Demand Side Response 2016

Demand Side

Response Turning inertia into inertia 2016 Report

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Give National Grid your response

By Tim McManan-Smith, editor, the energyst Awareness of demand-side response (DSR) appears to have increased since National Grid announced a major push in June 2015. Businesses have appetite to reduce costs and monetise assets.

There also appears to be a buzz around battery storage.

But 12 months from our last survey, barriers from both a customer and market perspective, seem to have changed very little. Where customers are concerned, the survey data suggests that awareness is not the problem.

The key fears appear to be that equipment and processes are not suitable and that operations will be disrupted.

However, lack of understanding was high on the list of reasons respondents gave for not participating in DSR. This is unsurprising. The market is complex, as the product map on p18 illustrates. Energy and operations managers have day jobs.

But National Grid has been working to disseminate information and aggregators and suppliers appear to be making progress in terms of market engagement. Around half of those surveyed said they had been contacted by aggregators or suppliers with regard to DSR compared to a quarter in last year’s survey.

But aggregators can only do so much in terms of market education.

Simplifying the market might make a more significant impact.

National Grid says it recognises the issue of complexity. It plans to move from engagement to action during the second year of its DSR push via the Power Responsive platform. Now it wants the public and private sector to continue to engage and specify which products require simplification and outline the kind of information needed to enable broader or deeper DSR participation (see p34).

That presents an opportunity for businesses to shape the market.

Given the steeply rising costs of decarbonising the energy system, the impact of intermittent generation and extremely thin capacity margins, it is an opportunity we must take.

Author’s note Thanks to all the people who took part in the survey for this report. Thanks also to the market participants for sharing their views on barriers and solutions. I hope you find the report useful and would welcome feedback via www.theenergyst.com.

Brendan Coyne, report author

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Key survey findings This year’s survey suggests progress in terms of market engagement. However the need for education, simplification and revenue certainty remain.

This year’s survey confirms some of last year’s findings. The vast majority (around 80%) of those that provide DSR do so through an aggregator and around nine out of ten are satisfied with the outcome.

Those that do not provide DSR (around 73% of respondents) are largely concerned about unsuitable equipment and processes, followed by disruption to core business. Many respondents cited both of these factors in tandem.

However, several aggregators interviewed believe that most companies could unlock a degree of flexibility. That suggests a need for continued market education, potentially more focused at operations level. Some 90% of nonDSR participants said they would be interested in DSR provision if it did not affect core business.

Of those that do not participate in DSR, around half said they had been contacted by suppliers or aggregators about service provision.

That suggests progress: last year’s survey found only a quarter of firms had been contacted by aggregators or suppliers regarding DSR. Around two thirds of those not yet contacted by aggregators or suppliers have annual energy spend of under £1m and around half are small companies. That appears to confirm the view that aggregators and suppliers are primarily targeting larger operations with higher energy consumption and potentially multiple sites.

Overall, almost six in ten non-DSR participants surveyed said they have some form of on-site generation, suggesting potential to provide DSR.

KEY STATISTICS AND DEMOGRAPHICS Of 212 responses, 191 completed the survey. Of those, 187 specified their industry sector: Around 56% are in the industrial and commercial sector; 25% the public sector; 9% in manufacturing; the remainder are in food and drink, finance and retail.

Around half of respondents work for large organisations (500+ employees); around a third for small companies (under 51 employees); the remainder work for mid-size organisations (51-499 employees).

Around half of survey respondents are managers, around a quarter directors and around a quarter consultants.

Some 42% have an annual energy spend of under £1m, 35% an annual energy spend of £1m-£10m, the remaining 23% have an energy spend of over £10m.

Around a quarter (27%) participate in DSR schemes. Three quarters (73%) do not.

DSR PARTICIPANTS Of those that do participate in DSR: 42.5% are in the industrial sector; 17% are in the commercial sector; 17% in the public sector. The remainder work in food and drink, manufacturing, finance and retail sectors.

Sample bias and caveats There is an element of self-selection within the sample survey. Around a quarter surveyed participate in DSR schemes. At face value, that would suggest a much broader take-up of DSR than in reality. Market penetration is likely low single digit, according to aggregators.

Another caveat is that while 59% of those that provide DSR say they turn equipment down or off, only 14% provide purely turn-down DSR. The vast majority (76%) of the market is provided by behind the meter generation and more than half (55%) of DSR providers use back-up diesel generators for at least part of their delivery.

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Suggestions to scale DSR Survey participants were asked to suggest how DSR could be scaled. 155 respondents offered a view.

Around 30% of answers related to increased revenues/ revenue certainty or subsidies.

Around 20% outlined a need for greater clarity/simplification of the market structure and schemes. Around a 20% suggested a need for greater market awareness and understanding. Around 10% think spikier and more broadly applicable time of use tariffs will drive uptake and around 7% believe advances in energy storage will increase market participation.

Around 80% contract via an aggregator although some also contract directly with National Grid (20%) and through their DNO (10%).

Around three quarters (76%) turn on standby generators or switch to onsite generation. 59% said they also decrease consumption; 24% said they increase consumption.

Generating income from assets was the main reason for participation (85%) followed by avoiding peak network charges (40%).

Almost nine in ten DSR providers (86%) said they are satisfied with the outcome. Reasons cited for dissatisfaction include scheme instability and revenue uncertainty, which in turn complicates finance/ investment; increased CO2 emissions from turning on diesel generators; and poor response and support from DNOs. Overall, the survey shows significant end-user interest in battery storage. Around half of all survey respondents are investing, or considering investment in batteries.

Survey respondents’ demographic breakdown

Number of employees

Annual energy consumption

4.6% 1% 16.4%

31.8%

42.1%

43.9%

4.6% 8.1% 7% 4.6%

l 0 - 49 l 50 - 99 l 100 - 249

35.9%

l 250 - 499 l 500 - 999 l 1000+

l £100m - £1bn l £1bn+

l <£1m l £1m - £10m l £10m - £100m

Job title

Industry sector

9.2% 3.1% 4.1%

2.6% 23.1%

25.1% 32.8%

Director

Manager

Consultant

24%

49%

27%

l Industrial l Finance l Commercial l Food / l Public Sector Drink

5

l Manufacturing l Retail

Which do you think of the following is driving future growth in DSR (Demand-Side Response)?

The weighted averages suggest fear over security of supply is the primary driver for DSR. Last year's survey placed more weight on the impact of renewable generation.

This winterâ&#x20AC;&#x2122;s capacity margin would have been 0.1% without balancing reserve procurement, which may have translated to greater security of supply fears.

Respondents believe desire from businesses to monetise assets is another significant factor in driving demand response, with similar weighting given to the impact of intermittent renewable generation of the electricity system.

Very important

Very important

Very important

Very important

Very important

Not Very Important

Not Very Important

Not Very Important

Not Very Important

Not Very Important

Transition to renewable energy sources

Fears over security of supply

Cost of DSR compared to alternative capacity sources

Rise in 'smart' assets which can respond intelligently

Desire from businesses to derive revenue from existing activities

How important is DSR to your energy strategy in terms of priority?

DSR is a relatively high priority for 42% of respondents and relatively low for 31%. Around 28% said it sits in the middle of their strategic objectives.

Very important

The data is interesting because only 27% of survey respondents said they currently participate in DSR schemes. That 42% rank it as first or second priority in their overall energy strategy may suggest a significant proportion are weighing up balancing services provision.

Not important

6

Does your organisation participate in DSR?

That 27% of survey respondents participate in DSR probably indicates sample bias. In the broader market, the percentage of companies and organisations providing balancing services is likely low single digit. Most surveys on a relatively niche topic will attract an element of selfselection. However, it suggests this yearâ&#x20AC;&#x2122;s survey is slightly more reflective of the broader market than last yearâ&#x20AC;&#x2122;s, where 33% said they participated in DSR schemes.

NO: 73%

YES: 27%

The following answers are from the respondents that implement DSR within their organisation

How is your DSR contracted?

Of the survey respondents that participate in DSR, the vast majority contract through an aggregator. The 23% that contract directly through National Grid were mostly water and energy utilities plus two respondents from the steel industry. Those contracting direct with DNOs were also largely energy and water companies, alongside large I&C and manufacturing firms.

100%

90%

79%

23%

10%

0%

Through an aggregator

Direct with National Grid

Direct with your DNO

Through the Capacity Mechanism

80%

70%

60%

50%

40%

30%

20%

10%

7

How do you participate in DSR?

Most respondents provide a range of services. Three quarters (76%) use behind the meter generation to provide at least some of their demand-side response. 59%, mainly from the I&C sector, said that they also turn loads off or down. Only 24% of respondents do not use onsite generation at all for demand response provision and flex both up and down. 14% said they provide purely turn down DSR. No respondents provide purely turn-up services.

100%

90%

76%

59%

24%

Turn on standby generators

Decrease consumption / turn loads off

Increase consumption / turn loads on

80%

70%

60%

50%

40%

30%

20%

10%

How much of your consumption approximately do you utilise for DSR? Consumption

Many participants use less than 10% of site consumption to deliver demand-side response and do so across sectors.

Those that provide 10-25% include utilities, I&C and manufacturing firms; those that provide 25-50% of consumption are mainly I&Cs. Those that say they are 50% to 100% flexible include a UPS manufacturer, a renewable energy firm, an NHS trust and a construction materials firm.

Responses

0-10% 10-25%

42%

25-50% 21%

10% 50-100%

13% 14%

Don't know

8

What was your main motivation for participating in DSR?

The vast majority (85%) of those that provide DSR say their main motivation is to generate income from assets. Avoiding peak charges is the key business reason for a significant factor (40%). While a few respondents participate to achieve CSR objectives or improve maintenance regimes, responses suggest that DSR participation is purely a commercial decision for most organisations.

100%

90%

85%

6%

6%

40%

8%

Generating income from assets

Support CSR objectives

Improved asset maintenance

Avoid peak network charges

Other

80%

70%

60%

50%

40%

30%

20%

10%

Which of the following DSR programmes are you utilising or have you heard of?

Two thirds of participants use demand response to reduce peak network charges. Short-term operating reserve (STOR) and frequency response are the most popular services amongst participants, with 44% active in those markets. A quarter said they participate in the demand-side balancing reserve (DSBR) programme, which some aggregators said was a relatively straightforward scheme to access. It will be replaced when the capacity mechanism kicks in, which some aggregators said was more complex. Five firms claimed to be involved in enhanced frequency response, although no EFR contracts had yet been awarded at the time the survey was conducted.

