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Chart of the Week

2020

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Challenger suppliers: started from the bottom, now we here

Hannah Treacy
Hannah Treacy

The publication of our Domestic Market Share Survey for Q1 2020 (referred to as Q120 with a reporting date of 31 January 2020) shows a shake up of the rankings that is unprecedented in the survey to date. The completed merger of OVO Energy and SSE, and organic growth from Bulb have seen the names of challenger brands sit among the largest suppliers in the domestic energy market.

Figure 1 shows that OVO Energy rose to second in the rankings, holding 14.1% dual fuel share after taking on 5.6mn SSE accounts in January, tripling its customer base. OVO Energy is now 3.8pp ahead of E.ON UK which fell to third place, despite recording record organic growth individually in Q120.

The second major change in the “Big Six” positions saw Bulb move ahead of npower by dual fuel accounts, ranking 6th and 7th respectively by this metric (however, npower holds its sixth place position by domestic energy accounts, as it has more single fuel customers). Bulb has recorded a net gain of more than 200,000 dual fuel accounts over the last year through organic growth, although it recently acquired 9,000 customers from GnERGY through the supplier of last resort process.

However, these positions aren’t expected to endure when the E.ON UK and npower profiles merge. Collectively, the two suppliers held 15.9% dual fuel share at 31 January 2020, which would put E.ON UK back into second position under the current customer base. E.ON UK’s agreement with Octopus Group’s Kraken Technologies will see npower’s domestic and SME customers migrate to the customer platform, E.ONnext, during Spring 2020, followed by E.ON UK customers in 2021. The partnership is expected to improve efficiency and provide a combined EBIT of at least £100mn by 2022.

The next quarterly Domestic Market Share Survey, to be published in June 2020 and covering the three months ending 30 April 2020, is expected to capture more recent mergers, alongside some of the initial impacts of COVID-19 on the domestic supply market. Some suppliers that have previously grown through face-to-face sales may be reassessing their routes to market, while others will be facing greater challenges in maintaining cash flow during this difficult period.

Chart of the Week

2020

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The pipeline for CfD AR4: Who, where, when?

James Brabben
James Brabben

With the potential reinstatement of ‘Pot 1’ technologies in the next Contracts for Difference (CfD) Allocation Round 4 (AR4) in 2021, this Chart of the Week takes a look at the pipeline of renewables projects most likely to enter the auction.

Drawing upon research in our new service The Renewables Pipeline Tracker, we show a heat map of site locations by capacity for potential AR4 bidders. This is calculated through:

  • Filtering our calculated total pipeline of over 37GW across 800+ sites into those “most likely” to bid
  • These “most likely” are categorised as all CfD eligible technologies which have applied for or gained planning permission, or re-applied for and gained permission, post all subsidy scheme changes and closures. Effectively, this is from early 2019 onwards
  • In our view, these projects are most likely to be competitive in the auction, as prior to the recent BEIS announcements they would have been aiming to operate subsidy-free anyway
  • A separate calculation is made for offshore wind, with all sites likely to be able to build by the delivery years of the next round, likely 2024 to 2026, included
  • From this, we use our database and wider data sources to place sites by their location against regions, specifically in relation to network connections
  • The differing scales of projects means there will be a mix of transmission and distribution connections, but our map groups these to align to the 14 distribution regions in order to visually display all of the data on one map
  • Concentrations in each zone, therefore, represent both larger transmission and smaller distribution connected sites, including offshore wind

The results are revealing, both from a commercial perspective and in the interactions of this with wider policy and network charging arrangements. The calculation reveals just over 13.0GW of our pipeline is eligible under this methodology, split between over 5.5GW of ‘Pot 1’ technologies including onshore wind and solar PV, 6GW of offshore wind and a smaller proportion of ~1GW for ‘Pot 2’ technologies, the majority of which is made up of Remote Island Wind (RIW).

The onshore wind capacity totals 4.2GW, a high figure considering the ~13GW in operation currently. Of this, over 3.8GW is in Scotland, highlighting the continued concentration of sites here owing to continued support in the planning regime, load factor conditions and land use arrangements.

Scotland is also home to all of the RIW pipeline, which totals 900MW and is dominated by the potential 450MW Viking wind farm development on the Shetland Isles. Compared to AR3, RIW projects could be in a more competitive position, with offshore wind potentially carved out of ‘Pot 2’ into a separate exclusive ‘Pot 3’.

