V2X: how ‘storage on wheels’ can reshape our energy system

EV smart charging

Dagoberto Cedillos, Strategy & Innovation Lead at Open Energi

As Electric Vehicle (EV) uptake accelerates we’re starting to see a radical transformation in the way transportation influences the power system. Vehicle-to-X (V2X) technology, which can be used to discharge an EV battery back to the grid, or to power our homes and businesses, has a pivotal role to play.

By unlocking ‘storage on wheels’ V2X can bring down the cost of EV ownership; reducing the need for infrastructure upgrades and cost effectively integrating more renewable generation. Open Energi’s analysis suggests that by using vehicle batteries to optimise electricity demand against prices, EV owners could benefit from a new income stream in the region of £1,500 a year.

EV momentum

The UK currently has over 130,000 EVs on the road, and National Grid expects this to rise to over 10 million by 2030. Globally, BNEF forecasts 130 million EVs in the same timeframe.  As 2019 gets underway, all the indicators suggest EV growth is well on its way to hitting these targets, breaking records month-on-month. The graph below shows how EV forecasts have increased year on year. It’s possible we will see a very visible step change in the mid-2020s, as EVs hit up-front cost parity with Internal Combustion Engines (ICEs).

 

BNEF rising consensus on EV adoptionRising Consensus on EV adoption, source BNEF

Quantifying EV flexibility from smart charging

Last year Open Energi analysed the potential to manage EV electricity demand (one way) using smart charging.  Taking National Grid’s 10 million by 2030 forecast, we identified some 12GW of flexibility which could turn EVs from a threat to grid stability to an asset that can benefit the grid, drivers and the environment alike.

Smart charging flexibility comes from the energy that can be shifted (e.g. moving a period of charge, or part of it, from one time to another) and is determined by the amount of energy a vehicle will require at a given charge.

An average vehicle in the UK drives 21 miles per day, which translates to 6-7kWh. It is also limited by the speed of charging, typically 3, 7 or 11kW for an EV charging at home or in the workplace.  These scenarios offer the most smart charging potential because vehicles are parked and charging for longer periods, which makes their charging more interruptible.

There is no need for an expensive rapid charger outside your office or home if you are parked there for several hours. You will have ample time to charge your vehicle with a cheaper, slower charger.

Flexibility from EV charging with higher charging speeds is less interruptible, as it will tend to take place in situations where people want to charge quickly and continue with their journey, e.g. forecourt environments. These rapid charging scenarios will likely be complemented by stationary energy storage, which will help to reduce consumption during peak periods, manage local network constraints and provide grid services, as in the case of Open Energi’s project at South Mimms Motorway Services.

V2X capabilities

V2X tableOpen Energi’s 2017 analysis explored the potential to enable flexibility via smart charging. Turning our attention from smart charging to V2X provides food for thought. Instead of being limited by the amount of demand that can be shifted, V2X flexibility is defined by the amount of energy storage capacity in the vehicle battery (e.g. 40kWh for a Nissan Leaf) and its charge/discharge speed (3kW or 10kW based on current technology). This energy storage capacity could be used multiple times in a day, depending on its charging and discharging.

Conservatively assuming 5 million vehicles on the roads by 2030 – half of National Grid’s forecast – this translates to 200GWh of storage. Assuming they could charge/discharge at a low speed of 3kW, this equates to 15GW of capacity, enough to power 30 million homes! For comparison, National Grid’s most optimistic 2030 forecast of total (stationary) electricity storage capacity is 9GW.

Household demand

Given the battery accounts for some 50% of the car’s cost it is important to consider battery lifecycle and how using it could impact the vehicle’s warranty. However, keep in mind that a vehicle driving the average 21 miles a day will use less than a fifth of its capacity each day (7kWh/40kWh). The graph below illustrates a typical UK home’s daily consumption, which is in the region of 2kWh over the evening peak (4-7pm).

Daily Household Electricity ConsumptionResidential demand profile, source UKERC

Using V2X technology, an EV battery could discharge to the home during this time and already create substantial value by simply taking the household ‘off-grid’ when prices are at their highest. Adding this 2kWh to the 7kWh needed for driving gives a total daily throughput of 9kWh, or 22.5% of battery capacity.

EV storage on wheels

The batteries Open Energi operates in our portfolio of distributed energy assets usually perform a full charge/discharge cycle per day and comply with warranty conditions, so there is potential to extract further value by increasing the utilisation of the vehicle battery. However, in the example of a household we need to evaluate if the spread between the export price during the peak and the import price when energy is recovered is positive to justify exporting to the grid. This is not necessarily the case for larger demand sites such as an Industrial or Commercial user.

Opportunity for large energy users

Sites with greater demand could shift even more energy, and discharge more vehicles at once, without having to export. Essentially, a fleet of commercial vehicles becomes a behind-the-meter energy storage asset for a site when drivers have finished their shifts, displacing site consumption during the peak and recharging the vehicle battery when prices fall. Open Energi’s analysis suggests that this kind of demand optimisation could be worth up to £1,500 per vehicle per year.

The main obstacle today is the price and availability of V2G chargers but this should quickly change. While V2G chargers are relatively difficult to procure at present, V2G compatible vehicles are already being sold at a similar price to comparable EV models. For example, Nissan’s electric van, the e-NV200, does not seem to have a premium for the feature – it comes already equipped with V2G compatible charging technology. As charging technology catches up, V2G will be a standard bundled feature of these vehicles.

