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moneyThe capacity market auction specifically for turn down demand-side response has cleared between £45 and £50/kW, according to the EMR delivery body. The exact clearing price will be published at 7pm. Updated: Clearing price is £45/kW/yr.

The result is around double that anticipated by some market participants, and much higher than last year’s Transitional Auction, which cleared at £27.50/kW. Smartest Energy, which was vying for around 100MW of contracts, suggested it would clear at around £25/kW.

Screen Shot 2017-03-22 at 16.25.13

National Grid aimed to procure around 300MW, but had leeway to procure up to 500MW if the price fell significantly.

Given that only 373MW of turn down DSR was bidding for contracts, the outturn is perhaps unsurprising. It does, however, provide an indication of the volume of turn down DSR in the market, which had previously been an unknown quantity. According to Energyst Media’s end user surveys, the vast majority of demand-side response comes from generation technologies.

Today’s auction was the last set aside purely for turn down DSR. The now defunct Energy and Climate Change Committee urged the government to create policy that favours turn down demand side response over decentralised diesel generation in its final report. Such an approach, via a mooted merit order, would be more environmentally friendly. But it would significantly reduce the current DSR market that is able to contribute to security of supply.

Regulator Ofgem has recently issued proposals that would make engine farms less competitive in the capacity market, but other market participants, such as Flexitricity founder Alastair Martin, believe there is a simpler fix for a market that has failed to deliver a single large scale new build combined cycle gas turbine.

Update: 19:00 22/03/17: headline updated to reflect actual clearing price.

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Owens: Unlock DSR by levelling playing field

Owens: Unlock DSR by levelling playing field

The capacity market auction specifically for turn down demand-side response (DSR) will likely clear around £25/kW, according to Smartest Energy. The so-called Transitional Arrangement (TA) auction, which begins tomorrow, has a target of 300MW, although it could technically procure up to 500MW if the outturn is drastically lower than anticipated.

Robert Owens, VP Asset Optimisation at the supplier and aggregator, has urged policymakers to create a level playing field for DSR, fearing that it will struggle to compete with generation technologies within the capacity market proper. The last capacity auction cleared at £6.95/kW, with most DSR bidders falling away as the price fell below what they were prepared to accept. Existing gas, coal and biomass plant took the lion’s share of contracts, with commentators suggesting plant owners saw the auction as a bonus revenue stream.

Aggregators have long complained that DSR is unable to access longer-term capacity contracts as well as other grid balancing services, such as the (now defunct) Strategic Balancing Reserve and Black Start contracts.

While, as a supplier, SmartestEnergy can access wholesale markets in order to trade flexibility at the best price, other aggregators without a supply licence say their inability to access wholesale and balancing markets puts them at a disadvantage with licensed suppliers. Since industry rule changes have made penalties on suppliers for being out of balance increasingly punitive, suppliers are now aggressively vying with aggregators to acquire flexible megawatts from UK firms.

Although government has created a market for DSR by changing the TA rules so that only turn down DSR can bid for contracts, Owens believes both policymakers should do more.

Aggregators have suggested that testing and metering regimes for DSR are overly onerous, with no incentive for metering parties to undertake the work in the required timeframe. SmartestEnergy said that should be examined. The firm also called for clarity in whether year ahead (T-1) capacity auctions would set aside contracts specifically for DSR, and for longer term contracts both within the capacity market and across National Grid’s broader ancillary services.

But Owens said aggregators must also help themselves.

“As well as changes to the market structure, there needs to be some responsibility placed on the market participants to develop and deliver DSR in a credible, holistic way. Aggregators have an important role to play in building the market and establishing consistent pricing for flexibility, by providing products that match customers’ requirements and investment cycles.”

 This includes making customers aware of broader DSR opportunities outside of government and System Operator schemes.