Offshore wind has some higher concentrations of projects elsewhere, notably off the east coast of

Heat map of potential CfD AR4 pipeline (transmission and distribution) displayed by DNO region

England, but still sees the majority of capacity in Scottish Waters. Upcoming leasing rounds by ScotWind and the Crown Estate, could also yield additions to this pipeline. Although these will likely be too late for AR4.

For solar PV, the story is very different with the majority of the 900MW pipeline in England and Wales. The data also skews towards the South East region, with the 350MW Cleve Hill Solar Farm, which has been earmarked as a subsidy free development but has the potential eligibility to bid into AR4, hence its inclusion here. However, the project is considered a Nationally Significant Infrastructure Project due to its scale and is awaiting a decision from the Secretary of State in the coming weeks on whether permission will be granted. Our solar PV data for the tracker is taken from planning data sources and therefore does not show the high levels of solar PV without planning status but in the grid connection queue, which has been calculated at over 7GW.

Overall, our analysis shows just how competitive an AR4 auction could be, especially between ‘Pot 1’ technologies. However, the location of potential applications may not be seen in the spread of successful CfD awards. This is due to wider factors such as high TNUoS costs for larger sites in Scotland, differences in load factors and site conditions and wider financing and strategic factors at play from project sponsors. The pipeline may also change as we head through to 2021, with some sites continuing to look at subsidy-free and merchant options instead, whilst new sites may also join the queue for the CfD.

We will be detailing our latest research and our new Pipeline Tracker Service in a webinar, hosted at 11:00am on 22 April. You can sign up to the webinar here.

Chart of the Week

2020

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Energy demand falls amid coronavirus outbreak

Sam Holland
Sam Holland

Since the government imposed restrictions on movement in the UK on 24 March, demand for power has fallen around 11% March 2019 levels. Comparatively, demand for gas has been less affected due to the dominance of the domestic heating market on gas demand.

In this Chart of the week, we look at the timeline of the Coronavirus outbreak and the impact of milestone events on the daily gas & power consumption in the UK.

In the first part of March, average daily power demand was 0.78TWh, only slightly below the seasonal normal, however demand began to fall between 20 – 23 March as schools and businesses were asked to close. A number of large end users had already scaled back demand as a result of the pandemic, including manufacturers unable to source parts from overseas. A similar trend was seen in the service sector as most bars, restaurants, pubs, gyms, cinemas and many schools have closed. These two sectors represent around two thirds of total power demand and their partial closure has resulted in total daily demand falling by 0.1TWh on average in the first week of lockdown. Over the initial three working week shutdown period this could result in a 0.5% reduction in total annual demand.

Longer-term consequences driven by the fall in demand could effect non-energy charges. This is due to smaller charging bases for networks and policy subsidies and the changing of consumption patters for households and businesses. We expect disturbances to price caps from Summer 2020 onward. There is also the potential for challenges in electricity system balancing if demand remains low and existing generation fails to operate.

Timeline of UK Events

  1. Initial closure of some schools on 11 March.
  2. On 18 March most schools were closed. Two days later all pubs, clubs, restaurants and indoor sport and leisure facilities were ordered to close.
  3. On 23 March, the government imposed further restrictions on freedom of movement. This saw a further reduction in demand as the majority of the workforce is now working from home.

 

Chart of the Week

2020

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ES Catapult: shifting energy vectors in net zero

Neil Mearns
Neil Mearns

This month, we launch our first Energy: Net zero publication – the new name for the revamped Energy:2030. This publication, with a renewed focus on answering the net zero question, is a sister publication to Energy Spectrum and issues at the end of each month.

In this week’s Chart of the week, we pick out a chart from Energy Systems (ES) Catapult which, in its report Innovating to Net Zero published earlier this month, presented two distinct pathways to a 2050 net energy system: centralised (Clockwork) and decentralised (Patchwork).

In a Patchwork pathway, central government takes less of a leading role, resulting in a patchwork of regional low carbon strategies. In a Clockwork pathway, coordination from central government drives long-term investment in strategic energy infrastructure.

The figure shows the final energy consumption for 80% and total net zero targets from 2020-50 under the Clockwork pathway. The three principal energy vectors of petroleum, gas and electricity are prominent in all years to 2050 in a “Clockwork 80%” scenario. In a “Clockwork Zero” scenario, hydrogen overtakes both gas and petroleum in its importance between 2045 and 2050. Also notable here is the rapid rise and domination of electricity as a vector. 73% of the mix is comprised of electricity (43%), hydrogen and district heat by 2050.
Most of the remaining fossil fuel component is used in industry and aviation in “Clockwork Zero”. Negative emissions (CO2 removal initiatives) can help
counter residual emissions from these activities in the net zero scenario.

