? 75% of the 127 opted for “energy system architect”, with only 25% choosing “the market” option.

Gareth Miller, CEO of Cornwall Insight, said: “This poll highlights the need for clarity and consistency in terms of the direction of travel that the market alone is not capable of delivering. However, before the sector creates more governance layers and institutional responsibility, the industry needs to assess what it is looking to solve.

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“Those favouring institutional creation suggest that this is necessary because the pursuit of net-zero requires “whole systems thinking”. This will need the combination of deep expertise and a long term and non-party political perspective to unlock. This assumes that efficient whole systems outcomes require an “intelligent designer” or a group of such actors working together to define the roadmap to net zero.

“However, does our experience of innovation, ingenuity and evolution in other complex systems really bear this out? Or are we being seduced by the idea of institutionalising innovation or transformation because it makes the monumental task feel less daunting?

“There is some doubt that a new institution is the best way to achieve low-carbon innovation in the consumers’ interest. Such an institution risks setting too much regulation and will end up stifling innovation in the market.

“Instead, would the courageous move now be to reduce the number of institutions and rollback the regulation’s frontiers? Perhaps the focus should be on sharpening the economic costs for emissions and the incentives for low-carbon solutions and then focus on reducing complexity and increasing transparency and accessibility of both regulation and industry data.

“This institutional and regulatory “decluttering” and unleashing the power of data would make it easier for businesses who are delivering exceptional outcomes to consumers through digital platforms to enter the market.

“In this world, we would accept that once the policy ambition is set, as it has been by net zero, regulation and institutions should ensure acceptable levels of equity and fairness, efficient system operation, and maximising competition and innovation.

“Perhaps we would be better advised to start the conversation on regulatory and governance reform now, rather than default directly to adding to the institutional complexity that already characterises the sector just because it makes us feel like we have more control.”

The survey has seen a 15% and 14% rise in reported average REGO values for Fuel Mix Disclosure (FMD) 2020-21 and 2021-22, to £0.20/REGO and £0.32/REGO respectively.

The independent survey of 59 organisations across the industry ran from 18 January to 3 February. It also revealed that 31% of respondents felt that consumer demand for REGO-backed supply products is increasing, with demand changes being driven by the SME and domestic markets.

The below graph compares the average response for current trading values for REGOs over Fuel Mix Disclosure (FMD) years 2020-21 and 2021-22 from our past five surveys.

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Commenting on the survey results, Luke Ansell, Analyst at Cornwall Insight, said: “Pre-COVID, respondents to our December 2019 survey, reported average REGO prices of £0.66/REGO for FMD 2020-21 and £0.72/REGO for FMD 2021-22. The pandemic then saw demand for REGOs fall due to an unprecedented drop in electricity demand, while renewables generation continued to rise as more projects were commissioned, increasing the supply of REGOs. As a result, the October 2020 survey showed the average reported REGO trading price had dropped by 74% and 61% for FMD 2020-21 and FMD 2021-22, respectively.

“Following the previous sentiment expecting a rise in prices, our latest survey shows REGO prices have now slightly risen since our October 2020 view. This positive sentiment for REGOs is set to continue.

“REGO values continue to vary by technology, with unfuelled technologies (e.g. wind, solar and hydro) commanding higher REGO values than for fuelled technologies (e.g. landfill gas, biomass and energy from waste). This has been a consistent trend across the surveys, with greater demand for REGO certificates from unfuelled technologies.

“Some respondents to the survey also suggested that REGO market reform is necessary. With calls for more specific reforms, including: REGOs to only be given to unsubsidised renewables generation, a greater focus on additionality requirements when presenting REGOs for FMD and improved transparency to consumers.

“Green certificate markets have been the subject of much debate, amid the rise in demand for renewable supply tariffs in parallel to stricter national emissions reduction targets, and amid the uncertainty of EU GoO treatment with Brexit. Nonetheless, green certificate markets are set to continue to develop.”

The below graph presents the number of units active in the BM — defined as having had any volumes accepted to date — from these technology types, along with the total capacity of such units.

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Joe Camish, an analyst at Cornwall Insight, said: “The greatest new entrant growth over the past year has come from aggregated units, which has more than doubled from January 2020 levels of 20 to 45 units in January 2021. As a result, the total active capacity from aggregated units has risen by 87.4% to 1.7GW.