 “High peak energy costs still make a powerful business case for companies to provide DSR because of the savings they can make from avoiding peak energy prices,” said Owens. “While there is some uncertainty around the ongoing availability of capacity contracts for DSR, we urge businesses to still invest in DSR because there are significant opportunities available from Ancillary Services and non-commodity cost savings.”

The previous Transitional Auction, which allowed generation forms of demand response to bid for contracts, procured 803MW at a cost of £27.50/kW. Smartest Energy secured 20MW in that round, but is bidding for 100MW of contracts in tomorrow’s auction.

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Screen Shot 2017-03-13 at 10.15.02Policymakers should reject calls for the UK to return to double digit margins of power capacity over demand and let flexible plant and agile companies deliver a leaner electricity system, a new report suggests.

The Energy & Climate Intelligence Unit (ECIU), a non-profit thinktank funded by climate and environment bodies, suggests that National Grid’s Supplemental Balancing Reserve (SBR), put in place to shore up thin capacity margins ahead of launch of the capacity market, was a £180m waste of money.

It argues that the fact SBR was not once called upon over three years underlines the reliability of the UK power system. Now the capacity market is up and running, “that should be the final nail in the coffin for blackout fears in the UK,” states the ECIU, pointing out that the chances of the grid totally failing are remote.

“A reliability of 99.999993% corresponds to a less than one-in-ten-million chance of the grid failing to deliver power, roughly equal to the chance of winning the lottery in each UK draw,” states the ECIU. “It is also around a thousand times less likely than asteroid 2013 TV135 – which would cause an explosion 50 times more powerful than the most powerful nuclear bomb ever used – hitting the earth.”

The thinktank believes storage, interconnectors, demand-side response and peaking plant can deliver a leaner, more responsive power system that will cope with ever thinner margins as older plant retires.

“The new [decentralised] system would operate more like a traditional market, where demand can flex to supply as well as vice versa,” it suggests.

That view appears to be gaining traction at both government and regulatory levels. BEIS and Ofgem recently issued a call for evidence on the shift towards a smarter power system, and the regulator’s most senior networks partner Andrew Wright has consistently stated that the value of flexible kilowatts will increase significantly over the coming years.

Meanwhile, traditional utilities, rather than committing to large new power stations, are in the main developing smaller plant to capitalise on peak prices.

However, to significantly scale demand-side response participation from UK companies, it may be that price signals will need to be sharpened.

Download the report here.

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Screen Shot 2017-03-14 at 15.20.24Blockchain technology could facilitate a fully decentralised energy system. Demand-side response would be a clear beneficiary, provided the industry cooperates, writes Electron chief operating officer Joanna Hubbard.

Blockchain technology has the potential to deliver more efficient, transparent and egalitarian transaction platforms that will unlock new business models.

In the energy industry, this promise is particularly compelling when applied at the grid edge, as we seek to create greater market participation and transparency.

We have already seen several instances of this technology enabling peer-to-peer trading and now it is also being touted as the solution to a more efficient market for demand side response.

What is it?

Blockchain presents an innovative decentralised method for validating and recording direct transactions between peers. All transactions are recorded in a single source of truth that is auditable, immutable and visible to all permissioned network participants. The technology was pioneered by Bitcoin in 2008 and is currently seeing widespread adoption by other industries that had previously relied on trusted central parties – most notably financial services.

However, blockchain is not just a technology. It is also a new way of doing business and its adoption will require the energy industry to self-organise and assume new models of co-operation. 

Jo-Jo Hubbard: New models of cooperation will be required

Jo-Jo Hubbard: New models of cooperation enabled, and required, by blockchain.

Remove the middle man

The fundamental change is to the role of the central intermediary: it is not needed. Removing this function removes a cost base, a barrier to transparency and innovation, and a single point of failure.

The first publicised use cases for blockchain in the energy space all focused on peer-to-peer trading of electricity in micro-grids. Companies such as Lo3 Energy in the US and Power Ledger in Australia, have created blockchain transaction platforms on which energy consumers can source energy from local renewable assets.