Storage on wheels

Projects such as Powerloop, the first large-scale domestic V2G trial in the UK, aim to demonstrate the benefits of V2X in action. Backed by Innovate UK and bringing together a consortium including Open Energi, Octopus Energy, Octopus Electric Vehicles, UK Power Networks and ChargePoint Services, the 3-year, £7 million project will see 135 V2G chargers rolled out on the UK’s electricity grid. EV drivers will be able to access a special V2G bundle when leasing a V2G compatible car.

A two-way charger will enable the driver to charge their vehicle intelligently, using their vehicle battery to power their home during peak times or sell spare power back to the grid. The project will also focus on the role of EVs in delivering flexibility services to the local network. Open Energi’s Dynamic Demand 2.0 technology will aggregate the cars’ battery power to integrate domestic V2G into UK Power Networks’ flexibility services.  Together, we aim to demonstrate the benefits of using EVs to support the grid and reduce costs for drivers.

It’s clear that V2X unlocks a huge opportunity for energy systems globally – with the potential to create a volume of ‘storage on wheels’ that will ultimately eclipse grid-scale and behind-the-meter batter storage many times over. Depending on how we shape regulation, develop technology and create new business models, this huge amount of flexible storage potential could be captured to lower the cost of car ownership, power our homes, and operate our electricity network more efficiently, whilst accelerating our transition to a net zero carbon future.

Flexibility a valuable opportunity for CHPs

CHP

Combined Heat and Power (CHP) units are helping businesses to reduce costs and carbon and boost energy security but could be missing out on valuable flexibility revenues. Alana O’Neill, Senior Business Development Manager at Open Energi, explores the opportunity.

CHPs have an important role to play in the UK’s transition to a sustainable energy system and are being adopted by a growing number of businesses across the UK to help reduce energy costs, boost energy security and support carbon reduction efforts.

A 2017 ADE report found that over 2,000 businesses across the UK had already invested in the technology, saving an estimated £375m annually. These CHPs are already generating around 5.7GW of electricity for a wide range of industries, from brewing and paper manufacturing through to hospitals and water utilities, and this could rise to 15GW by 2025.

One part of CHPs’ appeal is they are very flexible assets which provide a controllable source of on-site electricity generation and heat. This controllability means CHPs are also an ideal asset for participating in flexibility markets and can increase or decrease generation to help businesses reduce overall electricity costs. However, as this is not their primary purpose, CHPs are often not optimised against electricity prices or other market signals, which means they could be missing out on significant value.

Unlocking flexibility value

Open Energi’s analysis suggests that fully optimised, a CHP unit has the potential to earn around £20-35,000 per MW of installed capacity annually through a combination of flexibility services:

  • Peak price management – increasing CHP generation during peak periods (4-7pm) means sites can reduce demand from (or export to) the grid and reduce the cost of (or benefit from) Triad, DUoS charges and the CM Levy*.
  • Balancing services – CHPs can provide a combination of balancing services, including firm frequency response (FFR) and demand turn-up (DTU) to National Grid and earn revenue in return for increasing or decreasing generation to help balance electricity supply and demand.
  • Energy trading – CHPs can take advantage of price arbitrage opportunities in wholesale and imbalance markets to make money and cut costs. The scope of this will be determined by the supply contract or PPA in place, but the opportunity is expected to grow as price volatility increases with growing renewable generation.
  • Local markets – Distribution Network Operators (DNOs) are starting to procure flexible capacity locally – most have now signed up to the Piclo Flex platform as their route to market – offering a new revenue stream to CHP owners able to help DNOs manage constraints on the network and avoid reinforcement costs.
  • Capacity Market – exporting CHPs which aren’t receiving subsidies under the Renewable Obligation scheme are eligible for the Government’s Capacity Market scheme, which pays providers of capacity for being available to respond when the system is under stress*.

Site factors to consider

There are lots of factors that need to be considered when building a business case for CHPs.

  • Biogas or gas grid connected – The ADE suggests that over 2,000 businesses or sites across the UK have CHP units installed, and latest data from Ofgem indicates that there are around 450 which are renewably powered. Sites reliant on biogas will face different constraints and challenges when it comes to managing generation and providing flexible capacity including the availability of gas storage.
  • Behind or in front of-the-meter – CHPs supplying on-site demand (known as behind-the-meter) will have a different business case than front-of-the-meter sites e.g. AD plants, which are solely exporting. The former can unlock more value from reducing site demand but may be more constrained in other ways.
  • CHP location – Peak prices vary across Distribution Networks, so this can affect the business case.
  • Heat demand – Requirements for on-site heat demand are also an important factor in determining how much flexibility a CHP unit can provide.

Of course the primary concern of any site operator is that asset performance and lifetime will not be affected by asking CHP engines to perform flexibility services. The importance of understanding site characteristics and asset constraints cannot be understated. Building strategies that can deliver value automatically while working within these is key.

Open Energi’s Dynamic Demand 2.0 platform does just this – automatically optimising a CHP’s operation to maximise value from flexibility markets without impacting overall performance or asset lifetime. The platform uses artificial intelligence to coordinate site demand and generation and deliver an invisible service that takes a holistic view of energy optimisation.  To date the platform has connected over 3,500 assets UK-wide and performed over 60 million switches – operating invisibly deep within customer processes without once affecting site operations.

Future outlook

As the UK energy industry shifts to a more decentralised, digitalised and decarbonised future the need for flexible services to help manage the system is growing. Market regulations and policy are playing catch up as the Government seeks to deliver the £40bn of value identified by its Smart Systems and Flexibility plan. Significant reforms are expected to network charges and market access over the next 18 months. With the right technology in place, companies with CHPs will be well placed to take advantage of these opportunities and play an important role in creating a cleaner, more affordable energy future.