“A similar trend has been seen for gas reciprocating engines, with 19 units now having been active in the BM (excluding some that may form part of an aggregated unit), up from 9 the previous year. This has led to a significant increase in active capacity, leaping 143.4% to a total of 455MW. On the battery front, the BM has now had a total of seven units active to date (excluding some potential batteries within aggregated units), up from three in January 2020

“This trend of new entry is likely to continue throughout 2021, as new units, often with Capacity Market contracts, commission. Added to this, a greater number of parties that trade the power from flexible assets are enabling themselves to be active in the BM, often using the ESO’s Wider Access mechanisms to aid entry.

“One of the most recent measures implemented to aid entry was the launch of the wider access application programming interface (API), which launched back in September 2020. This web-based route provides an alternative to fixed-line connections, aiming to be simpler and more cost-effective. Tesla Motors were the first party to opt for the API route to market for its Holes Bay battery unit (7.1MW) in September 2020.

“Another trend amongst new entrants is the registration of Virtual Lead Parties (VLPs). A VLP is a new type of BSC Party that can register secondary Balancing Mechanism Units (BMUs) that can only trade volumes in the BM without needing to be a licensed electricity supplier or licensed generator. Six participants have now registered as VLPs, including Flexitricity, Habitat Energy, Cenergise, Adela Energy, Erova and Gazprom. While not all of these parties have had volumes accepted in the BM yet, it represents an intention to compete and enter new assets into this market.”

The below graph shows this trend.

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George Wong, modelling consultant at Cornwall Insight Australia, said: “Compared to last January, the largest decrease in the monthly average price of $119.24 can be seen in Victoria. The high price from January last year is largely due to a separation event at the end of the month.

“At $23.73 in January 2021 for Victoria, it is, in fact, the lowest monthly average price since December 2012. Unsurprisingly, this price drop had a large impact on more expensive natural gas generation in Victoria.

“The largest decrease in natural gas generation percentage can be seen in Victoria, where it only accounted for 0.7% of the total generation in January 2021. In Victoria, the brown coal generation also saw a decrease in percentage share from 78.8% to 74.9%. In contrast, solar PV generation has increased from 1.5% to 2.9%, while wind generation increased from 11.2% to 16.3%.

“This is the same story for other states, with a low average monthly price driven by increased solar PV and wind generation. The consequence of which is a reduction in the share of fossil fuels in the generation mix.

“As noted by the QED, as the wholesale electricity prices has fallen, out-of-market costs to keep the system secure have also increased, with SA particularly seeing a 91% increase in out-of-market costs when comparing 2020 with 2019. AEMO expects four upcoming synchronous condensers will curb this trend by the middle of the year.”

Learn more about the study.

According to the report the number of gas suppliers peaked in April 2019 at 77 suppliers and the collective market share by meters held by non-large suppliers has grown from 17.0% in October 2005 to 56.2%.

In the electricity market, the number of suppliers peaked in April 2019 at 73, but the market share of non-large suppliers by meters has grown from 3.6% to 28.2% in the same period.

Simultaneously, the traditional six largest suppliers (British Gas, E.ON UK, EDF Energy, npower, Scottish Power and SSE) have seen their combined market share by meters decrease.

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Large suppliers’ collective market share by meters has reduced from 82.7% in October 2015 to 71.8% in October 2020. Large suppliers’ collective market share by meters has decreased from 55.8% to 43.8% in the gas market.

Molly Lloyd, an analyst at Cornwall Insight, said: “Growth for non-large suppliers has been driven by several factors, including the acquisitions of customers from exiting suppliers (including Yü Group, which acquired around 4,000 business meters off of Bristol Energy in August), competitively priced propositions or engagement with the TPI channels.

“The competitive pressures continue in the business supply market, with five exits from April to December. However, there continues to be interest in the market with two new entrants recorded over the same period.

“Despite market share growth for some suppliers this quarter, it is currently a challenging environment for suppliers due to COVID-19. This is likely to have an enduring effect on suppliers for some time, with some of the full impacts of the pandemic yet to be seen.”

