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Chart of the Week

2019

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Charging in: New BM entrants and Wider Access

Lee Drummee
Lee Drummee

While National Grid ESO has been granted a derogation until 30 June 2020 to implement project TERRE; Wider Access, its project to increase accessibility to the Balancing Mechanism (BM), is still scheduled to go-live on 11 December 2019. In this Chart of the Week we analyse recent activity of aggregated units and batteries in the BM and take a view on what new entry might mean.

Plants dispatched on the BM are known as Balancing Mechanism Units (BMUs). A BMU represents either a generation plant or smaller groupings of individual units in a plant that can be independently controlled. Since June 2019 the volume of accepted actions on the BM from aggregated and battery BMUs has risen considerably. In June, just over 2GWh of volume was accepted. By August, this had reached 9.1GWh and accepted volumes have not fallen below 5GWh since.

This increase has coincided with a rise in active aggregated units and batteries. In January, just five units from three parties had volumes accepted. By the end of November, a total of 22 unique BMUs from 9 separate parties had been active in the BM over 2019.

The Wider Access workstream has objectives to allow non-traditional providers easier BM access with this being facilitated by measures such as allowing BMUs to submit data at an aggregated level and through introducing Virtual Lead Parties that will be able to register BMUs from 1MW.

In late November, Elexon announced that three parties are actively going through the qualification process to become a Virtual Lead Party.

It is expected that additional parties will take advantage of the changes made and increase the number of aggregated and smaller units active in the BM. Many of these players will be looking to add the BM to their existing business cases in the hope of upside in what can be a volatile pricing environment.

Like the Capacity Market and Balancing Services markets before it, the competitive landscape of the Balancing Mechanism is likely to change with the entry of smaller aggregated units.

This analysis is taken from our BM reporting service which tracks competitive dynamics, pricing and Wider BM Access. If you would like more information about this service, please get in touch.

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Training course | Flexibility fundamentals

Chart of the Week | Call on me: Scottish wind farms in the Balancing Mechanism

Chart of the Week

2019

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Bang for your buck: consumer cost of policies

Nick Palmer
Nick Palmer

Ofgem published its State of the Market 2019 Report on 3 October, providing a comprehensive overview of the state of competition in the retail and wholesale energy markets. It also assessed how well vulnerable customers are protected, the performance of network companies and the progress of decarbonisation.

Using third-party analysis, Ofgem presented the relative costs to the consumer of various types of decarbonisation policies from 2010-2018. The acceleration of decarbonisation required to meet net zero by 2050 means that the cost for the consumer is something that will need great consideration by the government. In this Chart of the Week, we consider the cost for consumers of decarbonisation polices.

Figure 1’s y-axis shows how much bang for your buck each type of policy offered over the 2010-2018 period, in £ per tonne of carbon saved. The x-axis shows how much carbon was saved by these policies over the period, in millions of tonnes (Mt).

The chart shows that demand-side policies, such as energy efficiency measures, were the most cost effective for consumers, at around £21 per tonne of carbon dioxide saved, based on BEIS estimates of their impacts. However, while demand-side policies were the cheapest per tonne of carbon saved, they were only responsible for around 20 Mt saved.

Carbon prices were the next cheapest, costing £31 per tonne of carbon saved. In total, carbon prices were responsible for around 320 Mt saved, the largest amount of any type of decarbonisation policy. However, Ofgem noted that, given that there is limited coal plant left on the system, the cost effectiveness of the carbon price may diminish over time.

Air quality directives cost £46 per tonne saved and were responsible for around 50 Mt saved. Large-scale renewables subsidies, such as the Renewables Obligation, cost £99 per tonne saved and were responsible for around 220 Mt saved. Small-scale renewables subsidies, such as the Feed-in Tariff, were by far the least cost effective, costing consumers £322 per tonne saved. Additionally, they only saved around 20 Mt of carbon over the period.

In Ofgem Chair Martin Cave’s launch speech for the report, one of the major themes he covered was the net zero target. The inclusion of this policy cost comparison in the report further suggest that Ofgem is seeking to take a greater role in the UK’s decarbonisation.