For ongoing analysis and insight into net zero pathways, as well as the technologies, policies and markets that will help us achieve net zero, contact n.mearns@cornwall-insight for a free trial of Energy: Net Zero or call 01603 542119.

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Chart of the Week

2020

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Suppliers struggle for profitability

Oliver Archer
Oliver Archer

This week many suppliers have agreed a series of measures to ameliorate the effects of the Corona Virus on vulnerable consumers.

This is no doubt the right thing to do but will come at a cost. In what position are they to take this cost? This Chart of the Week takes a look at financial accounts from licensed suppliers covering 2018-19, discussing profitability in today’s energy supply market.

A first reading of the available 2018-19 accounts (some are yet to be published, others do not include profit and loss) does suggest an industry struggling to realise profits, for a range of reasons specific to supplier size and strategy. Figure 1 shows the 15 businesses which have published these reports recording an aggregate operating loss of £23mn. British Gas and Scottish Power, the two large suppliers that have already published financials for 2019, together made an operating profit of £178mn, though both recorded significant reductions year-on-year in profitability and noted the negative impact of the default tariff cap. Among the six medium suppliers whose financial metrics have been aggregated in Figure 1, only Utility Warehouse reported a profit, and as a group these suppliers made a collective operating loss of £159mn.  Prepayment specialists E and Utilita fell into losses in the 12 months ended March 2019, both citing the impact of the prepayment cap, and Octopus Energy, Bulb, and So Energy reported deepening operating losses as the suppliers invested in growth and technology development.

As well as a difference in operating profit between the large and medium groups, there is a contrast in gross profitability, or the margin made on selling energy before operating costs are considered. The aggregate medium supplier gross margin is less than half that of the large supplier group, at just 7%. Gross margins for Bulb and Octopus Energy fell to 1% in 2018-19, and only Utility Warehouse reported a gross margin in the same range as the large suppliers, at 19%. This trend is seen to an even greater extent among some of the small suppliers, with Tonik Energy posting a gross loss of £4.5mn for the year ended March 2019, and Pure Planet reporting a gross loss of £7.3mn for the same period, its second gross loss in two years. Ecotricity, Good Energy, and Green Energy UK were the only small companies to report gross margins in a similar range to Utility Warehouse and the large suppliers.

Any perception that energy supply is a comfortable sector to operate in is challenged by financial reporting from the industry, with many businesses loss making, and some even in gross losses. Tariff caps are weighing on margins, and competitive pressures continue, with suppliers having to make tough strategic decisions as a result. Our domestic Supplier Insight Service tracks key supplier developments, including financial releases, investments, and acquisitions. For more information please visit our website.

Chart of the Week

2020

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We’ve got the power: T-4 Capacity Market results

Lee Drummee
Lee Drummee

On 6 March, the EMR Delivery Body (National Grid ESO) published the provisional results of the T-4 Capacity Market (CM) auction for Delivery Year 2023-24. The clearing price of the auction was £15.97/kW/year, the highest value since the 2016 auction, procuring 43,749MW of de-rated capacity. The clearing price was significantly higher than the £6.44/kW/ year in the recent T-3 auction. In this Chart of the week, we explore some of the reasons for this.

Existing generation accounted for 33,983MW, equivalent to 77.7% of overall capacity compared to 81.9% in the T-3. Only 4.0GW of nuclear was awarded agreements, down from 5.9GW in the T-3 auction. Hunterston and Hinkley B had already opted out of the auction, while Heysham 1 and Hartlepool were unsuccessful in winning agreements.

This allowed more “space” in the auction for new build sites, with 1,798MW of de-rated new build capacity awarded agreements across 95 individual CMUs. The Keadby 2 CCGT was the largest of these, with a de-rated capacity of 803.7MW and representing the first new build CCGT to win an agreement since the first T-4 auction in 2015.

The next biggest new build plant was Ferrybridge Multifuel 2 at 66.1MW. However, the success of both these new build projects was somewhat expected, with SSE already committed to building Keadby 2, while the Ferrybridge site entered commercial operation in December 2019.

Battery storage accounted for 114.5MW of de-rated capacity, split between 1-hour duration (94MW) and 2-hour duration (20.5MW). This included the 50MW battery at the Whitelee windfarm.