This maintains the value generated from within the community. In theory, sourcing local energy should also mean cost savings from reduced storage and transmission losses, that being said, the benefits of peer-to-peer trading will not be fully realised until the energy system is restructured to account for localised pricing.

Blockchain and DSR

Another market that seems to be crying out for lower barriers to participation and increased transparency is demand-side response (DSR).

The build out of inflexible, intermittent wind and solar generation in our system has increased the complexity of balancing the grid, the cost of which is forecast to double to reach £2bn by 2020. A large and liquid market for flexibility on the demand side will ensure security of supply and keep the lights on while enabling savings both in terms of cost and carbon emissions.

Opacity, inefficiency

At present the UK flexibility market is estimated to be only a tenth of its potential size and is struggling to scale fast enough. As a whole, the balancing market is overly complex, with more than 26 separate products, and illiquid, with only one real buyer for flexibility in the system operator.

It is also opaque, with little price discovery and trading is often conducted on an inefficient bilateral basis, as many products have prices set by auction months before they are needed.

Collaborative trades

An interesting feature of DSR is that multiple parties can benefit simultaneously from a single action. The same turn-down DSR could enable the system operator to rebalance the grid, a distribution network operator to reduce stress on a load-managed asset and a supplier to correct a trading imbalance.

Enabling collaborative trading will unlock cost savings for purchasers of flexibility and drive liquidity by enabling the execution of trades that would not have been possible on a bilateral basis. Collaborative trades need to be traded on a single platform to ensure simultaneous and complete execution. Historically that would have entailed creating one hell of a monopoly.

No single buyer

Blockchain could present an alternative solution. At Electron, we have created a trading platform that will enable flexibility to be traded collaboratively without handing the levers of power to any single entity.

The platform leverages blockchain to coordinate and record all trading interest in an immutable, auditable ledger. Moreover, its open protocols create results in a transparent execution and governance structure. All parties can see the rules that they are signing up to in advance and verify correct value allocation for themselves.

Collaboration required

Collaborative trading could maximise the efficiency of the flexibility market and in turn the efficiency of distributed asset deployment – but only if the industry cooperates.

There are many reasons for cooperation, such as a more liquid, competitive market for flexibility purchasers; a fairer, more transparent market for flexibility providers; and, ultimately, cost and carbon savings for consumers. This will entail a mindset shift away from the central point of accountability model. It will be up to startups to prove that the technology works in the real world, industry to invest and regulators to engage – and it looks like this is starting to happen.


How long before blockchain might replace the system operator?

Whether blockchain gains traction in the energy system is highly uncertain. But Hubbard tells The Energyst that it could be embedded and fully commercialised within three years, depending on the number of market actors that build systems and processes around the technology. 

“Whether the regulations move that fast, I am not sure,” she says. “With blockchain, we have to do it together or not at all.

“Can we persuade the industry that the trade off between this open, fairer marketplace with lower cost of interaction and single source of truth is worth losing the central point of accountability? Because that is the tradeoff and that is the key barrier: persuading people that [structural shift] is worthwhile,” she says. “It will not be decided by us, but by the industry incumbents.”


What does blockchain mean for I&C companies

All but the largest energy consumers would still engage in flexibility markets via an aggregator. In that sense, it would be business as usual, Hubbard tells The Energyst.

“Aggregators have done a fantastic job helping people to understand their flexibility, de-risk it and sell it into the market,” says Hubbard. “We would like to see a fairer marketplace [enabled by blockchain] for aggregators to operate in. Perhaps the largest energy users will want to interface directly with the blockchain platform, but I think we can do this without changing the way end-users experience [demand-side response provision]. They just benefit from more efficiency, transparency and liquidity.”


What and who is Electron?