I wrote about the State of the Market 2019 Report in more detail in Energy Spectrum 686. For more information about subscribing, please contact n.palmer@cornwall-insight.com

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Publication | Energy Spectrum

Publication | Energy Market Bulletin

Chart of the Week

2019

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Sizing up: Flexible versus Renewable PPA markets

Charlotte Farmer
Charlotte Farmer Analyst

As a result of the publication of our new Flexible Power Purchase Agreement (PPA) Market Report, we have been able to compare and contrast the different markets for PPAs between renewables and flexible assets. This Chart of the Week highlights the primary differences in the market sizes of each sector.

The total size of the flexible asset market is an order of magnitude smaller than that for renewables, with total capacity for flexible assets estimated at 4.5GW in 2019, compared with renewables’ 40.6GW. Flexible assets in our review, used in turn to size the flexibility PPA market, are those that focus on peaking and optimisation. These include gas peakers, OCGT plant, diesel engines and batteries.

The proportion of each market which can be deemed as “contestable” for third-party PPAs also differs significantly. Where up to 65% of the renewables market will be looking for a third-party PPA, just 40% of flexible assets will seek this.

This stems from the higher proportion of utilities and large developer-trader organisations which will trade and optimise their flexible assets independently. In contrast, the renewables market has seen a higher level of independent developers, often without trading capabilities or relevant industry licences, that have required third-party PPAs for the offtake of their power. Flexibility assets also see greater levels of equity ownership which can reduce the requirement for long-term third-party PPAs.

But despite the smaller size of the contestable flexible asset PPA market and the reportedly narrow margins available, the sector is still highly competitive. – with up to 20 offtakers competing for contracts with flexible assets. This compares to more than 40 active offtakers in the more mature renewables space.

Cornwall Insight’s latest Renewables PPA Market Share and Flexible Asset PPA Market reports were released in September. Please contact c.farmer@cornwall-insight.com or t.dixon@cornwall-insight.com for more information.

 

 

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Blog | Renewables Obligation Mutualisation Looms again

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Chart of the Week

2019

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I want to break free – Ofgem’s Collective Switch results

Hannah Treacy
Hannah Treacy

On 27 September, Ofgem published the final results of its five collective switch trials, which were administered by energyhelpline and held between February 2018 to April 2019.

The trials were designed to test switching among disengaged customers and assess the impact of the default tariff cap on switching. Customers received three letters sent either from their supplier or Ofgem. Letters offered a collective switch or an Open Market offer which did not indicate a specific tariff. Open market letters saw fewer switches, suggesting that naming a tariff can remove confusion surrounding switching.

More customers switched in Trial 3 after the default tariff cap was implemented (Figure 1), despite potential savings being lower. The Re-engagement trial offered a collective switch to customers who did not switch in Trial 1. Despite the low switching rate (14%), which was expected, the results highlight the value of secondary communications, particularly as just ‘a handful’ had remembered Trial 1.

19% of those that took part in the collective switch switched to a small and medium supplier (SaMS). The lower value was attributed to disengaged customers feeling ‘uncertain’ of less familiar brands. However, 30% of the customers switched to SaMS after the trials, according to energyhelpline, suggesting that the trials sparked long-term engagement.

The success of these trials could inform future regulatory intervention under Ofgem’s ongoing retail market reforms. In fact, energyhelpline suggested that Ofgem assess the market impact of scaling the trial up to the full database of 8mn disengaged customers.

However, Ofgem has announced it will not progress in developing this database.

Scaled-up trials could pose risk to large suppliers and their long-term customer bases, although the preference seen towards recognisable branding offers an opportunity for large suppliers to retain loyal customers, and the potential for increased acquisition if they win a collective switch auction.

Our Domestic Energy Sales Channels report explores sales channels including collective switches. For more information contact h.treacy@cornwall-insight.com

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Chart of the Week | Price is King for TPIs

Service | The Faster Switching Service

Chart of the Week | Domestic supply: Highest highs and lowest lows

Chart of the Week

2019

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Zoning out: ESO aims to reform generator TNUoS

Steven Britton
Steven Britton

Transmission network use of system (TNUoS) charges are partly based on a locational element, determined by which charging zone the network user is in. There are currently 27 zones for generators – in this Chart of the Week we look at how National Grid ESO is seeking to change that.