Codford Biogas case study: for more information on Open Energi’s work with CHP units read our case study with Codford Biogas, who are recycling food waste to provide almost 4MW of renewable generation.

Contact: Alana O’Neill – alana.oneill@openenergi.com / 07468 700796

*On the 15/11/18 the Capacity Market was temporarily suspended after an EU ruling against the European Commission. This means the CM has entered a ‘standstill period’ which prevents any CM auctions being held or payments being made until the scheme is reapproved. You can find more from National Grid on CM payments and the upcoming CM auctions here, and BEIS’ most recent proposals here.

How greater flexibility can help UK deliver 50% renewables by 2030

electricity pylons

The National Infrastructure Commission (NIC) recently published its first National Infrastructure Assessment (NIA), setting out a strategy for the UK’s economic infrastructure from 2020 to 2050. A key focus is decarbonising the UK’s energy supply and the report recommends 50% of generation is supplied by renewable power by 2030, with the UK’s electricity supply almost entirely zero-carbon – thanks to nuclear and renewables – by 2050. But how can we integrate this level of renewables cost-effectively, and what do we do when the sun doesn’t shine, and the wind doesn’t blow? Wendel Hortop, Commercial Analyst at Open Energi, explores the role of flexibility in enabling the UK’s transition to a zero-carbon energy system.

What would such high levels of renewables mean for the energy system?

The UK is on track to power 50% of our electricity supply with renewable generation by 2030 but this level of renewables creates some very specific challenges. Solar and wind, which would form most of new renewable capacity, are highly inflexible – energy is only generated when the sun is shining, or wind is blowing. Despite increasingly accurate forecasting, this inflexibility introduces short-term (balancing electricity supply and demand within a given half-hour) and long-term (what to do when wind and/or solar output is low for hours or days at a time) challenges, and reduces the level of inertia on the grid, resulting in much quicker changes in system frequency – which must be managed to ensure power keeps flowing.

Flexibility can help to address these impacts cost-effectively – reducing total system spending by between £1-7bn per year – and enable the UK to integrate renewable generation at the scale required by the NIC assessment.

Flexibility can deliver significant cost reductions in in a high renewable system

Source: Open Energi
Source: Aurora Energy Research

 What role does flexibility have to play?

The majority of system balancing occurs through the energy market in response to energy prices visible over different timescales, of which the last resort is the imbalance price. Energy generators and suppliers forecast their half-hourly energy usage and provide this to National Grid, who then take action to correct any differences between forecast and actual energy usage. Anyone out of balance in a way which harms the system pays a penalty, whilst the opposite is also true – putting yourself in imbalance to benefit the system gets rewarded. The imbalance price (or System Price) is not known until afterwards so predicting and reacting to it allows energy users to help the grid and be rewarded; increasingly trading teams at big suppliers are looking to their customers to help manage this.

Open Energi are already responding to the imbalance price by flexing loads through signals from suppliers, such as Ørsted’s Renewable Balancing Reserve. Increased renewable generation on the grid will increase the likelihood of system imbalances, and the incentive to respond.

Flexible loads can respond in real-time to predicted system prices

Flexible loads can respond in real-time
Source: Open Energi

The wholesale market doesn’t balance all supply and demand so National Grid look to the suite of services they procure to do the rest. For example, frequency response services fine tune the system balance and provide a ‘first line of defence’ after large generation outages.

Demand flexibility is already an established tool in helping to balance frequency on the grid via the Firm Frequency Response market. Inertia levels falling means faster frequency response is needed. Lithium-ion batteries are perfect for delivering this, whilst some forms of demand flexibility can also respond at the required speed. National Grid is developing a Faster Acting Frequency Response product which will allow loads capable of responding quickly enough to participate and will procure a mix of assets capable of tracking frequency (such as batteries) and those capable of delivering large shifts in demand almost instantaneously (such as large industrial processes).

Longer term shortfalls in generation introduce a new challenge for flexibility

The more significant challenge is in longer periods of low wind and solar generation. Increased interconnection with Europe will help but demand flexibility can again play a key role.

Frequency response has tended to focus on energy flexibility within a half-hour period, however many processes have inherent energy storage of hours or even days. Water pumps, heating and CHPs are all assets which can shift demand over long periods. The signals to do so come from the market – low renewable generation leads to increased wholesale energy prices, and vice versa. As wholesale energy prices can be known a day ahead, a load can be optimised in advance to increase consumption when prices are lowest, and reduce consumption when prices are high.

Many flexible processes have hours or even days of energy storage
 

Many flexible loads have hours or even days of storage
Source: Open Energi

Advances in storage technology will also assist with this longer duration requirement for flexibility. Technologies such as vanadium flow batteries can provide over 4 hours of energy storage and can help balance sustained periods of low or high renewable generation as well as providing short-term frequency response and price arbitrage.

Aggregation of assets such as these, diverse in both location and technology, will help to tackle longer periods by spreading the requirement for flexibility. Digitalised platforms that use artificial intelligence (AI), statistics and probability can schedule and manage asset behaviour to deliver the optimal amount of flexible capacity.

As we look to 2030, increased adoption of electric vehicles (EVs) will also come into play, either through smart charging or vehicle-to-grid (V2G) charging. In their latest Future Energy Scenarios report National Grid predict we could have over 10 million electric vehicles in 2030, and over 35 million in 2040 – a huge number of flexible, distributed assets.