Key:

80% 70%

40%

Heard of

Not heard of

73% 64%

60% 50%

Participate in

47% 45%

30%

20%

66%

71%

46%

59%

44%

30%

25%

23%

73%

61%

57% 36% 24%

23%

24%

20% 10%

8%

7% 11%

STOR

10%

11%

Fast Demand-side Frequency Enhanced Reserve balancing response frequency reserve response

11% Demand turn-up

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67%

16% Time of use tariffs

7%

Critical peak pricing

5%

Interruptible contract

16%

9%

11%

DuOS / Triad avoidance

Capacity market

Do you use diesel back-up to provide DSR / avoid peak charges?

More than half of respondents use diesel back-up generators to deliver demand-side response services. These were largely utilities (mostly water companies and some energy-related companies) and NHS trusts, as well as organisations in the I&C, manufacturing and education sectors.

YES: 55%

NO: 45%

If so, how many hours per year on average do they run?

The majority (71%) of those that run diesel generators for DSR do so for less than 50 hours per year.

Defra says it plans to limit emissions from diesel generators by 2019 at the latest, which could have some impact on run hours.

The department says generators that solely provide back-up power during power cuts or other on-site emergencies will not be affected. However, those under 50MW bidding into the capacity market have been served notice, although firm details of any changes are yet to emerge.

l 1-10 hours l 11-30 hours

29%

14%

36% 21%

l 30-50 hours l 51+ hours

10

What are your thoughts on using diesel back-up generators for DSR?

The majority of those participating in DSR appear relaxed about proposals from government, via Defra, to tighten rules around diesel emissions.

Most see using diesel back-up generators as a useful source of revenue and a way to improve and monetise maintenance.

However, around a third take a negative view, believing costs, both financial and environmental, outweigh benefits.

23%

21%

11%

36%

Uptime is very The cost The cost important to the to run the and DSR environment generators allows regular outweighs the outweighs the testing DSR benefit DSR benefit

9%

Can provide Proposed a useful tighter source of emissions laws revenue will limit its contribution

In terms of DSR experience overall, have you been satisfied with the outcome?

That 86% are satisfied with their DSR experience is a positive statistic, although it is down on last yearâ&#x20AC;&#x2122;s survey, where 94% were happy. Arguably this year's broader sample does not offer a true year-on-year comparator.

NO: 14%

Those that were not happy all contract through an aggregator but their stated complaints appear largely outside the aggregators' control. Reasons for dissatisfaction included rapidly changing programmes and revenue uncertainty, in turn creating finance/investment difficulties; increased CO2 emissions from turning on diesel generators; and poor response and support from DNOs.

YES: 86%

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The following answers are from respondents that do not implement DSR within their organisation

Do you shift loads to avoid peak network charges (Triad)?

The majority of non-providers do not loadshift to avoid peak network charges. However 12% are involved in demand management for Triad and DUoS periods. These were mostly in industrial, commercial, manufacturing and public sectors.

YES

NO

12% 88%

Do you have any form of onsite generation?

That almost six in ten organisations not currently participating in DSR have some form of onsite generation suggests an opportunity for aggregators and energy suppliers, particularly if less flexible generation can be paired with batteries.

Changes to the Embedded Benefits regime may potentially alter economics in some cases.

YES: 57%

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NO: 43%

What are your thoughts on using diesel back-up generators for DSR?

Those not participating in DSR are less convinced of the merits of using diesel generators to balance the power system than those that provide DSR.

14%

25%

19%

18%

24%

Half think that either the cost to the environment is too great or that proposed tighter emissions laws will limit dieselâ&#x20AC;&#x2122;s contribution to the mix, although almost a third think it could provide a useful source of revenue or monetise maintenance.

Uptime is very The cost The cost important to the to run the and DSR environment generators allows regular outweighs the outweighs the testing DSR benefit DSR benefit

Can provide Proposed a useful tighter source of emissions laws revenue will limit its contribution

Has your electricity supplier or an aggregator spoken to you about the advantages of flexibility in your energy consumption?

Roughly half of non-DSR participants surveyed have been approached by aggregators or suppliers about provision. Last year, 74% said that they had not been engaged by market actors.

While this yearâ&#x20AC;&#x2122;s broader sample does not allow a true year-onyear comparator, that figure could reflect increased engagement â&#x20AC;&#x201C; both by pure-play aggregators and traditional suppliers now looking at DSR with renewed appetite. However, half the market remains untapped. This may be because aggregators and suppliers target what they see as the biggest wins for the lowest cost of sales.

YES: 49%

NO: 51%

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Would you be interested in earning money through DSR if this did not affect your operation?

Almost nine in ten nonparticipants would be interested in DSR provision if it did not disrupt their core business. That suggests a significant opportunity to scale the market if suppliers and aggregators can allay other concerns around trust, complexity and revenue.

YES: 87%

NO: 13%

Which of the following DSR programmes have you heard of?

That the enhanced frequency response and demand turn up are the services with least visibility is unsurprising, given that National Grid announced them only last year. Both are currently niche services, although are expected to scale as battery prices and summer demand fall.

Key: 90%

Heard of

81% 84%

80% 70%

87%

87%

13%

13%

DuOS / Triad avoidance

Capacity market

87%

85%

61%

58%

57%

39%

42%

43%

60%

Not heard of

60%

62%

50% 40% 30%

38%

13%

20% 10%

40%

19%

STOR

16%

15%

Fast Demand-side Frequency Enhanced Reserve balancing response frequency reserve response

Demand turn-up

14

Time of use tariffs

Critical peak pricing

Interruptible contract

Why have you not considered DSR?

The biggest perceived barrier to DSR provision is that equipment and processes arenâ&#x20AC;&#x2122;t suitable, followed by disruption to core business. Many respondents cited both of these factors in tandem. Lack of market understanding was another inhibitor. Some believe that the returns are not high enough and trust issues around ceding control to a third party remain.

Similar to last yearâ&#x20AC;&#x2122;s survey, awareness does not appear to be a major issue. However, caveats around a self-selecting survey sample must be applied.

0%

10%

20%

30%

40%

Not aware of the possible opportunities

16%

Concerned about disruption and impact on business performance

37%

Return on investment not attractive enough

24%

Does not count towards carbon reductions

8%

Equipment / processes are not suitable

39%

Don't understand enough about the market and different options to make a decision

28%

Lack of trust in a third party having control over your kit

23%

The following answers are from all respondents

Are you considering / have you invested in any forms of energy storage such as batteries?

Around half of all survey respondents are investing, or considering investment, in battery storage. Batteries are particularly suited to providing higher value DSR such as frequency response and enhanced frequency response and can also facilitate peak cost avoidance, as well as fulfill UPS roles. Combining batteries with other assets can also unlock greater flexibility.

Costs are expected to fall significantly over the next few years and National Grid expects penetration to increase. However, as in any market, higher volumes tend to result in revenue commoditisation.

YES: 52%

15

NO: 48%

How do you / would you use the revenue from DSR?

Around half of respondents would offset their energy costs via DSR or already do so. Around a third would reinvest the proceeds in energy efficiency.

Investing in energy efficiency delivers permanent cost reductions. But doing so may actually may reduce the amount of flexibility a business can harness, which highlights a tension between demand reduction and demand response.

However, as survey data suggests most providers switch to on-site generation to earn DSR revenues, investing in energy efficiency would be a win-win for those organisations.

Offset energy costs

Fund energy efficient projects & sustainability initiatives

47%

31%

Investment Other in new equipment

11% 10%

Selected comparisons between 2015 / 2016 survey data results

Has your electricity supplier or an aggregator spoken to you about the advantages of flexibility in your energy consumption?

That around half organisations that currently do not participate in DSR have been contacted about provision by suppliers or aggregators is an indication of increased market engagement.

Last year's survey suggested that three quarters of the potential market had not been approached.

2015 YES: 26% 2016 YES: 49%

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Selected comparisons between 2015 / 2016 survey data results

Would you be interested in earning money through DSR if this did not affect your operation?

Almost nine in ten organisations would consider DSR participation if their core business was not affected. This is a slight increase from last year but could suggest a need for further market awareness and engagement activities as in most cases, DSR is subservient to core business.

2015 YES: 79% 2016 YES: 87%

Selected comparisons between 2015 / 2016 survey data results

Why have you not considered DSR?

The perception that DSR is disruptive to business performance is seen as a greater issue this year than last year, although caveats around broader sample must be reiterated. Concerns around unsuitable equipment are lower, but both barriers could be addressed with greater education.

2016

2015

+/-

Not aware of the possible opportunities

16%

17%

-1%

Concerned about disruption and impact on business performance

37%

27%

+10%

Return on investment not attractive enough

24%

22%

+2%

Does not count towards carbon reductions

8%

5%

+3%

Equipment / processes are not suitable

39%

46%

-7%

Don't understand enough about the market and different options to make a decision

28%

25%

+3%

Lack of trust in a third party having control over your kit

23%

22%

+1%

0%

10%

20%

17

30%

40%

Key DSR markets at a glance As the diagram below illustrates, the balancing services market is complex and there are many ways businesses can help balance the grid in return for payment. At a basic level, the main requirements are around managing supply and demand in terms of capacity and managing the frequency of the grid to keep it stable at 50Hz. The following programmes are some of the main mechanisms open to demand-side response providers:

SHORT TERM OPERATING RESERVE (STOR) STOR helps Grid manage longer duration capacity shortfalls. It is largely provided by generation rather than turndown DSR. Providers are given 4 hours notice and must be able to deliver for a minimum of two hours, three times a week if necessary. STOR payments have declined in recent years as more providers entered the market.

DEMAND-SIDE BALANCING RESERVE (DSBR)

is also a transitional arrangement (TA) auction, which has been reengineered so that it will only be open to turn down DSR providers.

Capacity market contracts allow for provision of other balancing services, so long as providers deliver what they are contracted to deliver in the capacity market when called upon.

DSBR was created to help mitigate winter peak capacity shortfalls ahead of the opening of the capacity market. A simple service, it requires providers to turn down consumption or switch to back-up generation at four hours notice for at least one hour.

CAPACITY MARKET

DEMAND TURN-UP (DTU)

The capacity market was created to ensure security of supply over the winter peak. It is open to all forms of generation and DSR. There

Demand Turn-Up is a new service designed to help Grid cope with excess generation at times of low demand, i.e. summer. DTU pays

Demand Response Markets

DR Services

Balancing Services

Demand Turn-Up

Reserve

DSBR

Distribution Network

Capacity Market

Frequency

T-4 Auction

T-1 Auction

Fast Reserve

Dynamic

Static

Dynamic FFR

Static FFR

EFR

FCDM

STOR

Committed

Flexible EFCC Premium Flexible Partially Dynamic Enhanced Optional STOR

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Transitional Arrangements

providers to increase demand or turn-down onsite generation. The notice period is longer than other forms of demand-side response and providers must be able to respond for at least two hours. It is currently a manual service but will likely become automated.

FREQUENCY CONTROL BY DEMAND MANAGEMENT (FCDM)

secondary frequency response, where assets must respond within 30 seconds. They must be able to sustain output for up to 30 minutes.