Electron is a start-up with some early private backing as well as Innovate UK funding. In addition to its DSR platform, the company is building a blockchain platform for meter assets, that is, all UK gas and electricity supply points, via which it hopes to facilitate faster switching. If adopted, Electron has claimed the platform could make switching 20 times faster.

Chief operating officer Joanna Hubbard says Electron will have developed its proof of concept into “a fully scaled prototype that simulates trade and value transfer by next summer”.

This article was originally published in the Feb/March print issue of The Energyst. The magazine is free to end users involved in energy procurement and management within their organisation. Click here to see if you qualify for a free subscription.

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batteryUtility Vattenfall plans to build its largest battery storage facility at a wind farm in South Wales.

Subject to a final investment decisions, the 22MW facility will be constructed at the 230MW Pen y Cymoedd wind farm in South Wales. Vattenfall, which won a 22MW, four-year enhanced frequency response (EFR) contract last year from National Grid, said the unit will provide grid balancing services via that service.

The announcement comes as Vattenfall announced a deal with automaker BMW for 1,000 batteries with a capacity of 33kWh, which it will use in all of its currently planned storage projects. The batteries are the same as those used in the BMW i3 electric vehicle.

“We want to use the sites where we generate electricity from renewable energies in order to drive the transformation to a new energy system and to facilitate the integration of renewable energies into the energy system with the storage facilities,” said Gunnar Groebler, senior vice president of Vattenfall and head of its wind business. “The decoupling of production and consumption and the coupling of different consumption sectors are in the focus of our work.”

See the announcement here.

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Groves: We can monetise your flexibility

Groves: We can monetise your flexibility

Around 10,000 UK firms could make around £20,000 a year in cost savings or revenue by shifting or curtailing power use at peak times, according to analysis by SmartestEnergy.

The firm basis its figures on businesses consuming 10GWh of power a year. According to Cornwall Energy, around 9,700 firms use at least that amount. SmartestEnergy, which is bidding into next week’s capacity auction, said those savings applied to companies with 250kW of flexible capacity.

Based on the last auction, which cleared at £22.50/kW, revenue for companies that sign a demand-side response contract with the supplier would equate to £2,812  from capacity market payments (250 x £11.25 – representing a 50% revenue share).

However, SmartestEnergy said firms with that level of flexibility could make far greater savings: an additional £15,000 by shifting consumption off peak and £17,150 by stopping consumption altogether during evening winter peaks.

Between October and February each kilowatt consumed between 4pm and 6pm costs on average eight times more than off-peak power – £68.60 compared with £8.59. If businesses curtail peak generation they save £68.60. If they shift it to off peak they save £60.01, the firm explained. That equates to savings of £15,000 (250 x £60.01) by shifting consumption off peak and £17,150 by stopping consumption altogether (250 x £68.60), according to SmartestEnergy’s sums.

With non-commodity costs markedly increasing over the year ahead, allied with volatility in the wholesale and balancing markets, companies that can shift loads and sell power back to the market at peak times can make significant revenue, according to SmartestEnergy.

“Matching demand to supply is key to a cost-effective and reliable energy system, and businesses which can help do this stand to gain by tens of thousands of pounds a year,” said CEO Robert Groves.

The firm, which is an aggregator as well as an energy supplier, touted its ability to maximise returns for customers.

“We can navigate the complexities of DSR contracts, spot opportunities to sell the electricity they have bought at a good profit, and ensure that savings on non-commodity charges are passed on,” said Groves.

He added that most companies could shift around 10% of load “with little impact on operations”.

While that represents an opportunity for some businesses, SmartestEnergy recently warned that companies that do not take action will this year be facing ‘huge’ hikes from the impact of the capacity market.

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batteryA “buoyant” energy storage market has led to 667 connection applications totalling 12.2GW over the last 15 months, according to UK Power Networks (UKPN).

The distribution network operator (DNO) said the surge of interest in storage, virtually all batteries, is creating challenges for network firms and it wants to be allowed to charge for design and assessment fees to cover costs.