National Grid ESO re-evaluates how many charging zones there should be for the start of each price control period. It has found that continuing to use its current methodology would lead to the number increasing to around 50 from April 2021, when the RIIO-T2 price control begins. It considers that this would create too much uncertainty for investors and TNUoS-liable generation, and so has proposed to instead align the zones with the demand zones (the Grid Supply Point regions). To do this, it has raised CUSC modification CMP324 Generation Zones – Changes for RIIO-T2.

Figure 1 shows how big this change would be – there are 14 demand zones and few map onto the generator zones. The most dramatic difference would be in Scotland, which would move from having 12 generator zones to only having two.

The move towards a less granular charging scheme for generators may seem curious given the direction of travel for distribution charges and the amount of attention charges in general are getting from Ofgem’s Significant Code Reviews at the moment. However, National Grid ESO has suggested that granularity is less important for transmission charges and outweighed by the benefits in simplicity and predictability. This modification will have real consequences for generator charges and it is expected that other parties will propose competing solutions.

We provide regular coverage of these developments with our generator regulatory services. For more information call 01603 542126 or contact s.britton@cornwall-insight.com

 

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Services | Monthly Regulation Report 

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Chart of the Week

2019

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Better late than never: smart rollout gets new targets

Oliver Archer
Oliver Archer

Last week the Department for Business, Energy and Industrial Strategy (BEIS) announced plans to set binding smart meter installation targets out to 2024.

The plans came alongside an admission that around 30mn smart meters are expected to be installed by the current 2020 deadline, out of 53mn meters, equivalent to roughly 57% completion. While the new targets do not mean the 2020 obligation will be relaxed, they give a clearer idea of the timescales expected to fully deliver the rollout.

In this Chart of the Week, we will look at some of the implications of delays to the rollout and highlight four key industry programmes that may be affected. Government has described the smart meter rollout as not only creating potential savings for suppliers and customers, but importantly laying the groundwork for significant future changes.

However, as shown in Figure 1, some of these programmes that rely on the wide uptake of smart meters are due sooner than the expected 85% coverage by 2024 can fully support:

  • The CMA recommended BEIS that continues price protection for prepayment customers until a smart prepayment solution is available. The current cap is set to be lifted by 2020
  • Continuation of the default tariff cap is set for review annually between 2020 and 2023. Uptake of smart meters is one of the measures Ofgem will look at in this process
  • Suppliers with over 150,000 customers must offer a Smart Export guarantee (SEG) to replace the Feed-in Tariff (FiT) from 2020 onwards. A smart meter is a pre-requisite for SEG tariffs
  • A decision is yet to be made on industry-wide Half Hourly Settlement (HHS), but delays to the smart rollout pushes any start date back to 2025 or later

While BEIS noted that solutions to technical issues hampering the rollout should be in place by 2021, some of the programmes listed above will surely find themselves delayed. Taking a wider view, we may also see impacts on the development and uptake of technologies linked to decarbonisation and flexibility, including smart charging and demand-side response.

If you are interested in the smart meter rollout, Supply Licence or the Smart Energy Code, find out more about our Domestic Smart Metering Market Report and Smart Meter Regulation Service.

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Service | Smart Meter Regulation Service

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Training | Flexible Smarter Electricity Networks

Chart of the Week

2019

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Call on me: Scottish wind farms in the Balancing Mechanism

James Brabben
James Brabben

With the wind in her arms

While much of the attention in the Balancing Mechanism (BM) focusses on how flexible technologies such as gas, coal and, increasingly, batteries are being commercially utilised, less is often spoken about the role of wind.

Whilst not strictly dispatchable, management of wind resources is a critical tool for National Grid in dealing with system constraints, supply and demand imbalance and increasingly inertia. We’ve been analysing the BM in greater depth as part of our relaunched Balancing Mechanism Reporting Service, with data for August showing wind was the second-most utilised technology in the BM by accepted volumes after gas.

This week’s Chart of the Week provides detail on this recent trend and importantly who is being called on from the wind market and why.

Someday, some good wind

All licensed generators operating in the BM have to submit bids (to turn down) and offers (to turn up) for each half-hourly period. Accepted wind actions are predominantly accepted bids (to turn down) owing to two key factors. Firstly, nearly all current wind assets are under subsidy support regimes – most under the Renewables Obligation (RO) – and receive payments on a MWh basis. Therefore, when the wind is blowing, operators will typically maximise output for the period to capture value. Secondly and linked to this, wind farms are rarely in a position to dispatch in the BM and “offer” to increase volumes, either technologically or because they are already running at maximum or close to maximum capacity in the prevailing weather conditions to capture subsidy.