Interruptible processes and diesel generators on hot standby can be suitable assets. Static Frequency Response is a high value service.

DYNAMIC FREQUENCY RESPONSE

FCDM is usually provided by large, intensive power users when a power station or interconnector goes down. An automated service, it interrupts electricity supplies within two seconds of grid frequency dropping below a certain threshold, and providers have to be able to sustain delivery for 30 minutes.

FCDM is a high value service.

STATIC FREQUENCY RESPONSE Static Frequency Response is triggered when grid frequency drops below a certain threshold, usually if a power station drops out. It encompasses primary frequency response, which requires assets to respond in 10 seconds, and

Dynamic Frequency Response keeps the grid stable in both directions – when frequency is too high or too low. As such, providers have to monitor grid frequency in real-time and flex consumption or generation up or down accordingly.

Providers have to deliver within two seconds for up to 30 minutes, but in most cases, the duration of response is a few minutes. Dynamic Frequency Response is a high value service.

ENHANCED FREQUENCY RESPONSE (EFR) Enhanced Frequency Response is the fastest dynamic frequency response service. Providers have to deliver in under a second. The first four-year contracts were issued in

August this year, the vast majority to be delivered via battery assets.

Providers have to sustain delivery for a minimum of 15 minutes in either direction. It is the highest value frequency response service.

PEAK CHARGE AVOIDANCE Avoiding peak charges on the transmission and distribution networks also constitutes demand response.

Reducing transmission costs is known as Triad avoidance.

Companies turn down consumption or switch to onsite generation over what they think will be the three highest winter demand periods. If they manage to accurately predict and avoid those peak periods, they can significantly reduce the transmission element of their bill.

Distribution peak charges, known as ‘red zones’, vary by distribution network but during weekdays largely fall in the late afternoon and evening, regardless of season.

Companies that can reduce loads or switch to onsite generation during those periods can significantly reduce distribution network charges.

Price-based DR

Site Optimisation

Variable Costs

BSUoS

Wholesale

Peak Prices

Imbalance DUoS

Import/Export Tariff

Maximum Import Management

Day/Night Supplier Tariff

Day Ahead Trading

Intra-day Trading

Triads

Capacity Market Levy

Courtesy of Open Energi

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Trust, technology, complexity, certainty: Customer barriers to DSR participation Most operations have some degree of power consumption flexibility, according to aggregators, yet relatively few organisations participate in balancing services. So what are the key customer challenges and how can they be resolved?

As with last year’s survey, concerns around disruption and that equipment and process are unsuitable remain key customer inhibitors. These are followed by a lack of understanding of an undeniably complex market.

Revenue and ceding control to third parties appear lesser but notable barriers.

Those findings ring true both with aggregators and businesses that have had to sell DSR within their own organisations.

MOST FIRMS HAVE SOME FLEXIBILITY In terms of unsuitable equipment or processes, Sam Scuilli, regional director for international sales at Enernoc, says most I&C businesses have a degree of flexibility to harness.

Sam Scuilli, Enernoc

“It is hard to generalise, but we find that most plants have some level of flexibility. It may not be at the level that they want or expect.

But it may be a way of getting into the programme with equipment that

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Louis Burford, Restore

was not part of their normal thought process - and then expand as it grows,” says Scuilli.

“When internal engineers actually dig into their equipment and processes with an eye to the specific

Simplifying DSR in the public sector Public sector procurement body the Crown Commercial Service manages £2.3bn annual spend on utilities and fuels. It currently has around 30MW of DSR via three aggregators – Ameresco, Flexitricity and Kiwi Power - although it will tender for a replacement framework agreement in January.

Much of its contracted DSR is via STOR using back-up generation, but frequency response and the capacity market appear to be growth avenues, according to portfolio development manager Julie Braidwood.

“We are looking to increase the DSR we have contracted as much as possible,” says Braidwood. “There is a huge opportunity within the public sector estate.”

Amongst its diverse portfolio, the service has been working with National Grid to bring more hospitals into balancing services, identifying through workshops challenges, barriers and solutions to help NHS Trusts build business cases.

It is not a simple process, says Braidwood.

“The onsite energy manager thinks DSR looks interesting and could provide revenue. They have to speak to the estates team, who will look at the asset register. Then they have to get in touch with the finance guys to ask whether they can go ahead; there might be some invoicing arrangements, there might be funding required. Then they have to consult with the clinicians, who are acutely concerned about any break in supply. So it is critical for them to make sure there is a rigid safety process in place before they go ahead “Lastly, somebody from procurement will need to get involved to choose the supplier that is offering the best value.

As you can imagine in the public sector, that involves a fair amount of paperwork.”

That means “six months at best” before getting the to business case stage, says Braidwood. “And that is before you have even started talking to the DNO (distribution network operator). So the timescales are long and there is a lot of complexity.”

In response, Crown Commercial Service is putting together a ‘how to’ guide and business case template for the NHS. “If there are 400 hospitals, there are going to be 400 business cases to write,” says Braidwood. “Rather than reinventing the wheel, lets just have one version of that and ensure they can be confident of accessing the right services.” programme rules, creative and innovative engineers can find ways to participate. Then it becomes a financial discussion, because [the finance people] trust their technical people.”

If the finances stack-up and the service provider can make the concept accessible to all decision makers, much of the battle is won, says Scuilli.

“While is not true that every business has suitable equipment, with an element of creativity and can-do attitude, most companies will find that they do.”

But before reaching that stage, aggregators have to break through the barrier of “’don’t touch my stuff’”, he admits.

Louis Burford, vice president,

Pieter-Jan Mermans, Restore

Restore UK, agrees.

“Not every I&C consumer in the UK has flexibility, but for the majority, it is a perceived risk.”

He says it is key to know about the customer's specific processes before initial site visit. “That way you can have a very technical conversation – because it is the technical aspect they are concerned about.”

“Financially it makes sense, it is money for doing very little,” Burford continues. “So the FD is happy, the energy procurement guys are happy, but the operational teams have an initial nervousness that takes time to overcome.”

Burford thinks DSR suffers from a legacy perception of clunky mechanical processes. Today,

21

automation technology means that productivity does not have to be impacted – and aggregators can unlock even small pockets of flexibility.

For example, says Burford, an asset that cannot be turned off or on more than 12 times a year can still be brought into FFR markets via aggregation, so that even a very small number of hours of flexibility throughout the year can be monetised.

Restore’s co-CEO and co-founder, Pieter-Jan Mermans, underlines the need to cross technical bridges first.

Once that is achieved, he says that Restore has “never encountered major questions” around the financial business case.

Chris Kimmett, Open Energi

Q&A with John Conlon, Facilities & Engineering Europe, Marriott Hotels International What is the biggest challenge in implementing demandside response?

Getting our internal audience to understand the concept of “turning down” at their peak operating times.

How could the market work to overcome market barriers?

I don’t see enough PR on the subject.

Have you used the revenue from DSR participation to fund other energy initiatives (and if so, what)?

No. The revenues have not been significant but the PR has been.

How has your participation in DSR grown?

We have increased our participation in the UK and are now exploring opportunities throughout Europe.

What advice can you give to energy managers selling DSR to the board?

Create ‘sales flyers’ that are clear, concise and compelling to promote the concept. Focus on cost and PR benefits.

TRUST ISSUE Almost 90% of survey respondents that do not yet participate in DSR said they would do so if it did not interrupt their core business. That suggests Restore’s view around perceived disruption is correct. It also suggests that while National Grid and aggregators have stepped up customer engagement, there is still work to do in terms of market education.

Mermans says he has no issue with the current market framework and that the company “does not complain” about perceived barriers.

He says his only request of National Grid is to keep making “mature statements to the generic press” that demand-response is a positive development, not a negative one.

“The more Cordi O’Hara and her team make these statements, the more we will create a broader understanding with plant directors,

financial controllers, etc., which is required. Because they are part of the decision landscape,” says Mermans.

“Our message is not that ‘DSR will become a success if rule 1,2,3 are changed’. We believe that is not true and that the battle is elsewhere; we believe that the battle is in technology and in trust with consumers.”

MESSAGING, MIXED MESSAGING AND COMPLEXITY Chris Kimmett, commercial manager at Open Energi, says market education programmes are beginning to bear fruit.

“There is momentum in the market compared to last year. People are starting to come to us rather than vice versa. Energy managers are moving away from the mantra of ‘use less and buy better’ to ‘use smarter’”

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Philppa Hardy, Delta-ee

However, he says the core challenges remain the same.

“The education and information piece has definitely helped. But it’s still not people’s day job and it will never be their number one priority.

“It’s on the agenda of energy managers but it’s not on the agenda of the next level down - site managers or business process owners. The challenge is to get the message down from energy managers and also up to board level.

Then you can drive change and scale up a lot quicker.”

Philippa Hardy, senior analyst with consultancy Delta-ee, agrees that it is a complex market to fathom for people getting on with core business.

She thinks competing market actors can compound the issue.

“Complexity comes in different forms: Complexity over what demand response is and how it works; but also complexity around the different messages being given by different stakeholders,” says Hardy.

“It can be quite complicated and hard to compare different propositions from a customer perspective. Then you have the complexity around contracts - and this all leads back to time and hassle, which is a barrier in itself,” she says.

It's complicated, so simplify it “One of the biggest barriers for customers is that a lot of the services are technically quite complicated, so there is a hell of a lot for them to understand,” says SmartestEnergy’s Robert Owens.

“Some customers have the time and resources to put into unpicking it. Others don’t like to be in a situation a third party knows all of the detail. So they need a partner to help them through that complexity.”

While being that partner is one way for suppliers and aggregators to make money, Owens believes it is a suboptimal approach.

“Ultimately it would be better if the schemes themselves were adapted or changed to reflect that not everybody is building a CCGT or is a licenced supplier who understands that sort of detail. Because if you can improve people’s understanding you can open up a lot more opportunities.”

Building the business case United Utilities energy manager Andy Pennick says developing the DSR business case is not easy, but advises firms to start the ball rolling.

The energy required to treat and move water costs United Utilities around £60m a year. But the company is offsetting that bill via a growing demand-side response programme: It responds to peak network charges (Triad and red zone avoidance); operates its standby diesel engines in the Stor market; and is scaling its frequency response participation.

“How easy it is to get a business case together for DSR? The top and bottom of it is that it's not easy. It is confusing as a customer, confusing as a business, confusing for somebody who has spent a long time looking at it. So you need to spend some time looking at what you could do and then match it up with your assets and the risk that you are prepared to take.”

A water company can take no risk whatsoever with its core business, says Pennick.