Research from Cornwall Insight examining the trends observed across exchange platforms at the start of 2021 highlights that prices have started to diverge between the two GB day-ahead exchanges, the N2EX and EPEX platforms.

Key findings

• Prices at the two power exchanges are diverging, prior to Brexit they would outturn the same.
• Between 3-10 January, N2EX prices averaged £0.37/MWh above EPEX prices. This was mainly due to several exceptional price events where N2EX prices exceeded EPEX prices by notable amounts.
• On 6 January between 5pm and 6pm, there was a price differential of £262.59/MWh.
• In contrast, 68% of all hours in the week saw EPEX prices outturn above N2EX prices.

The below graph shows the volumes traded across both exchanges, and the cleared prices, on the hourly day-ahead auctions in the eight days examined. Nordpool’s N2EX platform has seen the greater volume of trades, with roughly double that of EPEX day-ahead auctions.

Tim Dixon, Wholesale Team Lead at Cornwall Insight, said: “Although the GB market is currently decoupled from the European power exchanges, this does not mean that electricity interconnector flows stop, rather the way flows are allocated and auctioned have now changed. This means that each relevant power exchange will have to run and calculate their day-ahead auction results independently of any cross-border capacity allocation process and each other.

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“It is expected that this will result in less efficient price-setting and interconnector flows, thus negatively impacting players’ economic welfare. For example, a cheaper generation option may not be used due to its participation in one auction platform over another, or because interconnector capacity has not been allocated appropriately to allow a cheaper alternative to run in a neighbouring market.

“At this stage, it is difficult to know if the lack of coupling resulted in higher overall prices for consumers or not. Arguably the record £1,000.04/MWh price clearing bid seen on the 6 January would have remained the price-setting plant in a coupled auction. Still, alternatively, cheaper options may have been available elsewhere with implicit trading provisions. These differences have caused market participants challenges, with considerable price differences already being observed in some hours.

“One notable example includes renewable generators under the Contracts for Difference (CfD) scheme, which receive top-up (or they pay back) from their pre-agreed strike price to a market reference price (MRP). For intermittent generators, the MRP is the day-ahead hourly auction price. However, with two day-ahead hourly auction prices now emerging, it has become a challenge for CfD generators to sell their electricity on wholesale markets and achieve the precise MRP.

“It will be interesting to see how market participants now react and if the dynamics between the two power exchanges change until more permanent solutions are implemented.

“It should be noted the current arrangements are not an enduring solution and the Free Trade Agreement has outlined what the future trading arrangements will look like, but the operation of these new arrangements are a way off yet.”

Learn more about the report.

Robert Buckley, head of relationship development at Cornwall Insight, said: “Cornwall Insight modelling suggests it now looks likely that we will see a substantial rise in the summer energy price cap period, completely reversing the fall that was seen in October. This increase was driven mainly by a rebound in the wholesale cost of energy over the latter part of 2020 and into 2021. For example, April Baseload prices have risen 16% from 1 December to the present.

“Wholesale prices have been boosted by a combination of factors including rising worldwide energy costs and recovery of UK prices from the ground that they lost in Summer 2020 under the first COVID-19 lockdown period. In addition to this, is the impact of the current winter weather conditions on the market.

“While wholesale costs constitute a large proportion of the potential rise, there are other influences at play, including an increase in some of the policy costs in place to support renewable and low-carbon electricity generation.

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“This upward movement has been mitigated slightly by the fact that a one-off £15 COVID-related cost element in place for the Winter 2020-21 cap is now no longer present in the calculations for Summer 2021.

“However, Ofgem is currently consulting on introducing an additional charge for COVID-19 related bad debt. The regulator has estimated this to be a £21 charge for Summer 2021. This would represent a further rise to our predict view.

“Currently, competitive tariffs are priced around £180 below the current level of the cap, so customers can still make savings, especially if they are on a Standard Variable Tariff. So, it would be wise to check their deals before the price cap rises.

“The COVID-19 pandemic has brought a unique set of circumstances for suppliers having a difficult situation to juggle, facing higher wholesale costs and bad debt levels rising. Now, they will be assessing their commercial strategies closely. The decision of what to do is not a simple one, with fragile balance sheets, varying hedging strategies, and rising policy and network costs mean there is no one-size-fits-all answer.”