It says this would deter ‘highly speculative’ enquiries.

UKPN also wants to adapt its processes to enable a range of capacities to be specified by developers so that it can tell them how much storage capacity they could connect at a given location without need for system reinforcement.

In the longer term, it says network companies, as they become distribution system operators (DSOs), may need to run their own, local capacity markets to procure flexibility.

UKPN outlines in some depth the key issues around charging for use of networks and flexibility services in its response to BEIS and Ofgem’s call for evidence on creating a smart, flexible energy system.

In the document, UKPN also indicates a ramping up of its demand-side response activity, stating it will procure more flexibility in 2017 via relationships with aggregators and directly with industrial and commercial consumers.

“As the use of flexible connections expands and more storage looks to connect, demand-side flexibility will need to be facilitated through the connections process and agreement, which we are well positioned to enable,” the firm added.

See the full response here.

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Nat Grid control centreNational Grid will extend the period for its demand turn-up (DTU) service to run from March to October. The system operator (SO) has also confirmed it aims to broadly double the 300MW it procured in 2016 and will provide two routes to market for providers.

Meanwhile, the system operator has also lowered the minimum clip size for those participating in Firm Frequency Response (FFR) to 1MW.

While most forms of balancing ask demand-side firms and power stations to adjust output or production when there is a shortage of power, DTU aims to help balance the system when there is too much power to handle. National Grid says that is a growing challenge. The system operator therefore launched a DTU trial to run between May and September last year, during which 10,800MWh of response was called into action.

Initial procurement for next year’s service will started in February. However, after the first trial with distribution network operator (DNO) Western Power Distribution, the SO and the DNO have outlined plans to tweak the bid process and payments structure.

Providers can bid for ‘fixed’ DTU contracts in February, which lock in prices for their availability throughout summer. However, they can also bid for ‘flexible’ DTU contracts on an ongoing basis every Friday and Tuesday between 27 March and 29 October. Providers can submit different availabilities within the same availability window, so can declare themselves available for parts of the windows and unavailable for others.

Meanwhile, although the minimum clip size for providers will remain 1MW, it will now be less constrained by location – so aggregators do not have to find that megawatt within the same grid supply point.

National Grid has previously indicated it would look to procure much more DTU in 2017. A Grid spokesperson confirmed that to The Energyst, saying “it is likely to double”.

See the summary of DTU trial and service changes here.

Additionally, National Grid confirmed in December that the entry threshold for Firm Frequency Response (FFR) providers would fall from 10MW to 1MW as of April 2017.

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Alastair Martin: engine farms win where today’s capital cost is the only consideration

Alastair Martin: engine farms win where today’s capital cost is the only consideration

The capacity market is buying the wrong stuff, because it’s a single-issue policy that joins up with nothing, according to Flexitricity founder and chief strategy officer Alastair Martin. He says engine farms will continue to price more efficient plant out of the market unless policymakers make a simple fix.

In truth, there are many things wrong with the Capacity Market (CM) – the UK Government’s flagship policy for the security of national electricity supplies. Among these is not whether or not the CM will work. It will – the lights will stay on. Probably.

Nor is it the somewhat disappointing price in the first CM auctions, which earlier this month hit a historic low of £6.95/kW per year. Admittedly, this was for the ‘bonus’ early auction for delivery from October 2017; the four-year-ahead market managed a more respectable £22.50/kW in December’s auction. Prices like that will delight Government: the consumer is getting supply security for only a modest hit on bills. The lesson is that auctions discover prices, and Dutch auctions discover low prices. Government made a shrewd pick of auction format for the CM.

Most of my thousand gripes about the CM are details which are eminently fixable. Flexitricity’s demand response portfolio is made up of a broad mix of flexible loads, combined heat and power (CHP) generators, critical power supplies and small hydro generators. This diversity is a massive part of its success, but the CM wasn’t designed to recognise that. Fitting flexible customer-side assets into the CM is like playing chess in boxing gloves. It can be done, but it’s pointlessly awkward.