“Building an investment case, you always have to look at the risk versus the reward. For us, the risk is technical risk against not doing what we are meant to be doing. That is, providing excellent quality drinking water or treating wastewater so that it can be returned safely to the environment – which we never put at risk. So DSR has to operate within the golden rule of ‘don’t affect my business, just flex what I do’,” he says.

Short contract terms are a hurdle to clear within business case building, says Pennick.

“I have to invest a certain amount of money, but if I only have a one year contract term and it doesn’t pay back within that year, that is a struggle to get past the board,” he says.

While contract terms and complexity are barriers industry must address, Pennick says that they are not impassable, as proven by United Utilities' ongoing investment in DSR. Businesses should grasp the nettle, he advises.

“Don’t get paralysed by choice, just make a decision and start. But start small,” says Pennick. “Develop a trial, pick an asset. Do it for a month, review it and see what happens. Once you have a solid concept you can roll that out across the business.” independent third party within DSR procurement. The idea is to assess customer’s flexibility and produce a specification that providers can bid for on a like-for-like basis. “I think something like that would unlock the market,” Baddeley suggests, but he admits there are question marks over margin.

STOP, COLLABORATE, LISTEN

TRANSPARENCY Adam Baddeley, head of energy at Eunomia, agrees that “the opaque nature of the ancillary services market” can lead to reluctance to engage from end-users.

“We haven’t seen services being procured in any sort of way that is pricing transparent,” he says.

The consultancy is mulling whether to partner with an engineering firm to become in

Others are less convinced another middle layer is the way forward.

“I don’t think you need an independent party to come in between, more that the companies should work together,” says Alana Johnson, products and flexibility manager at Dong Energy.

“The different parties that can provide the different value streams should start working together. It is better to use the experts in their different fields,” she says. “I think that is where we will find the greatest value for the consumer without confusing them too much.”

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Alana Johnson, Dong Energy

REVENUE CERTAINTY Another customer barrier is around certainty of revenue, which also crosses into market barriers. It is hard for energy managers to make a compelling business without longerterm revenue assurances.

Dong, along with other aggregators and suppliers, sits on National Grid’s Power Responsive group. Johnson says simplifying the market and providing more certainty are high

Industrial view: Clearer signals, higher value Mark Fitchett, head of electricity procurement at Ineos-owned chemicals firm Inovyn, says he is “all for demand side response, but sceptical about where we will end up”.

The firm participates in DSR in six of its eight European markets, but does very little in the UK. That’s because, along with Germany, “the UK is the markets where the value is lowest,” he says.

He also questions what ‘DSR’ actually means.

“If DSR is about making small embedded generators centrally dispatchable to National Grid – that is great. But it isn’t demand flexibility. And the economics of those two and the models that you need are very different,” says Fitchett.

“We run a big site and yet my manufacturing manager doesn’t like doing this, because it could be putting his job at risk and his job is to make chemicals. So you have to be going with a value proposition and a risk proposition and that is a difficult sell.

“We are a big user, we have been doing it for years and it is still a difficult sell. So if you are going down into smaller companies it gets harder.”

Fitchett believes that the market signals need to be simple and clear if DSR is to scale.

“If we can find an easy way of getting those signals and then we can operate on them. But you have got to keep it simple because even the most sophisticated users aren’t.” on the agenda – and that market makers recognise the need to act sooner rather than later.

“Power Responsive has created a lot of interest, Ofgem has put a lot of papers out into the market and [end users] are interested. They hear flexibility might be the next big thing to think about,” says Johnson.

But she adds that there is a risk that if the market is not sufficiently clear on how customers participate with different assets, “they will just step away again”.

“So if we don’t come together and make it clear how different customers participate in the different schemes – and maybe give a longerterm guarantee on payments - there is a danger of losing that very good level of interest and not capitalising on the value of the flexibility that, currently, is just sitting there.”

SHOULD NATIONAL GRID LOOK LONGER TERM? National Grid says it recognises the need for simplification and that short-term revenue streams can create difficulties for organisations contemplating DSR provision.

Speaking at the Power Responsive conference this summer, Cordi O’Hara, director, UK System Operator, said Grid “absolutely takes the point about simplification. We need to do better there.”

In terms of contract terms, National Grid received “lots of feedback around the duration of revenue streams” but O’Hara suggested that

Cordi O'Hara, National Grid

its hands were tied to a degree by its own incentive structure.

“The system operator has typically been incentivised over very short timescales with very prescriptive services so that they can compete to lowest cost and be held to account with the regulator. Do we need longer term revenue streams [and if so] how long do they need to be?” she said.

“We recognise businesses might need to change the kit in the factory – and must present that to a CFO and create a business case – and that a one year [contract] isn’t going to cut it. But where should the signal come from? Is it through longer-term incentives on the system operator, or is it changes to the capacity mechanism?”

O’Hara urged businesses to provide their views on that subject via the Power Responsive Platform.

“That would [enable] a very different set of conversations with both regulator and government.”

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Ofgem: Value of flexibility will soar The value of businesses’ flexibility is going to increase “a lot”, according to Andrew Wright, senior partner energy systems at Ofgem, “maybe by orders of magnitude”. He says the regulator will help businesses unlock that value and that firms that invest in DSR should be highly confident of return on investment.

The loss of thermal plant means the UK system is losing cheap flexibility that resulted “almost as a side effect” of a fossil-based power system, said Wright. Meanwhile, electrification of transport, and potentially heat, will require an energy system to meet potentially greater and much more variable demands than today.

“That is a real challenge for the system,” said Wright.

“Without demand flexibility, it will be really expensive, disruptive and very difficult to achieve.”

Unless carbon capture and storage can be “cracked”, said Wright, “it is difficult to know where cheap flexibility is going to come from”.

Even a system based on CCS, nuclear and “huge” investments in transmission and distribution infrastructure, will “be a very expensive way of decarbonising and will rub up against the challenges of affordability and reliability,” said Wright.

“So flexibility is the key to an affordable decarbonisation of the electricity system,” he said.

“In that sense, you should be very confident that if you have invested in the flexibility of your demand, you are likely to create value for your business in the future.”

Market barriers, challenges and manoeuvres Aggregators and consultants weigh in on market challenges, manoeuvres and the long road to scale A uneven playing field, uncertainty around revenue and market rules, and lack of access to wholesale and balancing markets are recurring themes in analyses of DSR market barriers.

National Grid System Operator director, Cordi O’Hara raised the issue of whether Grid should be allowed to think further ahead in terms of revenue certainty at the Power Responsive conference this summer (see p24). Terms for the capacity market are largely out of its hands.

Other barriers include dampened market signals negatively affecting customer pull-through as well as the ability of smaller aggregators and suppliers to cost effectively acquire megawatts.

BALANCING IMBALANCE Those calling for a level playing field point to the money spent by National Grid on ancillary services such as Strategic Balancing reserve (SBR) and Black Start, opportunities worth approximately £300m, which are not accessible to DSR. Contract terms in the capacity market are another issue (see p30).

“The overwhelming reason we don’t have more DSR in UK is that the markets aren’t suitable for it and the

playing field isn’t level,” according to Kiwi Power CEO Yoav Zingher.

“The lack of awareness and complexity of the market is an issue, but it is a secondary issue. The issue that we really need to fix is the fact that DSR can’t really bid into the capacity market and the fact that there’s a whole bunch of market like SBR and Black Start that incentivises power stations with tonnes of money

Will half-hourly metering drive more firms into balancing?

The move to bring all business and eventually households into half-hourly metering could potentially unlock the market. But there are mixed views on the level of response that will create.

Kiwi Power’s Yoav Zingher thinks that “the spikiness in the wholesale market is going to be dampened by all the other interventions that are happening. We could be wrong,” he admits, “and if we are, that would be great. But it hasn’t happened so far”.

SmartestEnergy’s Robert Owens thinks volatility will increase when Ofgem’s single cash-out reforms “settle down”. He says that will send signals to customers about the need to balance loads – and stronger signals to suppliers. “[Suppliers] will be approaching customers saying ‘what flexibility have you got that helps us avoid £3000/MWh in deep winter?’” says Owens.

“You don’t have to get that wrong too many times before it becomes very painful.”

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– but DSR is not allowed to play. That makes up the majority of the market barriers.”

National Grid has made progress in encouraging DSR into the balancing markets, says Zingher, with incubatortype arrangements for some of its programmes such as STOR and FFR. “But the reality is that the majority of the money that National Grid will spend, something like £300m over the next few years, is in SBR and Black Start.”

Zingher believes that creates a “perverse situation”.

“DSR is encouraged to participate in a bunch of balancing markets, yet the one place where it is not allowed to participate is where all the money is being spent,” he says.

“That is a squandered opportunity, because DSR could have contributed so much to system security at a really low cost compared to what National Grid ended up spending [on SBR].”

WHOLESALE CHANGE OR LICENCE ACQUISITION? Other market participants suggest allowing aggregators to access the wholesale market and balancing mechanism could lift one of the major

market barriers. Access would enable them to provide customers with new revenue streams and maximise the value of flexible megawatts.

The Association for Decentralised Energy recommended Ofgem changed market rules to allow aggregators to participate in the markets as ‘Balancing Responsible Parties’, one of three recommendations in its Flexibility on Demand report.

Other market participants, however, believe that is not necessary. Limejump, for example, has acquired a supply licence, enabling it to participate in those markets, as has Pearlstone.

Eamonn Boland, manager of consultancy Baringa Partners, thinks other aggregators may follow suit – and not just to access wholesale markets.

That is because some of the benefits of DSR accrue to suppliers rather than aggregators or directly to

customers. Boland cites avoided use of system charges, such as Triad, as an example.

“The value may be £30k-£40k per MW, which might be a third of your total potential earnings. If a third party aggregator uses the customers’ assets to reduce the Triad cost, that benefit accrues to the electricity supplier, who passes that revenue back to a third party aggregator,” says Boland.

Aggregators are therefore reliant on the commercial terms negotiated with the supplier as to how those revenues are split between parties.

“So you straightaway want to become the electricity supplier yourself,” says Boland.

Flexitricity co-founder Alastair Martin agrees it is “likely to some extent” that aggregators will acquire supply licences to access markets.

“But I don’t think it is the best way of approaching it,” he says.

The best way of approaching it

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would be to end vertical integration, suggests Martin. However, with the CMA giving the market the all clear, that approach appears unlikely.

Another way would be to adopt the European Commission’s plan to enable DSR companies to offer variations in customers’ consumption to the short-term markets, without becoming formal electricity suppliers, he says.

“That was a model which could have been pursued. But whether we end up getting a taste of that is unclear because of Brexit.”

Not entirely dissimilar to the ADE’s suggestion, another potential solution would be to “create a type of balancing market participant”, moots Martin.