Bid and offer price levels are decided by the generators on the basis of the commercial impacts on the operators. As a result, wind generators typically bid at levels which offset the lost subsidy revenue from not generating. The chart shows this price range for the top 14 generators by accepted bid volumes in August. It also shows that bid prices were in the range of -£65/MWh to -£73/MWh – please note that negative bids represent a payments to generators to turn down output. The bid price is around that needed for an onshore wind farm to compensate for lost RO certificates, as well as accounting for start-up and shut-down costs and any associated maintenance. The degree to which a margin is made from this bid will depend on each wind farm and their operations. Licence conditions also restrict gaming activities.

A question arises as to why National Grid would “pick” these wind generators to turn down, when they are generating low-carbon electricity, something we are asked about regularly by our report subscribers. The answer is that typically, National Grid will have already used other, cheaper, options in their “stack” of bids to manage the system when there is too much power. Our analysis shows that wind is predominantly called on overnight and in the middle of the day, times when you would expect the chances of an oversupplied system long system to be greater.

But they don’t tell it all

While price is important, there are also locational and physical system characteristics that National Grid has to bear in mind when balancing the system. Of the top 14 onshore wind generators by accepted bid volumes in August 2019, all are located in Scotland.

This is not only a result of high proportion of onshore wind being located in Scotland, but also system constraints. Effectively, when there is high wind output in Scotland, especially North Scotland, constraints on the physical network often make it difficult to transport power to demand areas, predominantly located further south.

National Grid will often constrain wind production to avoid system issues, and provide a constraint payment for this. The issue has been exacerbated recently with operational issues for the newly commissioned HVDC Western Link, specifically built to mitigate north-south constraints. As a result, constraint payments have hit record monthly highs this year and our BM report analysis shows they topped £8.5mn alone in August.

Constraints are clearly reflected in BM actions, with our analysis showing that 91% of wind actions taken in August being what is known as “SO-flagged”. This is where balancing actions are flagged as system issues, such as constraints, rather than energy issues, such as too much or too little power.

The high volume of flagged actions clearly shows how physical system constraints are impacting the BM, leading to large volumes of wind generation each month being curtailed. While the development of further onshore wind in Scotland is crucial for further growth in renewable electricity, interactions with the physical network will create challenges and likely lead to greater levels of activity in the BM unless further network reinforcements or solutions are found.

We will be hosting our latest Scottish Generators Forum on 26th September in Edinburgh discussing topics such as onshore wind in the BM as well as the latest regulatory and policy news. Please contact James Brabben j.brabben@cornwall-insight.com for details.

Our relaunched Balancing Mechanism Reporting Service is available for a one-month trial, including daily reports and a monthly webinar. Please contact Tim Dixon t.dixon@cornwall-insight.com for details.

Chart of the Week

2019

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Could have had it all: enrolling in the DCC

Oliver Archer
Oliver Archer

Earlier this week, the Smart Data and Communications Company (DCC) announced the installation of the two millionth SMETS2 meter. The installation was reportedly carried out by British Gas in a house in Surrey. However, with less than 15 months until the smart meter rollout deadline, and around one-third of household installations completed so far, SMETS2 install rates remain well below what is needed to meet the target.

The latest calculations from our Smart Metering Market Report show that the industry would need to install over 50,000 meters a day to complete the rollout by 2020. As shown in Figure 1, SMETS2 installation rates were sitting around 9,000 a day in early September, and – according to their licences – suppliers should at this point only be installing these newer meters.

In reality, SMETS1 installations continued past the 15 March cut-off, and are likely still ongoing. Although the regulator has expressed understanding with the external factors driving continued SMETS1 installs, it is not clear how much flexibility Ofgem will allow, nor how lenient it may be when it comes to assessing compliance at the end of 2020.

At the peak of the SMETS1 rollout, suppliers were installing around 17,000 meters per day. SMETS2 installs would need to almost double to match this rate.

At the current trajectory, daily installations will be closer to 12,000 at the end of this year, at which point 12 months would remain to install meters in close to two-thirds of domestic properties.