The basic structures of energy policy aren’t wrong either. We live on an Atlantic archipelago that’s sometimes windy, sometimes wet and sometimes sunny, and which is surrounded by tidal and wave energy. We should be doing all we can to use our free resources in preference to burning commodities which come loaded with financial and environmental risk. We pay renewable resources to churn out the megawatt-hours as much as they can. We don’t pay them for reserve or capacity services, because that’s not what they do best. This means that the balancing capacity – traditionally gas, coal and oil burners, but now also demand response and batteries – isn’t going to make all of its living selling energy. So we pay such ‘despatchable’ resources for the security they provide. Taken as a whole, and setting aside Westminster’s recently-acquired fear of a wind turbine that anyone can see, this combination of policies – for green energy and reliable capacity – makes sense.

Back to those lights, and their staying-on-ness. Secretaries of State don’t get to use the word “probably” in this context. But that’s government policy. Perfect security costs infinite money, and no-one wants an infinite electricity bill.

The UK is in good shape when it comes to raw megawatts, if we count – and we should – energy efficiency and flexible consumers. They are part of the mix. Our Loss of Load Expectation (LoLE) sits at around 0.5 hours each year – that’s the number of hours in which we expect somebody, somewhere in GB, to be going without electricity because there isn’t enough. Government’s target LoLE is three hours. That’s what politicians mean when they say “the lights will stay on”. They mean probably.

This winter, France suffered the nightmare of all those concerned with reliability: a type fault. Type faults are faults affecting many different stations of a similar type. In this case, it was the discovery that many of France’s nuclear reactors had been made with the wrong type of steel, and were at risk of ageing disgracefully. Prior to the discovery of this fault, the French grid operator RTE had estimated LoLE at a respectable 1.25 hours. 2016/17 is the first winter I can remember in which we regularly exported power to France during our weekday evening peak.

Diversity is important in security, and being technology-neutral, the CM has the potential to encourage a broad mix of resources to participate. It has largely delivered this in all but one category – new-build generation. It is in this category that the CM’s real flaw is found.

The CM is buying the wrong stuff, and it’s doing it because it’s a single-issue policy that joins up with nothing.

Under the CM, it’s possible to get a 15-year contract if you’re building a new generation site, but everyone else must take shorter contracts. This means that the CM strongly favours low-capex projects. This delivers one thing: engine farms – rows of reciprocating engines, gas or diesel, in shipping containers.

It is a post-hoc rationalisation to claim that engine farms are what’s best for the consumer. They win where today’s capital cost is the only consideration. It’s also a calumny to claim that engine farms are there to balance wind. This is nuts: wind generation varies, but over timescales of hours and days, not minutes and seconds, which is where engines have a place. We do sometimes get storm shutdown events that result in a fast drop in renewable output. For that, engines are fine. But we’ve got enough – there are more megawatts of standby diesels already installed in the UK than there are of wind farms.

December’s auction saved some face, but not enough. Centrica’s repowering of King’s Lynn A will give us a nearly-new combined-cycle gas turbine CCGT. Intergen’s Spalding extension will produce a large open-cycle gas turbine (OCGT), which will probably compete with engine farms on efficiency, but not with a new CCGT.

An engine farm might manage an efficiency of 41% if it’s gas, or 38% if it’s diesel. That means around 60% of the energy put into an engine farm is blown into the sky as waste heat. Compare that to a new CCGT at 61% or more, or, better still, a CHP in a district heating network with a total efficiency approaching 85%. If the CHP has a heat store – a big tank of water – it provides all of the flexibility needed to balance renewables. Add a large-scale heat pump, and the site can switch from generation to beneficial consumption as renewable generation ebbs and flows – a virtual battery, without the lithium.