“Essentially allow a demand response participant, whether an aggregator or a business with its own sites, to offer flexible volumes to the market.” While volumes would be netted off against suppliers’

Aggregators need both big and small sites Flexitricity’s Martin agrees that aggregating small sites is a challenge, but says acquiring big sites is not the only game in town.

“It is not always the case that multisites are cheap to develop. Clearly you expect to get more value from a larger estate, but when it is large, it is often also more complex. While you might try to roll out a large number of sites using the same technology, typically site-by-site variations pop up, and you end up really where you started,” he says. Individual large sites often require more detailed engineering and “more nuances and intelligence” in the design, adds Martin.

“Everybody likes the big sites. But you can’t run your business purely on them. You have to go after the medium and the relatively small. We range in size from around 100kW to well over 20MW on individual sites, and we find that we have to be attentive to all ends of that scale. “ He does agree with Baringa’s Boland that a more informed market will help reduce cost of sales and says platforms like Power Responsive are paying dividend.

“Ultimately, all of these are decisions taken by human beings. And if they already have prior knowledge of what they are talking about, they skip a major step in the megawatt build process.”

accounts, “that volume would be available to the market in the shortterm within-day,” says Martin.

“That is probably the easiest option to do quickly,” he says. “I am not sure it is the best option, because it doesn’t solve all of the problems in the market. But it is certainly worth a good bit of thought.”

SUPPLIERS VERSUS AGGREGATORS While aggregators mull supply licences, suppliers are making “defensive moves” in the aggregation market, according to Baringa’s Boland. If they can get it right, he believes they have a significant advantage over aggregators in terms of ability to scale.

The firm has advised on DSR company investments and acquisitions. A big hurdle for aggregators, says Boland, is the ability to accrue megawatts.

Existing utilities and aggregators

are all eyeing the same type of I&C customers, he says.

“What we see quite quickly is that it is okay to get one or two discreet sites or 1-2MW. But we found it is quite difficult to get to a sizeable portfolio greater than 10-20MW. There is quite a lot of competition for those [large I&C] sites.”

That is where aggregators are at a disadvantage, he suggests.

“Brand recognition, their commercial credibility, is a barrier. If you are taking control of key pieces of kit for a superstore or a smelter, they would be quite slow to hand control over to someone that doesn’t have brand recognition or that they don’t know in the market.”

Those sites may be more confident ceding control to a large utility with whom they potentially already have a relationship, says Boland.

“So that is a soft barrier as we see it. But it is meaningful in terms of getting to a sizeable portfolio.”

That is particularly the case with “genuine” turndown DSR as opposed to behind the meter generation, says Boland. He says the distinction is important because the revenues for fast-response turndown can be much higher.

“In essence there are a lot of individual sites in the UK, but there aren’t that many portfolios of sites that can be used to provide genuine load reduction - and if you are doing individual disaggregated sites, the cost of sales is quite high,” says Boland.

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COST OF SALES While there are thousands of sites that could turn down air conditioning or fridges for half an hour, doing so economically is a challenge.

“This is the crux that we keep hitting when we do these projects.

Yes there are quite a lot of individual isolated sites. But if the cost of sales of each of those isolated sites is high, then it is difficult to build a scalable business model across loads of individual discreet sites,” says Boland.

“Obviously you want to target a portfolio of sites. But the point is those kind of estates are quite aggressively pursued if they are not doing DSR already.”

Boland thinks that National Grid’s target of 30-50% of balancing services from DSR will be “difficult to achieve” for that reason.

“If [aggregators] are having to go around to 30 or 40 parties each with a half megawatt in order to build a 15-20MW portfolio, that cost is very high,” said Boland.

“Because you are doing it on a siteby-site basis, bilateral negotiation, bringing those people up to speed on what are complex products and potentially complex offerings.”

For that reason, Boland is unsure calls to simplify the market would make much difference.

“It is difficult to see how that could change from a regulatory or policy standpoint other than the market just becoming more informed,” he says.

“If those 30-40 individual sites are more open to the conversation with

Energy efficiency a clearer return?

While Ofgem’s Andrew Wright believes “flexibility will become more valuable than energy efficiency” (see p24), that is not necessarily the case today.

Delta-ee senior analyst Philippa Hardy sees a conflict between the two. “Some commercial customers we have interviewed believe they could create more value for themselves through energy efficiency compared to some balancing services,” she says.

Jon Ferris, a director at Utilitywise, agrees.

“If you look at the current market structure in terms of the tariffs and with regard to suggestions [from market participants] about smoothing out some of the DUoS bands, in the short and maybe the medium term, overall energy efficiency is the more incentivised and the easiest for businesses to understand,” he suggests. aggregators then the cost of sales would potentially decrease,” he says.

“But we are not there now.”

That is why he thinks traditional utilities may eventually gain the upper hand.

“If you are a utility with large I&C customer base, it is exceptionally valuable to you,” says Boland. “Most of the suppliers with an I&C retail electricity supply base are looking to move [deeper] into DSR aggregation, whether through acquisition of a start-up aggregator or organically because they have that very clear route to market.”

Should utilities aggressively target demand-side response – and Boland thinks that they will – life could become more difficult for aggregators.

Limejump’s Erick Nygard agrees

Business, Energy & Industrial Strategy = DSR? Open Energi commercial manager Chris Kimmett says regulators and central buyers should focus on one thing: “Open up the markets”.

“Some markets are limited to traditional generators and we know the traditional generators are closing.

We’ll need an alternative, so open up the wholesale and balancing markets sooner rather than later,” he says.

Kimmett hopes that the government department now responsible for energy will “champion” that approach. While BEIS’s priorities are yet to emerge, Kimmett says DSR “sits squarely within its remit: We operate in business, we’re innovative and we deal with energy”. that if utilities can get their act together, the market implications would be significant.

“They are all looking at it,” says Nygard.

“The problem they will face is whether they have the ability to adapt and scale to the market changes. You never want to underestimate anybody, but on the large utility scale, their real option will be to acquire businesses to get there.

Getting there themselves is going to be a ten or fifteen year type game,” he adds.

“If they wait that long, in my extreme personal opinion, a lot of them will just fall by the wayside.”

Nygard concedes that utilities have the natural advantages of brand recognition and customer access – and potentially the stomach to see

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off a new breed of aggregators with supply licences.

“They have the drive and the will to try and do it – but that is not going to be their problem. Their problem is actually going to be to deliver innovation through to the products that they offer,” he says.

“If they can do it, then we would have significant competition coming at us. But I’m just not that concerned about that in the next 5-10 years.”

ONE-STOP-SHOP? Armed with a supply licence (although not yet supplying much electricity) Nygard thinks the future is a onestop shop. Neither large nor small customers want to deal with a plethora of suppliers, he suggests.

“SMEs have enough to do managing their own small business

and we find it is the same with even our very large customers,” says Nygard.

“If they are paying for an energy management platform, paying for their electricity, paying consultants to advise them, engaging with DSR aggregator – at the end of it, they have a lot of contracts to manage. In our view, what is the point?”

Flexitricity’s Alastair Martin, however, is unconvinced.

“I&C and public sector customers are increasingly sophisticated.

They don’t, generally speaking, feel attracted by the one-stop-shop concept,” says Martin.

“They will buy electricity supply from whoever gives them the best price and the best data services.

They will buy energy efficiency from whoever is best at energy efficiency and they will buy demand response from whoever is the best at demand response.”

Utilitywise’s Jon Ferris says the supplier-aggregator model would have to be carefully considered.

“In doing it that way, the customer is usually taking full exposure to the balancing market. Whereas if they are going with a traditional supply contract, they are paying the supplier to bear the risk for very volatile short-term prices and spread that risk across their whole portfolio,” he says.

“So it is swings and roundabouts; having the simplicity of one provider compared to the simplicity of the supplier bearing that volatility and risk on your behalf.”

EMBEDDED BENEFIT CUTS The review of embedded benefits also presents a challenge to market.

Risk of change tends to dampen investment.

More specifically, the 2GW of distributed generation within the capacity market could be put at risk by unconsidered changes to revenue streams, according to Cornwall Energy.

Executive director Nigel Cornwall has also warned that anything but a thorough, wide-ranging review presents “a real risk of killing off flexibility markets before they have developed”.

While much demand-side response is currently provided by behind the meter generation, which may or may not be directly affected by the review, Cornwall has voiced concerns that the broader market may suffer significant damage.

Just get on with it?

Some aggregators think there are no insurmountable market issues. Restore’s PieterJan Mermans says firm “does not complain” and believes that there is sufficient opportunity to create scale.

“Our message is not that ‘DSR will become a success if rule 1,2,3 are changed’,” says Mermans.

“We believe that is not true and that the battle is elsewhere; we believe that the battle is in technology and in trust with consumers.”

Limejump boss Erik Nygard agrees, saying the firm “shies away from lobbying or regulatory change-type issues”. He says while Limejump “keeps track of the regulatory environment, we believe in the UK you have enough granularity of products, enough opportunity, to enable us to scale properly”.

“Embedded benefits are likely to play an important part in creating the business case for investors to invest in [storage and DSR] projects,” he says. “A reduction in embedded benefits overall in this important stage of the development of flexible products could set the industry back years.”

WHAT’S THE RUSH? A significant chunk of distributed generators’ revenue accrues from embedded benefits, largely the Transmission Network Use of System residual payment, often referred to as the Triad benefit. It currently equates to around £45/kW, according to Ofgem. The regulator points out that this is more than double the clearing price in the capacity auctions to date.

It also notes that the Triad payment could increase to £72/kW by 2020, which would significantly distort the market.

Because generation connected to the distribution network is assumed to reduce demand on the transmission network, suppliers with distributed generation on their books can ‘net off’ that generation in order to pay lower transmission charges.

They then pass back some of the savings to the distributed generators.

How much they pay back is dependent on bilateral negotiations, but Cornwall Energy estimates that between 20% and 50% of distributed generation revenues come from the various embedded benefits.

Ofgem has indicated it is the Triad element that may be first capped and then cut – and it is not going to undertake a significant code review.

Its initial thinking also appears to rule out grandfathering of benefits or transitional arrangements. With the next capacity auction in December, it aims to take swift action.

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National Grid, through the Connection Use of System Code panel, is also looking at the issue.

Proposals include stopping generators with Triad payments entering the capacity market.

While the reviews are largely to try and stop diesel farms undercutting new build gas power stations in the capacity market, the impacts will likely be felt by most types of dispatchable distributed generation.

A PYRRHIC VICTORY? Limejump’s Nygard says that the developments put aggregators in a “tricky” position.

“We want to scale but we now have to flag to customers that if they go into the capacity market, there is a risk that they might not have access to Triads,” he says, “and that kind of uncertainty will often make people pull out.”

On the counterfactual, Flexitricity’s Alastair Martin says aggregators could potentially benefit – but it may be pyrrhic victory.