Smart charging will allow EV charging to be modulated or staggered to avoid surges in consumption or shifted to times of day when demand is low, reducing the infrastructure required to support them. Aurora Energy Research estimate that smart charging can reduce the level of generating capacity required in 2050 by up to 22GW in a high renewables system. Meanwhile V2G charging introduces possibilities such as taking households off-grid during peak periods – Open Energi are part of the PowerLoop consortium exploring this and other potential V2G applications.

Smart charging significantly reduces the need for flexible generating capacity

Source: Aurora Energy Research
Source: Aurora Energy Research

Decarbonisation of heat will introduce new sources of flexibility

One common process with very high levels of inherent storage is heating; however the UK’s reliance on gas means potential flexibility which could be offered to the electricity system is currently limited. Looking forward the decarbonisation of heat therefore offers long-term opportunities, whether this comes through electrification or a transition to hydrogen and district heating.

Switching to heat pumps would introduce a large but flexible energy load into the system with significant storage potential. Coupled with smart meters and other advances in technology this could lead to a highly distributed source of flexibility for the grid, just as with the shift to electric vehicles.

Hydrogen powered heating – produced via electrolysis – is an energy-intensive but flexible process, which alongside district heating networks would likely lead to many more CHPs – which offer short and long term flexible capacity.

Technology will play an important role in delivering this flexibility

The NIA shows that flexibility has a key role to play in delivering or surpassing our carbon targets. As renewable generation increases significantly so will the need for flexibility. We already have many of the solutions we need – the real challenge is rolling these out at the required scale and speed.

This is where AI and cloud computing can come into their own. Aggregation of larger and larger portfolios of diverse loads will require the behaviour of each of these individual loads to be optimised and controlled in real-time in response to the requirements of the system. Meanwhile the move to smaller, distributed loads, including those on a domestic scale such as electric vehicles, will rely heavily on cloud computing with dispatch instructions delivered over the internet and loads communicating their behaviour with the platform and each other.

Ultimately these solutions can give rise to an autonomous, self-balancing grid which operates incredibly cheaply. Open Energi are leading this transition, connecting, aggregating and optimising distributed energy resources in real-time, to create a more sustainable energy future.

Power Responsive success stories: South Mimms battery storage and EV charging

At South Mimms Motorway Services, Open Energi own and operate a 250kW/500kWh Powerpack alongside one of Tesla’s largest and busiest UK charging locations. The project, which is one of the first of its kind globally, was selected as a demand side flexibility success story and showcased by National Grid at their 2018 Power Responsive summer reception.

The Supercharger site can charge up to 12 cars at one time, and since popular charging periods often coincide with peak periods of grid demand – between 4pm and 7pm, when electricity prices are at their highest – flexible solutions are needed to ease the strain on local grids and control electricity costs.

Integrating a Powerpack at the location has meant that during peak periods, vehicles can charge from Powerpack instead of drawing power from the grid. Throughout the remainder of the day, the Powerpack system charges from and discharges to the grid, providing a Firm Frequency Response (FFR) service to National Grid and earning revenue for balancing grid electricity supply and demand on a second-by-second basis.

Combining batteries and electric vehicles makes vehicle charging part of the solution to integrating more renewables without affecting drivers, unlocking vital flexibility to help build a smarter, more sustainable system.

Robyn Lucas, Head of Data Science at Open Energi explained “[the battery] provides a source of flexibility to what is otherwise a very inflexible demand. We do frequency response for most of the time, and over the peak period we use the battery to charge the car up, rather than them charging from the grid.

“Open Energi hope to repeat this blueprint with multiple other stationary storage assets next to EV charging stations. Having stationary storage assets used in this way allows both transport and electricity networks to be decarbonised and allows for greater renewable penetration.”

Power Responsive success stories: Aggregate Industries

National Grid’s Summer Reception 2018 profiled Aggregate Industries’ pioneering partnership with Open Energi as an example of real life achievements to unlock demand side flexibility and the innovation and collaboration within the industry.

Aggregate Industries is the first business to deploy Open Energi’s artificial intelligence-powered flexibility platform, Dynamic Demand 2.0, to deliver electricity cost savings of 10%.

40 bitumen tanks at ten Aggregate Industries’ sites UK-wide have already been connected to the platform, which uses artificial intelligence to automatically optimise their daily electricity use in response to a variety of signals, including wholesale electricity prices, peak price charges, fluctuations in grid frequency, and system imbalance prices.

Aggregate Industries is accessing the imbalance market via Renewable Balancing Reserve (RBR), a product offered by its renewable electricity supplier, Ørsted. RBR enables Aggregate Industries to tap into the financial benefits of participating in the imbalance market, by reducing its demand at certain times.

Over time Aggregate Industries plans to expand its use of Dynamic Demand 2.0 to 48 asphalt plants UK-wide – representing up to 4.5MW of demand flexibility. It is also exploring its wider portfolio of assets and processes to identify where further benefits may lie.

Talking to National Grid, Richard Eaton, Energy Manager at Aggregate Industries explained: “What we’re doing now is rolling out Open Energi’s Dynamic Demand 2.0 platform, where what we do is we flex our assets, not only to calls from National Grid, but also now to calls from Ørsted under their Renewable Balancing Reserve.

“The artificial intelligence within Dynamic Demand 2.0 is helping us to optimise our bitumen tanks leading to a predicted 10-15% reduction in the operating costs of those assets.”

How the rise of ‘Energy as a Service’ can power decarbonisation

open energi wind farm

Energy as a Service is the latest business model innovation to arrive in the energy supply industry. In short it is all about moving away from buying energy on a per unit (p/kWh) basis and moving towards a fixed fee per month within certain volume thresholds; akin to how we pay for mobile phone contracts. Energy as a Service has emerged off the back of disruption to the way we supply, consume and now ultimately buy energy, which has fundamentally changed energy market economics.