One of the huge problems faced by the energy industry is consumer engagement. Insiders know that energy would be cheaper, greener and more secure if the top deck of the Clapham omnibus buzzed with discussion about the merits of low-energy light bulbs, or whether to keep the washing machine off until after this evening’s peak. CHPs score over CCGTs because their natural home is in the community, and community ownership is a real possibility. Nothing captures attention better than skin in the game.

The Capacity Market misses all that, and instead floods the market with single-purpose peakers. There are only so many peaks to go round, and sending engine farms off hunting the role that CCGT and CHP could hold in the bulk energy market is environmentally and economically daft. Government knows that, but its efforts to control the problem have been tangential, and the damage largely collateral. Even this is an easy problem to fix. All that’s needed is an insistence that anyone wanting a 15-year contract meets the Government’s own Emissions Performance Standard or qualifies as Good Quality CHP, both of which are established Government schemes.

So why was the price in this month’s auction so low? In a word, P305 (note: in the GB electricity market, that qualifies as a word). It’s now over a year since Ofgem put the fizz back into prompt electricity markets with its reform of imbalance prices. No-one knows how long the fun will last, but for now, old power stations clearly find it worth staying at the party a little longer. That’s not a disaster; it’s the market doing what it’s supposed to do.

Meanwhile, the Capacity Market marches on, doing the one thing that it’s designed for, and optimising that at the expense of everything else.

This opinion was first published on Flexitricity’s website.

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vxnghcaynebgvecvgzhbNational Grid has awarded a 20MW frequency response contract to a grid-scale battery system operated by Renewable Energy Systems (RES). The system will provide enhanced frequency response type services, which help balance the grid in under a second.

The contract was awarded outside of the main Enhanced Frequency Response tender, which takes place in July. National Grid seeks 200MW of superfast balancing capacity from that procurement exercise, which is largely expected to come from grid-scale batteries.

Under the deal, RES will provide dynamic frequency response, whereby it gets paid to help balance the system when frequency is either too high or too low. Dynamic frequency response is the most lucrative of all balancing markets and requires participants to provide constant balancing services in response to fluid demand and supply levels on the national power system.

With increasing amounts of renewable on the system and older thermal plant rapidly retiring, demand for frequency balancing services – also known as demand-side response – will increase exponentially over the coming years.

Technologies that can respond fastest and most reliably to increasingly frequent frequency fluctuations will be in the strongest position to profit from National Grid’s move away from balancing the grid solely via conventional generating plant.

Under the agreement, the RES system must be fully operational within the next 18 months.

National Grid senior account manager Adam Sims said the deal marks the first time battery storage would be used to provide such rapid frequency response. He added that it will dovetail with the Enhanced Frequency Response service to “support the network as we transition to a generation mix with greater levels of low cost renewable energy.”

RES energy storage manager John Prendergast said the firm had experience of providing superfast frequency response services in Canada and was one of the largest such providers in the USA. The contract with National Grid represents “a major step” in scaling its UK energy storage business, he said.

Prendergast urged Ofgem and Decc to quickly remove market barriers to wider deployment of energy storage in the UK. The department has said energy storage is “a top priority” and will shortly issue a consultation on smart energy systems.

At present, however, energy storage faces issues such as double charging, as it is classed as both generation and supply. Meanwhile distribution network operators, which would like to use large scale battery systems to manage local network demand fluctuations, are not allowed to own and operate them under current market rules.

The National Infrastructure Commission has urged Decc to examine those regulations and expedite the move to a smarter energy system, which it believes could save bill payers billions of pounds in avoided costs of new build generation.

Energy minister Andrea Leadsom recently said the department had heeded that message but sought to avoid knee-jerk regulation that could deliver perverse outcomes.

The Energyst, National Grid, aggregators and energy suppliers are holding a demand-side response conference on 8 September in London. There are 100 free places for businesses that want to provide demand-response services. Visit www.dsrevent.uk to reserve your place.

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