“If the whole matter of embedded benefits was swept away, and there were no longer any special times of day, we would see significant stress to the system. You would be adding potentially 2GW to the evening peak in winter. And you would be exacerbating the post solar peak as well,” he says. “That would be a fairly hard hit.”

Aggregators would arguably make more money, he says, because a system that is more stressed creates more demand for their services. “But I can’t really argue that because it wouldn’t be a logical outcome overall.”

He suggested Ofgem, which is “not known for making mistakes by acting too quickly”, could justifiably take its time with a significant code review.

Flux capacity: Change for the better?

Most stakeholders interviewed for this report voiced frustration at chopping and changing of capacity market policy.

While complexity presents a market barrier across the DSR landscape, Flexitricity’s Alastair Martin believes “the capacity market is probably the area where complexity is most of the problem”.

Depending on who’s counting, he says there have been seven version of the rules and five versions of the regulations to date. Participants need time to assimilate those rules ahead of prequalification, but they have not been given much.

Now there is the spectre of further changes via the embedded benefits review and Defra’s plans for diesel emissions restrictions. Meanwhile the department of energy and climate change has been rolled into the business department.

Martin says complexity is compounded by instability.

“The thing is jumping around all over the place,” he says. “We need the capacity market to settle down.”

METERING OUT PAIN Stringent metering requirements have caused pain. Martin thinks they will “hit the next round of the capacity market fairly hard”.

For many existing sites, new more accurate metering is required for the capacity market. Installing new metering can require site shut down, which for some is not an option.

The metering rules also require certification of all parts of the chain, Alastair Martin, Flextricity

which Martin says is a “tall order; you are essentially saying that equipment needs to be replaced”.

ERROR MARGIN Site size is not taken into account by the rules, says Martin.

“For example, a 1.5% error in a 10MW site is not the same as a 1.5% error in a 100kW site. Recognising that would have helped substantially,” he says. “But that hasn’t been the case, so there will be sites that

Embedding fear Limejump boss Erik Nygard thinks that reviews around the Triad element of embedded benefits could cause participants to steer clear of the capacity market should the two revenue streams become mutually exclusive.

“We have a very small amount of contracts and will be prequalifying more for the next one coming up, but it is a tricky one,” says Nygard. “We want to scale but we now have to flag to customers that if they go into the capacity market there is a risk that they might not have access to Triads. That kind of uncertainty will often make people pull out.”

Erik Nygard, Limejump

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will really struggle to meet these metering requirements.”

There are ways of getting sites through, says Martin. “But if a site has any complexity, or anything special about it, or any combination of assets, then the easy fixes don’t work.”

Another complaint is that the capacity market obliges participants to produce information that can only be only be provided by licensed suppliers, licensed data collectors,

Storage 'theoretically possible but practically challenging' Storage can in theory participate in the capacity market. But in reality, duration requirements rule out many storage projects.

“Much storage may only be able to deliver for half an hour, maybe an hour. Clearly there are no special arrangements within the auction that allow for those shorter durations, which means there is a big challenge for storage to enter,” says SmartestEnergy’s Robert Owens.

“The only real way to do it is by entering either as a fraction of their capacity, so providing a smaller amount over an extended period of time, or in conjunction with other assets in an aggregated portfolio. That makes it a challenge for larger storage projects because it might be more difficult for them to find an aggregator package that they fit into, bearing in mind the CMU size for DSR caps out at 50MW. That means if someone was looking at a 10-20MW storage battery, which is not out of the question, it might be an uncomfortable proportion to try and aggregate,” Owens explains.

“So it is theoretically possible but practically quite challenging,” he says. “It means that for large projects it just may not be an option at all.” licensed data aggregators or licensed meter operators.

Martin says data collectors, data aggregators and meter operators have “no beef” with capacity market participants. “But they don’t have any obligation in their codes, or indeed any particular funding, to help people

comply with their capacity market objectives.”

The same applies to suppliers, says Martin, “and added to that they are probably your competitor. So we have a dependence on companies that don’t need to help us.”

While Ofgem has moved to head

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off the issue, Martin says it is still a problem for some sites – and anything that causes delay to an already tight schedule is bad news.

“My real concern is ensuring that demand response can get through its metering and demand response delivery test within the timescale that

Testing for winter in summer Aggregators and customers have spent the summer testing and proving their resources under the rules of the capacity market. But testing in summer for a service to be delivered in winter may not be truly reflective when push comes to shove, suggests Enernoc’s Sam Scuilli.

“Many customers have different load profiles in July and August than they do in December and January, so I think it will be very interesting to see how those two piece of the puzzle mesh together,” he says. “If the winter period is more valuable to National Grid, perhaps there is a way to prove the resource in the winter time.

“I think we will get some more data as all the aggregators go through this round of testing protocols for the TA to see how their portfolio shakes out,” says Scuilli. “I’m not willing to say that is a problem [at this moment], but it is a problem that could arise.” is provided,” he says. “With all these dependencies and complexities, that is quite hard to do.”

TERMS AND CONDITIONS Contract lengths remain a sticking point. Some aggregators argue that the capacity market cannot be regarded as technology neutral if generators can receive 15-year contracts, but demand-side response providers just one year contracts.

“It is understood why new build [CCGTs] need 15-year contracts, but more participants will be encouraged if you can give them slightly longer-term certainty,” says SmartestEnergy’s Robert Groves.

“It is not necessarily the case that you need to have an equivalent 15year contract. If you can do a threeyear contract, or five-year contract, that opens up opportunities. It is just making sure that you have the right parity.”

Kiwi Power’s Yoav Zingher agrees that parity is key.

“Do I think DSR needs 15-year contracts? No. I don’t think power stations do either,” he says. “Three-

to-five year [contract lengths] is good.

But parity is parity. If you want to create a technology neutral market, you treat all assets the same.”

An alternative, says Zingher, would be to remove bid bonds for unproven DSR providers in the T4 auction.

“A bid bond is a lot of money. It is the single biggest line item to get DSR up and running,” he says. “With only a one-year contract, nobody is going to finance it, so that is a big barrier.”

Enernoc’s Sam Scuilli believes that the issue is not so much one-year contracts, but a lack of price visibility in the shorter-term auctions.

“What we can’t do is provide

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accurate financial projections for customers. We truly don’t know what a megawatt is going to be worth over the next couple of years. That can be challenging.”

He says that customers can be enrolled on a year-by-year basis, but may then find that the economics do not stack up. Enernoc can find other ways to fulfill its commitment, he says, but it makes life more difficult.

“Candidly, I don’t think the structure of the one-year contracts is significantly detrimental right now, but obviously it would be much better if we had better price clarity moving forwards.”

Yoav Zingher, Kiwi Power

Sam Scuilli, Enernoc

Leading horses to water Does government have the policy right for DSR? Not entirely, believes Anglian Water’s Tom Lee. “I can see some brilliance, but also confusion. We have discussions with Decc and Ofgem and you can often come away with the feeling that maybe you haven’t hitched your horse to the right wagon – and that other wagons are out there. So it is difficult to plan.”

He thinks policymakers should also work to simplify market access.

“We are in the capacity market directly. We have an agreement for this coming winter and we have STOR for this coming winter. But we are not going to be able to use the same meters that we have installed for STOR to participate in the capacity market. Not only that, but the metering systems that we have to install must be twice as accurate as a normal half hourly meter,” says Lee. “We had to invest a lot in metering.”

Going though changes

Robert Owens, SmartestEnergy

A DIFFICULT TRANSITION Decc’s changes to the Transitional Arrangements earlier this year received mixed reviews. The TA's lifespan was cut from three years to two, volume was reduced and a requirement for turndown only DSR stipulated.

Encouraging turndown DSR as opposed to behind-the-meter generation is a good thing, says SmartestEnergy’s Robert Owens.

“But changing the rules of the transitional arrangements in the middle is unhelpful.”

Turndown DSR is one of the lowest carbon intensive ways of delivering flexibility, says Owens. But the challenge for SmartestEnergy is that the TA was supposed to be a way of easing customers into the main auctions.

The department of energy and climate change, before being subsumed by the expanded business department, made perhaps the biggest set of changes to the capacity market in March. Its decision to buy more capacity earlier reduced certainty around the T-1 auctions. That means DSR aggregators have to convince clients to think four years ahead, which many say is a challenge for businesses looking at annual budgets.

The move to stop new diesel farms being built via emissions restrictions has been welcomed from an environmental perspective, but there are fears about how the measure is implemented with regards to existing generation as well as back-up generators. Little detail has emerged from Defra, although the department has warned: ‘Investors bidding for new capacity into the Capacity Market auctions in 2016 should be aware that installations with a thermal input less than 50MW that become operational after the publication of proposals are likely to be directly impacted when the legislation comes into force.’

Decc wrapped in a review of the embedded benefits regime into the March announcement, noting concerns that the payments generators earn via Triad benefits was distorting the capacity market. The outcome of that review could significantly affect the types of generators bidding into the capacity market – and the auction outturn as a result.

The next T-4 auction takes place December 2016, the early auction January 2017 and the final transitional arrangement auction in March 2017.

“Effectively the rules have changed halfway through the process, so it is not really a transitional arrangement anymore.”

Ruling out generation also cuts off a route to customer growth, Owens suggests.

“Where people have onsite generation, that is an easy place to start. Then we can explore what they might be able to with turndown DSR. If you exclude them from the transitional arrangement you risk not having that first step.”

Kiwi Power’s Yoav Zingher goes further. He says Kiwi is fully behind turndown DSR, but that the TA is “not a route to market”.

“The original intention of the TA was three years of a growing market [that would then] bid into the main auction. But everything

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has changed now,” says Zingher.

“The TA ended up being reduced from three years to two, and it has more or less been scrapped for next year, because the volume has been reduced to 300 megawatts and they have changed the rules so that it is turndown only. That means the TA is not a route to market.”

Zingher thinks a better plan would be to create a firm, if modest, three-to-five year turndown market, enabling participants to develop technology and build customer understanding.

“That would provide a growth path towards serious volume. As it stands the TA is a one-year opportunity that is guaranteed to go away and no one is going to sell that,” he suggests. “It is a really missed opportunity.”

Putting more power in consumers’ hands National Grid has been running its Power Responsive programme, which aims to rapidly increase participation of the demand side in electricity markets, for just over a year. The programme’s manager, Paul Lowbridge, talks progress, priorities and how a changing energy market is putting consumers in control.

As the UK’s electricity system operator, it’s our job to balance supply and demand on the system.

A rise in renewable generation is redefining the energy landscape.

It’s creating fresh challenges for us, but exciting opportunities for energy users.

As the energy system moves into a low-carbon future, managing it requires a shift in thinking. With available power in decline, energy users hold the aces. We need more of you to manage your energy use flexibly; to turn your assets up or down, or shift their use, to help keep the system in balance.