New build onshore wind was again successful, with three more projects awarded agreements. The successful plants; Whitelaw Brae (57MW nameplate, 4.2MW de-rated), Aberarder (50MW, 3.7MW) and Blary Hill (35MW, 2.6MW) will also benefit from a clearing price ~2.4 times higher than the T-3 auction.

The only windfarm not to win an agreement was Vattenfall’s South Kyle with a nameplate capacity of 234.8MW. However, with the potential re-integration of “Pot 1” technologies in the next Contracts for Difference allocation round, missing out on a CM agreement allows the project to participate in the next CfD round if they desire. The next opportunity for new build plant will be the prequalification for the 2024-25 T-4 auction, which will commence in July 2020.

 

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Chart of the Week

2020

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WHD and ECO thresholds now cover 98% of market

Tom Faulkner
Tom Faulkner

1 April 2020 will see the government’s Warm Home Discount (WHD) and Energy Company Obligation (ECO) scheme thresholds drop from 200,000 to 150,000. This will require all suppliers with more than 150,000 domestic customer accounts to be mandatory participants in these schemes.

In this week’s Chart of the Week, we look at how the changing thresholds provide support to more of the market and what more needs to be done to make sure those that aren’t covered can access appropriate support.

In June 2018, the government considered that changing the then current thresholds from 250,000 to 200,000 would bring the market coverage from ~94% to 97%. According to our Domestic Market Share Surveys, the move to 200,000 accounts in April 2019 saw the market coverage grow to 95%. Also, according to October 2019 data, we would expect this to increase a further 2% with the falling thresholds to 98% as of April 2020 (Figure 1).

Suppliers can be voluntary ECO or WHD participants, which Figure 1 does not take into account. This aside, ~2% of customer accounts cannot receive a benefit they may be eligible for because their supplier has not passed the threshold.

It is worth noting that customer accounts are measured separately for electricity and gas and, therefore, the 2% could be anywhere between ~500,000 and 1mn domestic customers and not all of these customers will be eligible for the benefits that ECO and WHD offer.

Regardless, it is clear to see that the changing thresholds have given a greater number of customers access to important benefits, whether that be £140 credit under the WHD or energy efficiency measures under ECO.

 

 

We facilitate a quarterly forum to help support supplier best practice for serving vulnerable customers. For further information on our vulnerability forum, please contact Tom Faulkner on 01603 542123 or t.faulkner@cornwall-insight.com.

Chart of the Week

2020

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Customers drive TPIs to go green

Sam Holland
Sam Holland

In 2019, large consumer-facing businesses led Third Party Intermediaries (TPIs) to increase their valuation of green power contracts backed by Renewable Energy Guarantees of Origin (REGOs). In this weeks Chart of the Week, we look at Cornwall Insight’s 2019 TPI Satisfaction Survey, and the shift in I&C TPI valuation of services beyond energy contracts towards green power.

The TPI Satisfaction Survey is an annual report which details TPI views on services they receive from energy suppliers. The 2019 edition captures the views of almost 80 TPIs, and also asks questions such as which suppliers “meet TPI needs” best and whether TPIs would recommend suppliers for their products and service.

This year’s survey revealed a number of changes across the supplier rankings, as well as the emergence of REGOs and Demand Side Response (DSR) as highly valued services beyond energy contracts from suppliers.

Figure 1 shows the increase in TPI valuation of REGOs and DSR compared to the benchmark most popular service. This moved REGOs and DSR up the service rankings. Dedicated account managers remained the most valuable service beyond energy contracts.

TPIs found, compared to 2018, I&C businesses are more likely to engage with green energy and ask TPIs for a renewable energy quote. One TPI stated: “[in 2019] demand for green products [from businesses] has increased on a monthly basis”.

These large businesses are under pressure to source both renewable power and gas in order to fulfil net zero aspirations. However, anecdotal evidence from TPIs suggested significant barriers to the uptake of green gas still exist. In discussions, TPIs reported that premiums on the renewable variant of gas have risen from £3.50/MWh to as high as £11.0/MWh due to a lack of supply, making it unaffordable for most businesses.

For further information on our TPI Satisfaction Survey, please contact Sam Holland on 01603 542172 or s.holland@cornwall-insight.com

Chart of the Week

2020

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Critical Link: Western HVDC & wind in the BM

Lee Drummee
Lee Drummee

In a previous chart of the week (Bootstrap Bill: Western Link HVDC & BSUoS) in May 2019 we explored the relationship between BSUoS charges and the availability of the Western Link HVDC.