This disruption is the result of four major technology-driven trends:

  • Decarbonisation – The growth of energy supply from zero marginal cost renewable resources
  • Decentralisation – The growth in energy generated from smaller scale low carbon resources either on customer sites (Behind-the-Meter) or at the Distribution Level (Distributed Energy)
  • Digitisation – The ability to measure and monitor machine behaviour in real-time and automate how we use and supply energy
  • Democratisation – The rise in consumer participation, control and choice which is increasingly determining how energy is bought and used

Traditional per unit models work where the dominant cost in delivery of the product or service scales according to the volume used. This was true when the majority of power supplied came from sources that required a fuel input e.g. coal and gas. The more energy consumed the greater the proportional cost of buying and burning that fuel to generate more kWhs of power.  Other components which make up the total ‘at-the-meter’ price have also been charged on a per unit basis to ensure those who use more of the electricity network pay more for it; government taxes, utility profit margins and network charges (with some time-of-use element).

However, when you start to use zero marginal cost power the economics get flipped on their head. Renewable ‘fuel’ is free, so the dominant cost in consuming energy becomes the infrastructure needed to deliver it. Wind turbines, PV panels, transmission and distribution cables have low operational costs once built, so the initial capital expenditure is where the dominant cost lies.

Across Europe average wholesale prices now reflect wind and sun patterns more than the cost of coal and gas, and at periods of low demand and high renewable output we consistently see negative prices. Clearly change is needed as consuming more energy at these times is beneficial to the whole system but a per unit charging mechanism disincentivises users from doing that.

Enter, Energy as a Service. Already we are seeing a shift in network charging towards capacity-based charges instead of use-of-system charges. Wholesale prices are not far behind; the task becomes providing the flexibility to firm up renewable output. Thanks to the digital revolution described above this flexibility can come from consumers’ demand, cost-effectively tapping into flexibility inherent in distributed energy resources behind-the-meter.

Take a given offshore wind site, with known capacity factors of about 50%. It is possible to quantify the amount of flexible energy needed to ensure 99% of customer demand is met at all times. Using existing business assets means it is possible to take advantage of zero marginal cost flexibility in everyday processes (such as heating, cooling, pumping, battery storage and CHPs), avoid unnecessary infrastructure upgrades and minimise efficiency losses in transporting power. Once it is understood how much flexible power is needed to firm up the output of renewable generation the next task is what technologies do you use to meet that flexibility requirement.

Artificial intelligence-powered flexibility platforms – like Open Energi’s Dynamic Demand 2.0 technology – which can manage distributed energy resources in real-time, are critical. They can evaluate the amount of flexibility in existing power-consuming assets and processes – in addition to any battery storage and/or flexible generation (such as CHPs) – and map demand to supply. This then becomes a constant, real-time scheduling problem for the platform to manage; invisibly ramping processes up when wind is abundant and storing as much power as possible, or turning processes down to a stable minimum and discharging batteries or using a CHP when wind output is low.  If real-time scheduling isn’t maintained, the cost structure breaks down, so the reliability of these platforms is critical.

What is important to recognise here is that below a certain demand threshold the marginal cost of putting in place this service is the cost of operating the wind and the software required to schedule behind-the-meter flexibility. This is why Europe’s utilities are making huge investments and acquisitions in virtual power plant technology.

By doing so the costs of delivering energy become fixed and predictable and scale with size of connection instead of actual usage. Exactly like the mobile phone industry where the marginal cost of sending a packet of data is immaterial in comparison to network costs of all infrastructure.

For Open Energi Energy as a Service has always been the natural end-game in maximising the value of Demand Response. It shelters consumers from the continuously changing and complex incentives of the existing Demand Response markets, and instead offers a simple proposition: “By installing demand response software across a range of assets you can pay a lower fixed monthly fee for your energy”.

The clarity and certainty offered by Energy as a Service makes it easy to structure simple, long-term financing solutions for different technologies – e.g. solar PV, energy storage, CHP – and allows businesses to concentrate on what they do best.  All the complexities of power procurement and demand response markets are removed in place of a known fixed fee per month that ensures reliable, clean and affordable energy. 

David Hill, Commercial Director, Open Energi

This blog was originally posted on Current News.

Discover the value of your demand flexibility – explore our VR world!

Open Energi VR landscape

Your electricity demand may be more flexible than you realise. Our analysis suggests that on average up to 50% of a business’ electricity demand can be shifted for up to one hour, with zero disruption to operational performance.

This flexibility is vital to support more renewable power and create a sustainable energy future.

In the UK, it’s created a £9 billion market opportunity. But how much could it be worth to your business?

Explore our Virtual Reality world to find out:

vr.openenergi.com 

Open Energi’s Flexible Energy Survey service provides an accurate, independent assessment of your site’s total demand flexibility and the commercial opportunity it represents for your business.

It includes:

  • Comprehensive site survey carried out by qualified engineers with unique experience assessing distributed energy resources for demand-side incentives.
  • Detailed feasibility report identifying the total flexibility of your site, asset-specific strategies, integration solutions and commercial benefits.

For more details or to arrange a survey, please get in touch.

Open Energi VR works well on desktop, better on mobile and best with a VR headset. Please note, the figures used in this VR are based on current market data and Open Energi’s experience with similar assets and processes across a wide range of sectors. They are intended only as a guide and are no guarantee of future value.