What’s in it for you? Well, we provide the means and motivation - through reduced energy costs and extra payments - to do it. The power’s in your hands.

We launched Power Responsive - our programme to drive a rapid increase in demand side participation - just over a year ago. We’re making good progress, but you’ve been clear in telling us what still needs to be done. You see barriers to participation. You want simpler products and clearer markets. We’re listening to what you’re saying and we’re committed to addressing them.

SO WHERE ARE WE NOW?

Against this backdrop, we believe that giving customers easy access to demand side services and helping them manage their energy use more flexibly continues to be of great importance. We see the balance of power lying with consumers for years to come.

WHAT ARE OUR MAIN FOCUSES FOR YEAR TWO? We’ve put solid foundations in place.

Now we’re ready to build on them and deliver the evolving flexibility markets that will help secure the system for the future.

By ‘flexibility’, we mean sources of electricity that can be delivered at a given time in response to a signal.

It includes non-traditional sources such as demand side response (DSR), distributed generation and storage, which is our focus for Power Responsive, as well as more established sources such as transmission-connected generation and interconnection.

We’ve talked a lot about commercial and industrial DSR in previous articles and many of our products are already well established, such as our Short Term Operating Reserve (STOR) and Frequency Response services. But we’re now looking to extend our reach to cover

The first year of Power Responsive has delivered a surge in awareness and interest in the opportunities that exist in flexibility markets, particularly the demand side.

We’ve also been busy shaping the concerns that you’ve shared with us into a cohesive set of priority work areas. We’re already seeing some early wins, particularly with our Firm Frequency Response bridging contracts, which allow new entrants with lower volumes to enter the market. More on that later.

The electricity market continues on its trajectory towards decarbonisation and decentralisation.

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distributed generation and storage.

Power Responsive will continue to be the vehicle through which all our work will be progressed. Every step of the way, we’ll be working collaboratively with a broad range of market players and potential providers of flexibility. Our stated intentions for year two are to:

1. Continue to engage customers on opportunities in flexibility markets. Industrial and commercial users will continue to be a focus, and we’ll engage with the emerging sources of flexibility that we described above.

2. Increase confidence in flexibility as a product to ‘sell’. We’ll do this by improving the quality of information and market signals we provide, so that aggregators, customers and investors build more confidence in the markets they’re operating in. We’re also supporting the development of a code of conduct for aggregators

by Association of Decentralised Energy (ADE). This will build trust and credibility in the industry and gives customers the confidence to participate.

3. Support the evolution of flexibility markets. We’re determined to

simplify flexibility products and make markets clearer and easier to participate in. This will be key to helping more customers reap the benefits of using their energy flexibly.

WHAT OTHER CHANGES ARE WE SEEING IN THE ELECTRICITY MARKET - AND HOW ARE WE RESPONDING? With distributed generation rising - particularly wind and solar - and overall demand falling, the system has become more challenging to operate in the summer.

In terms of how that affects the way we operate, new challenges emerge on windy and sunny days in particular, with a baseload of nuclear and wind generation exceeding the lower demands.

We identified this as a potential problem last year and responded

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by procuring 300MW through our Demand Turn Up product. It’s a new balancing service which incentivises companies to use more power - or reduce their generation - when there is too much on the system.

While we anticipated this development in the market, it’s moved even faster than many perhaps expected. In August, we actually saw an example of national demand at transmission level drop below 17GW. So Demand Turn Up has been a part of giving us the facility to meet the challenge head on.

In a low-carbon landscape, Demand Turn Up has already become an important balancing tool. We expect this need to continue and will be buying the service again this year.

So if your business has the flexibility to provide volume to us in this way, it could provide an attractive, ongoing opportunity.

FIRM FREQUENCY RESPONSE (FFR) Breaking down barriers to entry is a key focus for Power Responsive. One area where we’ve seen real success has been the creation of our FFR bridging contracts.

Our main tendered FFR contract requires customers to provide a minimum of 10MW. However, we received a lot of feedback from consumers that they wanted to take part, but only had the ability to provide a fraction of that. In response, we developed a growth plan, delivered through a bridging contract, where businesses can enter the market with just 1MW.

This has broken down a significant barrier and opened the door for new providers to participate in DSR. While we’re pleased with this progress, we’re keen to develop it further. For now, FFR bridging is only available for providers of static response (where the service is triggered by an agreed change in system frequency). So we’ll be looking to extend this to dynamic response (continuously provided) too, and broaden its user base even further. Some users have told us they had a bumpy ride during their transition from bridging to joining the main FFR market. So we’ll be working hard to iron out those initial

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teething problems and ensure that transitions happen more smoothly in future.

HOW CAN WE BE SURE OUR PRIORITIES ARE THE RIGHT ONES? Through Power Responsive we work closely with businesses, suppliers, policy makers and other industry stakeholders to make sure the priorities we set are the right ones.

As I mentioned earlier in the article, many of you have asked us to improve our market information, and simplify products and markets. And we’d now like to hear more about the specific things you want us to change in these critical areas.

To make it simple for you to tell us, we’re developing a short questionnaire (four short, but urgent questions) which we’d like existing and potential providers to complete.

Please look out for the questionnaire and provide us with your input. Your support will be greatly appreciated.

By providing your responses, you’ll play a direct role in shaping our future work. We’ll use your vital feedback to underpin the changes that need to be made.

Now’s the time to be a part of how we shape the flexible energy system of the future. The power’s in your hands.

Demand-Turn Up: What works and what doesn’t in trial summer balancing scheme Demand-turn up (DTU) is intended to balance the grid when demand is low and renewable generation is high. National Grid launched the service this year to run from May to September to help counter an all time low in summer demand, a trend the system operator believes will continue summer months is not that much – so when you stack everything together, you still don’t beat the price that you would lose for turning off.”

Doubling the payment would work, Nygard believes.

“But it depends on the Roc multiples. Rocs are £40 and some solar sites are sitting on 1.3 or 1.4 Rocs. So you are talking £55 plus the power price at £40 so that is already £90,” says Nygard. “At [current DTU rates] £60 to £75, doubling it would make a return for them, broadly.”

In all, Grid eventually procured 309MW of response, with businesses either turning down onsite generation or turning up loads in return for utilisation payments of up to £75/MWh plus a small availability payment. They do so overnight or during the day on the weekends and bank holidays.

MANUAL HANDLING For end-users, one of the benefits of DTU is that they are not being asked to make “heavy commitments”, according to Flexitricity’s Alastair Martin. “That means that their flexibility can be limited within the needs of their core business processes.”

Other aggregators agree that the manual nature of DTU is a limiting factor. But Martin points out that DTU will be fully automated from next year, which should help build scale.

Tweaking the incentives for businesses may also be required, he believes.

“DTU heavily incentivises utilisation payments over availability”, Martin points out. That is the opposite approach to frequency response, he says, which offers relatively low payments for utilisation.

“DTU as it stands is very ad hoc – remember it is a trial and it is OK to have wobbles in delivery. But experience shows quality builds when people are paid for the commitments that they make. So ultimately [providers] are going to need to see that in an enduring service.”

MORE MONEY Enernoc’s Sam Scuilli says the firm is involved in DTU services in Ireland.

But in the UK, “we don’t feel there is a viable financial opportunity there for customers as currently constituted”.

DTU is part of the single electricity market in Ireland and it is “fully integrated”, says Scuilli. “Customers are earning significantly higher returns than they would under the

proposed construct in the UK.” Scuilli thinks that may change over time as summer demand decreases and renewable penetration increases – but he still sees the market as challenging.

“During the day, disconnecting your solar and consuming from National Grid doesn’t make a tonne of sense, or you turn off your CHP and pull power from the grid. It is actually not that easy to turn up regular loads at scale - generally things are either on or off,” says Scuilli.

“The money will never be there to incentivise people to make more widgets or to bring another machine online. Most plants are run much more efficiently than that. For the most part, they don’t have idle capacity sitting around.”

DOUBLE OR NOTHING Limejump’s Erik Nygard thinks that payments must increase significantly for solar generators to consider DTU. As it stands, Limejump is instead layering solar into frequency response, which has both low and high requirements.

“DTU is definitely not economical for them to do it. For me, more or less double [payments] would be necessary,” he says. “[DTU participants] have two line items. They have an availability fee (£1.50/MWh) and a utilisation fee (£60/MWh or £75/MWh),” he explains.

“The number of hours across the

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PERVERSE INCENTIVES Whether DTU’s stock will rise that high remains to be seen. Restore’s Louis Burford points out that there is good reason for lower payments.

“National Grid does not want to incentivise companies to use energy that they don’t need to use,” he says. “So DTU is a smaller target audience because you have to look to environments that are going to use the energy anyway - they are just incentivised to cover their energy costs to use it at certain times.”

Restore has 25MW participating in DTU. Burford said that “could have been fourfold” but for telephone dispatch. That creates staffing issues for providers, given that the service operates overnight and on weekends and bank holidays.

However, Restore shares Flexitricity’s confidence that automation will drive uptake.

National Grid this summer predicted a minimum demand of 18.1GW. “Can you imagine how low that is and what type of challenges that raises for the grid, given the huge amount of baseload generators that will not stop producing,” says Restore co-CEO Pieter-Jan Mermans.

“So it is very logical that demand response plays a large role there.

The market just needs a bit of time to go from ‘demand response equals curtailment’ to ‘demand response equals flexibility in both directions’”.

Battery storage: Positive outlook?

Costs are falling but batteries are still expensive. Bankable revenues are hard to come by and developers want more routes to market. But others believe they are commercially viable today.

Energy storage is seen as the answer to balancing intermittent generation. Batteries are particularly valuable to National Grid because they offer subsecond frequency response.

Costs are falling and investors and developers appear to have significant appetite.

National Grid has created a market and the first enhanced frequency response (EFR) tender, was massively oversubscribed. More than 1.3GW prequalified for 200MW on offer.

SOLAR APPETITE A degree of that appetite was from solar developers, who have seen their markets hit by subsidy cuts.

Batteries and solar PV are also highly complementary technologies.

But most prospectors find themselves without an EFR contract.

Market participants have called on National Grid to outline a route to market to maintain momentum.

“It would be a shame if that interest disappeared, because it is hard to regain momentum,” says SmartestEnergy’s Robert Owens.

“Over the last nine months we have gone from hardly anyone talking to

us about batteries to a pipeline of 800MW-1000MW. That is virtually unheard of.”

Cost versus bankable revenue is a market barrier. Businesses and investors have to work out how to stack revenue streams and take on a degree of risk. But some market participants believe batteries are a viable opportunity today, due to the flexibility they can unlock.

COMPLIMENTARY TECHNOLOGY Most market participants see batteries and demand-side response as complimentary technologies.