While reaching the two million mark does represent a significant milestone for the industry, it will need to be followed up by increased efforts to iron out the difficulties still holding SMETS2 installations back, not least the network connection issues which are frustrating installs in the north of England and Scotland.

For more information about our Domestic Smart Metering Market Report, click here

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Chart of the Week | Fix Up, Look Smart – SMETS installation dates on the horizon

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Chart of the Week

2019

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BFG: Big Frequency Game

Sonal Maroo
Sonal Maroo

Since last Friday’s (9 August’s) power blackout there has been considerable interest in how National Grid Electricity System Operator (ESO) balances power demand and supply. Terms such as frequency, rate of change of frequency (RoCoF) and inertia have all gained in currency.

Today’s Chart of the Week shows the distribution of frequency on the British electricity transmission system from 2014 to 2018. It aims to show the spread of frequency distribution away from the standard 50Hz and towards the allowed operational boundaries as the years go on, based on second-by-second data (see Figure 1).

 

 

Frequency is a measure of the stability of an electrical power system and deviates because of changes in demand and supply. A surplus of generation increases frequency, while excess demand yields a fall in frequency.

During 2014-18 the penetration of renewables has risen significantly. In 2014, 15% of generation was from renewables, with this increasing to 33% by 2018. Wind power contributed to 65% of that increase. Over the period the distribution of frequency has widened (see Figure 1), but until 9 August remained within its allowed limits.

Renewables generation changes as the weather changes. Wind power especially can experience several variations within a small period. In addition, solar and wind do not provide inertia – the free energy stored in the rotating mass of turbines – which helps maintain stability and limit RoCoF.

As the UK pushes towards a net zero target, the use of renewables will rise. It is also widely expected that the number of power stations with spinning turbines will reduce as older coal, nuclear and gas plants close. While power flows from solar and wind can be held back if required, having fewer turbines on the system will reduce inertia, increase RoCoF and thus the challenge of frequency management.

9 August’s blackout saw two generators fail near simultaneously. System frequency dropped to ~48.8Hz, below the statutory minimum of 49.5Hz. National Grid ESO, the government’s Energy Emergencies Committee and Ofgem are all investigating the exact circumstances and what lessons can be learned.

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Chart of the Week

2019

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Corporate PPAs: please form an orderly queue

James Brabben
James Brabben

With the promise of long-term fixed price agreements with creditworthy consumers, corporate power purchase agreements (CPPAs) have become one of the most talked about routes to market for new subsidy-free generators. CPPAs provide for the sale of electricity from a developer to a final consumer typically using a supplier to interface with market trading rules. Many large consumers are interested in them as a way of decarbonising their power supplies and in aiding budget certainty.

Recent announcements from developers such as Lightsource and EnergieKontor show that subsidy-free CPPAs can be delivered, but the scale of this model on a market-wide level is still being evaluated. This week’s Chart of the Week shines a light on this potential for increasing CPPA uptake by looking at the demand and supply balance.

For supply we have estimated new build onshore renewables capacity—currently ineligible for subsidy—from BEIS’ Renewable Energy Planning Database (REPD) based on projects with planning permission and grid connection dates already in place. Taking an average view on load factors, we have then calculated the volume production of this potential pipeline over the next five years.

This is compared to our calculation of aggregated demand of RE100 consumers in Great Britain. RE100 is a global corporate initiative which brings together leading multinationals committed to consuming 100% renewable electricity. Demand is then forecast against BEIS Energy and Emission Projections changes to show a like-for-like volume view of generation and consumption. We also show the existing RE100 demand we understand is currently being serviced by CPPAs. By 2021, the development pipeline for new subsidy-free assets is forecast to outstrip the demand from RE100 corporates and by 2024 it could be more than double their needs at 18TWh. Some developers are already looking to grow their market into small and medium business customers or advocating for other large energy users to opt-in for long-term fixed price agreements. However, business consumers are clued up on market trends and we could see a buyer’s market for CPPAs, potentially impacting who has the final say in all important negotiations around price and tenure.

We will be covering the size and scale of the potential CPPA market as well as new models being deployed for subsidy-free as part of our CPPA webinar on the 15th August. Please contact training@cornwall-insight.comfor details.  

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