 

Why precision matters for Triad prediction

United Utilities Davyhulme

National Grid recently confirmed the Triad dates for Winter 2017-18. As most businesses know all too well, consuming electricity during a Triad is extremely costly, so accurately predicting and avoiding these three half-hour peak periods is vital. Open Energi’s machine learning approach correctly predicted the specific half-hour Settlement Period (SP) for all three Triad days in 2017-18. Wouter Kimman, Data Scientist at Open Energi, looks back at what happened this year, the growing need for precision forecasting, and what the future may hold.

Triad season 2017-18

The demand patterns and Triad results seen in 2017-18 demonstrate the strength of the Triad incentive. But, as more businesses shift their demand making the ‘peak’ flatter, identifying the right SP is becoming more of a challenge.

The 2017-18 Triads all occurred on a Monday, but with a different SP for each, spanning 35 (5-5.30pm), 36 (5.30-6pm) and 37 (6-6.30pm) by order of date; see Figure 1. The 26 February was the latest Triad to date and only the second time it has fallen in SP 37. Given that historically, 85% of Triads have fallen within SP 35, this represents quite a shift.

 

Triads 2017-18
Figure 1: Triads for the winter of 2017-2018 as published by National Grid

 

The trend for falling overall electricity demand continued, with all three Triad days below 50GW. Comparing the daily peak figures to previous winters (Figure 2) we see the spread between the extremes (lowest and highest daily peak) was also reduced, with peak demand more concentrated around the average 45 GW.

 

Triads 2017-18 demand
Figure 2: Peak demand figures comparing all winters since 2011. Each dot represents a day, and box plots represent the minimum, first quartile, median, third quartile, and maximum of their distribution in demand.

However, quite possibly due to Triad avoidance techniques, the timings of daily peaks were spread out across the evening period, including many more during SP 34. Comparing days with peak demand greater than 46 GW in the last 2 winters to previous years in Figure 3, this past winter had a profoundly different pattern; even compared to last winter, shown on the left.

 

Shift in Settlement Periods
Figure 3: The shift in the SP with the highest national demand from previous winters to this winter. A much broader spread is seen this year, evidence of wide spread Triad avoidance strategies?

Another clear example of the impact of Triad avoidance was provided by the Beast from the East, which gave rise to an exceptional late and severe cold spell. This year’s largest demand peak actually fell on 1 March, just outside the Triad season. The demand profile for that day (Figure 4) shows a very distinct peak, much more characteristic of days of low demand, outside the winter. In contrast, days with high demand within the Triad season had a flatter peak, as seen in Figure 4. As more behind-the-meter flexibility comes on-line the impact of Triad avoidance will continue to be seen on the national daily demand profile, making predictions ever more difficult.

 

Daily national demand profile
Figure 4: Daily national demand profile of various days throughout the 2017-2018 winter, and the 1st March. A very different profile is seen outside of Triad season.

 

Triad Predictions

These shifts in the national daily demand show how successful businesses have been at avoiding Triad periods, aided by increasingly sophisticated strategies. Triad management can now be automated and optimised according to a site’s specific energy profile (and the company’s risk appetite). Using Open Energi’s Dynamic Demand 2.0, our cutting edge machine learning approach enables companies to precisely target a specific SP, minimising calls, disruption, and manual intervention.

As many of our customer’s operations are not able to switch off for long periods of time without disruption (e.g. bitumen tanks that need occasional heating to stay within temperature setpoints, or sewage treatment plants that have a continuous usage pattern) there is considerable value in precisely identifying the 30-minute window in which they should reduce demand. Knowing exactly when a Triad might start allows us to manage equipment to avoid impacting operational performance; Triads can be successfully avoided without allowing processes to violate their permitted control parameter ranges.

For batteries of limited storage duration, this can be even more significant as they can export to the grid during peak-prices. Depending on their capacity, it can be vital to issue a dispatch at the right time, ensuring the system has sufficient state of charge to realise maximum revenue.

To minimise the number of unnecessary calls, Open Energi updates the prediction during the day, given the latest information. An initial prediction gives a good indication of the likelihood of a Triad occuring, and over the season gives rise to around 20 warnings. During the day we then update our prediction, exploiting available real-time data. This allows us to cut the total number of Triad calls in half, while accounting for the uncertainties involved. By using the latest machine learning techniques, and real-time automated dispatch, over the course of a year the total number of Triad calls can be thus be reduced; disruption is reduced while value is maintained.

 

Figure 5: Open Energi’s Triad Settlement Period prediction on the three Triad days
Figure 5: Open Energi’s Triad Settlement Period prediction on the three Triad days


O
utlook for Triads

The electricity system must be able to meet peak demand; enough investment in the network must be provided in order that it can deliver the peak amount of electricity to homes and businesses. Triads are the current way that the transmission network is paid for. At present, there is a significant advantage to businesses in reducing their demand at peak, and as a result, the system peak has reduced. In theory at least (while the price signal exists), less copper is required.

While businesses are focused on avoiding Triad costs, Ofgem is increasingly concerned that their success is creating an unfair charging system, where those least able to afford the cost of the network (i.e. less well-off domestic users) end up paying more than their fair share. Consequently, Ofgem is in the middle of a network charging review expected to result in changes to the Triad system from April 2020. Its intention is to create a fairer charging structure where large, non-domestic users cannot avoid paying their fair share of network costs.

In the meantime, Winter 2018-19 will see two charging reforms coming into effect; updates to Distribution use of System (DUoS) charging and the start of embedded benefit reform. DUoS charges are being ‘flattened out’ across the day, while Triad payments for exporting from distributed generation will reduce gradually from £47/kW to £3.22/kW over the next three years.