The link suffered a fresh unplanned outage on 10 January, which caused it to remain offline until 8 February. This prompted Ofgem to launch an investigation into National Grid Electricity Transmission and Scottish Power Transmission over the delivery and operation of the cable. In this Chart of the Week we look at the relationship between the link availability and the behaviour of wind in the Balancing Mechanism (BM).

The most recent outage on the link coincided with record high levels of wind generation in Great Britain with generation from transmission connected wind topping 6.3TWh. However, with 2.2GW of the HVDC capacity unavailable, significant volumes of wind output had to be constrained to protect system integration.

This is highlighted in the chart, which shows that the volume of wind bids accepted in the BM classified as system actions hit a record high of 429.8GWh in January. Bids are instructions from National Grid to reduce output and system actions are those taken for wider system needs, such as constraints, on the physical network, rather than simply balancing energy supply and demand.

As a result, the cost incurred through the BM of turning down wind output also hit a record high of £30.9mn.These costs have been calculated by multiplying the £/MWh bid payment requested by the wind generators for turning down with the MWh volume of such actions.

Wind farms only receive subsidy payments when generating and therefore price lost subsidy into their bids.

The impact of the link’s availability can also be seen when looking at the difference in the volume of wind generation constrained in December 2019 and January 2020. Like January, December saw (at the time) record high wind output of 5.6TWh. However, with the Western Link available in December, the volume of wind bids classified as system actions on the BM was significantly lower at 247.1GWh.

As more onshore wind develops, especially in Scotland, in the coming years the problems of constraints will need to continue to be actively managed.

Our Balancing Mechanism Service tracks developments in the BM through our Monthly Webinar, Data Pack and Daily Summary. Please contact l.drummee@cornwall-insight.com for details.

Chart of the Week

2020

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Get a load of this! Wind output in January 2020

Tim Dixon
Tim Dixon Wholesale Team Leader

January 2020 was a ground breaking month for renewables, as National Grid ESO announced GB’s electricity system was the greenest on record. Transmission-level wind generation was 6.3TWh across the month.

High wind output has been aided by new capacity additions with projects such as the 285MW East Anglia One Phase 2 commissioning at the end of 2019 under the Contracts for Difference (CfD) scheme. These newer sites utilise the most advanced technologies, including larger turbine sizes, and are becoming notably more efficient than their predecessors. This efficiency is reflected in their load factors, which depend on their technology type – i.e. offshore or onshore – but also on the age of the site.

“Some of the newest offshore and onshore sites saw monthly average load factors close to, or above, 70% for the month of January, and on some days approached 100%.”

As a result of the elevated wind speeds experienced in January, onshore wind load factors averaged 42% for the month, and older offshore sites (pre-2016) reached an average of 52%. Demonstrating the rising efficiency of newer (post-2016) offshore wind farms, load factors averaged 55% for these sites. These are some of the highest load factors seen since the latter end of 2015. Some of the newest offshore and onshore sites saw monthly average load factors close to, or above, 70% for the month of January, and on some days approached 100%.

Our Chart of the Week highlights the monthly average load factors for wind technologies, across a sample of around 120 sites that we track. In the chart, we distinguish between offshore and onshore wind technologies, as well as by the commissioning year of the sites.

The chart shows differences in the performance of wind sites, with a trend line clearly seen in higher load factors for newer sites. This is likely due to the utilisation of larger turbines. With a further 1.1GW of new offshore wind capacity expected to be operational by April 2020 and with government aims to have 40GW of offshore wind by 2030 (up from today’s 10.8GW), these wind output records are likely to be broken more frequently.

Whilst a positive trend towards decarbonising the electricity mix, high levels of wind output are not without impacts. For one, all other things being equal, it causes lower wholesale power prices, often meaning that wind farms (bar those protected under the CfD), see reduced £/MWh revenues at times of high output. They can even cause negative prices, as seen for some day-ahead prices in December 2019.

There are also wider system impacts from increasing yield and the geography of wind assets. With the majority of onshore capacity in Scotland, limited transmission system capacity means that wind output is often constrained, resulting in additional consumer costs through the Balancing Mechanism and a reduction in wind output, something we will analyse in future Charts of the Week.

 

If you are interested in a free trial for our Energy Market Bulletin service, contact Lucy at l.dolton@cornwall-insight.com

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