Learn more about the study.

This is the first time SME prices have risen since Q418 following five consecutive quarters of price reductions.

The below graph shows one-year acquisition prices for 25MWh SME gas contracts and 6MWh SME electricity contracts.

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Sam Holland, an analyst at Cornwall Insight said: “Prices for SMEs fell steadily in 2019 after a milder winter led to oversupply in the gas markets. These reductions continued through the first half of 2020 due to COVID-19 associated falls in demand. However, in the three months to 3 November 2020, average SME gas prices increased by 5% for 25MWh contracts, while SME power prices for 6MWh contracts rose by 10%.

“Recently, the market has seen an upward trend in wholesale prices, contributing to the increase in SME prices. In fact, from 4 August to 3 November day-ahead gas prices rose by 159% to 37.75p/th, finding support from declining temperatures, alongside 20-month high LNG prices caused by adverse weather in Asia and North America. Across the same period, day-ahead power prices increased by 73% to £52.75/MWh as demand for power showed continuing signs of recovery.

“Despite the second national lockdown, SME prices remained steady during November with suppliers applying small price adjustments. Lower temperatures offset reduced gas demand and resulted in day-ahead gas prices averaging 37.74p/th, whilst day-ahead power prices fell to £46.29MW/h on average. They were buoyed by tight supply margins causing price spikes.

“Looking ahead, wholesale prices could recover further as news of a ~90% effective vaccine has led to growing oil prices. This has not yet affected gas and power prices for SMEs in GB but may do so in the coming weeks.”

These latest forecasts show more than 1.3GW requirement across all services in DNO regions in 2021.

The largest share of the requirement (636MW) is attributed to the Dynamic service which supports the network during fault conditions.

The figures also show the largest forecast procurement to be throughout the WPD region, with nearly 800MW of serviced need out to 2023.

It should be noted that these latest figures have not published requirements for both NPG and SSEN regions. This suggests that these regions are yet to disclose their future needs, or that they have no requirement for these services in the coming years.

Read more insights from Cornwall Insight

Joe Camish, an analyst at Cornwall Insight, said: “Since 2018, DNOs have been tendering and procuring for various flexibility services to help solve congestion (thermal constraints) in local electricity grids. More recently DNOs have started procuring for additional services to meet other network needs such as voltage and reactive power support.

“To date, providers of these services have typically been made up of battery storage units, demand-side response (commercial and industrial), gas reciprocating engines and EV fleets.

“Procurement of these flexibility services has progressed slowly over the past three years with several tenders concluding undersubscribed by a large amount resulting in outstanding requirement, while some regions are yet to procure any service volumes this year (NPG).

“However, these latest forecasts show that the requirement for these services is starting to gather pace as DNOs seek to rapidly decarbonise the energy system to meet its net-zero target.”

This led to a target revenue pool for TPI’s of £335mn/year, an 18% decrease on 2019 levels.

Key Findings

• TPIs operating in the SME segment saw total revenue fall from £225mn in 2019 to £190mn in 2020.
• Revenues for TPIs from I&C contracts also decreased to £145mn, compared to £170mn in 2019.

Molly Lloyd, Senior Analyst at Cornwall Insight, said: “The decrease in revenue was partly due to the temporary closure of businesses during national lockdowns. Also, during this time many TPIs furloughed sales staff which reduced the number of new business energy contracts TPIs were able to secure.

Read more reports from Cornwall Insight.

“Distress in many businesses meant the renewal of energy contracts moved down the list of priority for customers. Many customers would have chosen to defer contract renewals until the outlook for their business operations became clearer.

“The impact of business closures was coupled with commissions in the SME sector being impacted by the reduction in volumes. In some instances, those TPIs that were paid by suppliers on a volume basis or using estimated rates of consumption are seeing suppliers clawback commission payments in cases where actual consumption was lower.

“Trends seen in 2019 for I&C TPIs such as increasing competition among TPIs have continued into 2020, coupled with reductions in volume due to the COVID-19 pandemic.

“TPI penetration in the I&C market remained steady on 2019, as the market is more saturated, with the engagement of I&C businesses with TPIs seen as unlikely to increase.”