As the policy landscape continues to shift – and new markets emerge – we expect the task of managing behind-the-meter flexibility to deliver value becoming an increasingly intricate exercise. The ability to manage demand and generation assets in real-time, according to different site characteristics and constraints, will be crucial to choosing the right course of action to maximise client value.

By Wouter Kimman, Data Scientist, Open Energi

Innovative research project aims to support greater local integration of Solar PV

solar panels

Increasing levels of solar PV are having a growing impact on the operation of the low voltage (LV) network. The need for new grid connections has impacted project viability and in some areas of the country Distribution Network Operators (DNOs) have been forced to limit new solar integration. However, new technologies are introducing ways to make smarter use of the abundant free energy provided by the sun and deliver new revenue streams, without the need for costly infrastructure upgrades.

Funded by Innovate UK, this innovative research project aims to support greater solar PV integration, by forecasting solar output in near-time with better accuracy, and enabling generation to interact dynamically with demand.

In the South West of England, where these challenges are particularly acute due to a constrained network, Meniscus Systems, BRE National Solar Centre, Cornwall Council and Open Energi are collaborating to create short-interval (every 5 minutes), location-specific solar intensity and power predictions that will improve local grid operation, optimise the performance of solar farms and enable operators to participate in Demand Side Response (DSR) schemes to maximise revenue, with or without energy storage.

Cornwall has the fewest grid interconnections with the largest solar PV installed capacity – over 475MW of large-scale (1MW+) solar farms – leading to network operating problems. Resulting constraints imposed by the DNO make it harder to connect large scale renewable generation. The ability to better predict and manage the performance of solar PV on the LV network is an important step towards the creation of local energy markets, and will help to ensure that Cornwall’s residents, communities and local economy benefit from the low carbon energy transition.

The project will make use of:

  • Real-time and historic satellite based imagery to predict solar intensity for any location at intervals of 5 minutes on an hour ahead basis.
  • Historic and near real-time PV data from the Cornwall Council solar farm at Cornwall Airport Newquay (CAN) to test and demonstrate the system and explore the role of on-site battery storage.
  • Open Energi’s expertise to deliver accurate, real-time PV-based DSR solutions to DNOs and owner/operators of solar farms to more efficiently manage local networks.

Accurately modelling the commercial benefits of solar PV and battery storage will be an important aspect of the project. If predicted solar generation is higher than the export limit of the site, a battery can be charged instead of curtailing generation, discharged to grid during a later period of high demand, and in the meantime the battery can be employed for DSR. For a site with no installed storage, generation can be curtailed at times when the network is constrained in response to DSR signals, such as Demand Turn-Up. Accurate predictions allow the DNO or Transmission System Operator (National Grid) to efficiently manage their network

With the UK’s solar capacity forecast to rise to 15.7GW by 2020 – from just over 9.3GW at present – using advanced technology to more efficiently integrate and optimise solar PV sites is vital to create a more sustainable energy future. Due for completion in early 2019, this project aims to pave the way for the smarter use of solar PV via peer-to-peer energy markets that benefit local communities, delivering a smarter, more flexible energy system across the UK.

The lead Project Team comprise:

  • Meniscus Systems – Project Lead and delivery of solar intensity predictions in a form that will allow integration with the DSR market.
  • Cornwall Council – owner/operator of solar farm which will be used to test and demonstrate the system.
  • BRE National Solar Centre – responsible for ensuring the system meets the requirements of the PV industry and validating the system’s performance.
  • Open Energi – DSR aggregator responsible for identifying DSR revenue opportunities and systems needed to deliver this capability.

For more details, please get in touch.

Robyn Lucas is Head of Data Science, Open Energi

2017 in review: breakthrough tech and tumbling renewable records demand greater flexibility

2017 was a year of dramatic change in the UK electricity market. Overall, total UK electricity consumption fell 2.8% compared to the previous year: 264 TWh compared to 272 TWh in 2016[1]. This follows the long-term trend of decreasing peak and total yearly energy use, while the proportion of renewable generation continued to rise: 2017 smashed 13 clean energy records, low carbon generation exceeded fossil fuels, and the resulting trend for negative prices (as recent as last week in Germany thanks to high wind) looks set to continue.

Last year also saw a fall in the strike price for new offshore wind power to £57.50/MWh. Considering the government’s guaranteed price for Hinkley Point C is £92.50/MWh, it highlights just how competitive renewables, and particularly offshore wind, now are. However, the system must be able to cope with the intermittency that all this cheap, carbon-free power brings.

Figure 1 shows the huge variation in demand over the year: from peaks of nearly 50GW on winter evenings, to troughs of around 17GW on summer nights. Figure 2 shows the average daily profile of consumption. In 2017, the prize for peak demand goes to January 26th, which came in at 49.76 GW at 6pm. Compare this to the profile of June 11th, the day that the UK used the least energy: at 5am, it was 16.57 GW. This swing of over 30 GW presents many challenges for the system operator as more and more of the generation becomes intermittent and demand patterns shift: there is value in being flexible with one’s electricity consumption.

 

Figure 1. Daily demand over the year, and smoothed trend over the year.
Figure 1. Daily demand over the year, and smoothed trend over the year.

 

Figure 2. Peak and lowest demand of 2017, compared to the average daily profile.
Figure 2. Peak and lowest demand of 2017, compared to the average daily profile.

Historically, our electricity system has been built to cope with the peaks; and paying for this network accounts for around 30% of your electricity bill (and rising). What if, by being a bit smarter about when we use our electricity, we could flatten the swing out a little? Or better still, align it to renewable generation?

This is where demand flexibility comes in, empowering consumers and playing a vital role in providing the responsiveness needed to cope with huge swings in renewable generation as it makes up more and more of the UK’s generation mix.

Transforming the network

2017 will be known as the break-through year of batteries and electric vehicles (EVs). With the dramatic fall in battery prices we’ve seen a rush of parties buying up battery capacity, hoping to profit from what were lucrative flexibility markets. National Grid have seen batteries flooding into the Firm Frequency Response (FFR) market, attempting to secure profitable long-term contracts to satisfy investors. Market dynamics mean this is increasingly challenging. In a rapidly changing marketplace, a variety of revenue streams must be considered. Battery operation must encapsulate multiple markets to insure against future movements and maximise profits, while ensuring safe and careful operation of the asset such that state of charge, warranty, and connection limits are respected, an area where Open Energi has significant expertise.

EV take-up is accelerating more quickly than many estimated – UK sales of EVs and plug-in hybrids were up 27% in 2017 – and the need for managing this additional demand in a smart, automated way is crucial to alleviate strain on local networks. We have explored the enormous potential of EVs to provide flexible grid capacity and are working with a consortium to deliver the UK’s first domestic V2G trial.

While in the short term, as the big electricity players try to keep up with the changing needs of the system, flexibility markets present a degree of uncertainty, the long term need for demand-side response (DSR) and frequency regulation cannot be underestimated.

Grid Frequency and FFR

As the System Operator, National Grid must maintain a stable grid frequency of 50Hz. Generation and demand on the system must be balanced on a second-by-second basis to ensure power suppliers are maintained. Traditional thermal plant operates with physically rotating turbines, which carry physical inertia and act to stabilise the frequency. With the increase in generation from non-inertial sources (e.g. wind turbines, which don’t carry inertia in the same way, and PV cells), this stability is reduced. Larger deviations in frequency can result in the event of a power station, or interconnector trip, for example.

During 2017, the largest low frequency event (demand greater than supply) occurred on 13th July, when it dropped to 49.57Hz. Given that National Grid’s mandate is to keep it within 0.5Hz of 50Hz, this was rather close! Figure 3 shows the period, and we see a sudden drop in frequency which typically indicates the trip of a significant generator. In this case, the fault was at the French interconnector. Here, what usually functions to improve energy continuity and smoothen geographical variations in supply was the culprit for the biggest second-by-second imbalance in 2017!

The largest high frequency event (supply greater than demand), during which frequency reached 50.41Hz, occurred at the end of October, was much more gradual and seems to have been due to a combination of several effects. Demand typically drops quite steeply this late in the day, so large CCGT plants are reducing their output and on this occasion a sudden drop in wind-generation seemed to have been over-compensated by pumped storage.

Figure 3. Lowest and Highest frequency extremes in 2017.
Figure 3. Lowest and Highest frequency extremes in 2017.

As well as these relatively rare large frequency events, there are excursions that can last for several hours. Figure 4 shows two periods where the frequency deviated from 50 Hz. In general, the average frequency is 50Hz, and therefore any response to frequency regulation averages out to zero. However, over these medium-term time periods the average frequency is not 50Hz. For flexible assets like batteries, that are dynamically responding to correct grid frequency during such periods (performing FFR) the state of charge is affected.

For this reason, the state of charge of the battery must be actively, and automatically, managed – so that optimal state of charge is quickly recovered after such events. The battery is then able to continue to perform FFR, or other services such as peak price avoidance or price arbitrage in wholesale markets. The state of charge (bottom panels in Figure 4) can also have strict warranty limits set by the manufacturer.

Figure 4: Extended frequency events and impact on battery state of charge
Figure 4: Extended frequency events and impact on battery state of charge

Interestingly, 2017 saw an increase in both the number of frequency events (usually defined as frequency excursions larger than 0.2Hz away from 50Hz), and frequency mileage (defined as the cumulative deviation of the grid frequency away from 50 Hz), shown in Figure 5, particularly during the spring and autumn.

Could this be due to the large, somewhat unknown amount of PV on the system? It is distributed, meaning National Grid see PV generation as a fall in demand; they also have no control over it (unlike most other generation). PV efficiency is high in cold weather, so perhaps unexpectedly high and erratic solar generation on cold, sunny days in the Spring and Autumn led to a more unstable system this year, compared to 2016.

Figure 5. The grid has experienced more mileage and more events in 2016 than 2017, especially in March and October. Frequency “event” here is defined as a deviation of 0.1 Hz around 50Hz.
Figure 5. The grid has experienced more mileage and more events in 2016 than 2017, especially in March and October. Frequency “event” here is defined as a deviation of 0.1 Hz around 50Hz.

Figure 5. The grid has experienced more mileage and more events in 2016 than 2017, especially in March and October. Frequency “event” here is defined as a deviation of 0.1 Hz around 50Hz.

The rise of distributed generation, accelerating EV uptake, and plunging battery storage costs, are all driving a rapid transformation in the UK’s electricity system.  Managing these changes requires new approaches.  Demand-side response technologies, like Open Energi’s Dynamic Demand 2.0 platform, mean patterns of demand can be shifted in a completely carbon neutral way; enabling electricity to be consumed when it’s being generated: as the wind blows, or the sun shines. Rather than inefficiently changing the output of a gas fired power station to meet demand, we can make smart changes in demand up and down the country to meet generation, deliver local flexibility, and put consumers in control of their energy bills: delivering completely invisible, completely automated, intelligent DSR which paves the way for a more sustainable energy future.

By Wouter Kimman, Data Scientist, Open Energi

[1] For demand here and throughout this post we use INDO values as reported by ELEXON Ltd.