“Because of the raw flexibility in the battery, it can do whatever you tell it to do – anytime granular speed of response,” says Limejump CEO Erik Nygard.

“Combining a battery with DSR or generator means we can unlock a lot more flexibility from those asset types. An asset that I cannot turn on or off very frequently does not have much value on its own. But putting a battery alongside that asset allows me to create a new product to unleash value, because they are now working together to deliver something much more

proficient to National Grid.”

Nygard says Limejump currently uses batteries alongside solar PV to provide frequency response services, among other revenue streams.

SHORTER ODDS Kiwi Power CEO Yoav Zingher thinks that combining batteries and DSR will cut costs by enabling much smaller batteries to be used.

“You can make do with a battery with a shorter duration as well,” he says.

“Instead of building a battery that can deliver an hour’s worth of response, you can use a battery that delivers only 10 minutes of response and provide the rest with DSR, which can’t deliver response so quickly. So we think if you design the market well enough you can get more benefit from both.”

Zingher thinks there will be a “huge amount” of battery storage deployed as prices fall.

DOMESTIC OPPORTUNITY Restore co-CEO Pieter-Jan Mermans agrees that batteries are a “huge opportunity” for DSR – and not just for the commercial and industrial market.

The battery business case ‘already stacks up for I&C firms’

Seven firms take first EFR contracts

“It is not a small investment decision,” but the business case for battery storage already stacks up, according to Richard King, of energy management engineering firm Powerstar.

King says peak shaving for DUoS and Triad combined with frequency response revenues are in some cases secondary to the value of an onsite UPS “to cover the ‘microcuts’ we are increasingly seeing on the system”.

Combining the three elements makes a commercially viable proposition, he says, but early investors in the I&C sector are likely to be those who understand the value of lost load to their business.

“If you know that cost, you can monetise it – and it can be worth a great deal. If you are part of a supply chain, you may face very punitive penalties,” says King. “The ability to respond to a power shutdown within 20 milliseconds is very valuable – as are cutting network costs and generating income from frequency response.”

National Grid awarded the first round of EFR contracts to seven companies. Renewable energy investment firm Low Carbon was awarded two contracts totaling 50MW, EDF a contract for 49MW, Vattenfall 22MW, Eon 10MW, Element Power 25MW, RES 35MW and Belectric 10MW. National Grid said that of the 64 sites that make up the 201MW total capacity, 61 are battery assets, two are demand reduction and one is thermal generation.

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Restore, he says, will ultimately move into the B2C sector, with batteries likely to play a key role.

“We operate in Germany, where more than 10,000 batteries have been installed, with the primary purpose of balancing solar electricity.

People are looking at how to wrap them up into a 50MW block to offer to the TSO,” he says.

“From our point of view, that is exactly the same question as aggregating 50 pumps or compressors. So that is complementary. Battery operators will need DSR technology and software and vice versa.”

POSITIVES AND NEGATIVES Chris Kimmett, commercial manager at Open Energi, thinks behindthe-meter applications face few regulatory barriers and will work if asset owners can make the business case stack up.

“The price has come down to the point where it is starting to make sense to buy batteries,” he says.

But Kimmett also points out that the Brexit impact on Sterling has pushed prices back up by around 10%.

Despite that, he says it is “still an interesting place to invest”.

Sam Scuilli, regional director, international sales at Enernoc, agrees that it is “not too soon” to start looking at batteries but says they are

EFR tender: a bidder’s view Origami Energy took part in the Enhanced Frequency Response auction but, like most bidders, did not secure a contract. Simon Wilson, the firm’s storage lead engineer, says the mere fact National Grid has created a market is breaking down barriers and that the auction values will be useful information for storage project investors.

Wilson believes there are improvements that could be made for the next tender. As things stand, the £5k/MW bid bond favours larger developers, he suggests.

In terms of technical requirements, Wilson thinks ramp rates may have been “overly complex” and that the duration requirement of 15 minutes in either direction was more than the service needs, leading to costs being “slightly greater than necessary”.

Wilson also thinks that locking providers into EFR is potentially a missed opportunity.

“You can do multiple things with your site but if you are contracted for EFR, you must do it, so you can’t switch to a merchant model. If there was a price spike for example, you can’t then use your storage to meet that,” he says.

“The problem with energy storage is that you generally have to knit together a few revenue streams. So being able to be flexible and respond to market changes matters.” just one tool for National Grid.

“Batteries are specifically suited to fast response. But if you have a major capacity shortfall, there is probably not enough batteries that are going to help with that,” says Scuilli.

“That is where you need the broader capacity market or the whole Triad structure, which is designed to shift significant amounts of load.”

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MARKET CORRECTION Flexitricity chief strategy officer Alastair Martin agrees batteries “will find their niche”. But he thinks there will be a lot of disappointed developers.

“There has been a lot of noise and a massive rush – far in excess of what the EFR tender aims to stimulate. We are going to see a correction as a result,” says Martin.

Courtesy of National Grid 'Future Energy Scenarios 2016'

Grid predicts big future for batteries In its latest modelling, National Grid predicts a significant future market for batteries.

According to is Future Energy Scenarios report, Grid sees potential for up to 18GW of electricity storage, much of it batteries, by 2040, most of which would be connected to the distribution network under its ‘consumer power’ scenario.

In the short term, National Grid plans to review its current set of schemes and how they interact to allow storage providers to offer bundled services. That review is scheduled to commence in autumn 2016.

National Grid said it expects Lithium-ion battery cell costs to halve in the next three years, from around US$400/kWh to $200kWh by 2019.

Meanwhile, the system operator also forecast the maximum contribution from industrial and commercial demand-side response standing at 5.7GW by 2026.

“We have double-digit gigawatts of batteries in the planning system, the majority backed by people who believe that there is a frequency response contract waiting for them. But there isn’t a double-digit [gigawatt] requirement for frequency response,” he says. “So we are going to see a correction in that market.”

REVENUE CANNIBALISATION? Baringa Partners manager, Eamonn Boland, sees batteries as cannibalistic rather than complementary to DSR. “Batteries and DSR are in direct competition. If I were an investor I would see that the DSR market today offers a price of X. But I am seeing quite a large interest and volume of new entrant batteries coming into the market that can do exactly what I can do [and] be built at scale,” says Boland. That will put pressure on prices in frequency response markets, he believes.

“You can easily get to a point where that X value drops quite significantly, quite quickly. So you have a degree of uncertainty over revenue because of the competition coming from high volumes of batteries that are expected to come into the market.”

Batteries will start to spill out from FFR markets into lower value markets

Stacking revenue streams According to a recent report by Everoze for Scottish Renewables, there are 14 potential revenue streams for storage (see table).

Those looking to finance battery deployment have to stack several of those streams together, but they face challenges in terms of tender timings and the technical and contractual requirements of each scheme, according to the report.

The consultancy made a number of recommendations to increase deployment of batteries. These included longer contract lengths to improve bankability; alignment of tender timelines and a review of technical and contractual interfaces so that developers have more chance of stacking them together and reducing risk. as prices fall, Boland believes, enabling new business models to emerge. But for now, he says it is difficult for investors to place sizeable volumes of capital into development because of revenue uncertainty.

“You are confident that there is a need for flexibility and there is quite a high value to the response

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Courtesy of 'Cracking the Code' Everoze

times of batteries. But some people see the breadth of revenues they could provide as revenue diversification and others see it as compounded risk,” says Boland.

“So I think that is interesting for batteries.”

Report sponsors: How to engage in DSR

ENERNOC

SMARTESTENERGY

RESTORE

Enernoc works exclusively with organisations in the industrial and commercial (I&C) sector. At present, the company is primarily focused on the capacity market and static frequency, as well as Triad and DUoS avoidance and management.

Sam Scuilli says that the company looks for a minimum commitment of around 300kW from customers, although smaller loads can be aggregated provided there is a degree of automation.

But not everything has to be automated. Scuilli says while customers are often concerned about losing control of equipment or processes, that is not the case.

Within the capacity market, for example, National Grid provides four hour lead times. That means assets are often not automated, meaning customers remain entirely in control of their assets.

But even automation does not mean ceding control, says Scuilli.

While frequency markets require automation to deliver fast response times, the aggregator works with the business to set operational parameters – rules which respect core business needs and processes, says Scuilli.

His advice to organisations considering DSR participation?

“To be open-minded and creative about it. DSR should be viewed as another business optimisation tool. Whether you can participate or not, the ability to understand how you are consuming energy can have compelling impacts on your business.”

SmartestEnergy started out as an aggregator of power generators, before branching into business energy supply. It is now active in demand-side response via the capacity market and plans to have full service flexibility capability by the end of next year, according to Robert Owens, vice president of demand-side management: “Everything from peak network avoidance and through to wholesale and balancing markets and imbalance management,” he says.

The firm aims not to take “a traditional aggregator approach” but to look at flexibility in the round, says Owens.

“We will take an overall view of the value of customers’ flexibility and where that might be going forward,” says Owens. “Then we will give them access to whichever service best fits their capability, help them understand how those services work and how they can achieve most benefit and help them as that changes over time.”

His advice to organisations considering DSR participation?

“Make sure you are having discussions with someone that can help you through the complication as soon as possible. Also, to have a good reflection and view of what your capabilities might be and what your expectations are. In terms of your overall drivers: Is it about managing your costs? Is it about looking for additional sources of revenue or a combination of the two?

Then it is about drilling down in the detail with someone who can take you through the opportunities and capitalise upon them.”

Restore operates across much of northern Europe as well as the UK markets. Its initial strategy is to target the top 200 energy consumers in each market. It operates across firm frequency response, frequency control by demand management, fast reserve, STOR and the capacity market.

Restore plans to target smaller companies – and eventually households – in the coming years, according to co-founder and co-CEO Pieter-Jan Mermans.

His advice for organisations considering taking part in DSR? “It is about taking that first step.

Make that project a success and take it from there. But do it. Rather than stand aside and wait to see what happens,” says Mermans.

“We have done that with big companies like Total and ArcelorMittal. Those are huge tankers to try to move. You are not going to do that by being hugely ambitious, because you can end up being invited into HQ to present your project – and then it gets decided to death.

“You have to take one step, make it a success, invite other people to look at the success and create appetite and build your relationships from there. That has been very successful for us and I would recommend that approach to the entire community in the UK.” UK vice president, Louis Burford (pictured) says with the right technology and service implementation “even the smallest pockets of flexibility can generate revenue for businesses“.

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Report sponsors: How to engage in DSR

KIWI POWER

OPEN ENERGI

DONG ENERGY

Kiwi Power operates services across several flexibility markets, including frequency response, the capacity market and network constraint management.

CEO Yoav Zingher says the company's investment in proprietary technology, has reduced capex costs to “hundreds of pounds per site”. The firm says payback for companies entering DSR contracts can therefore be within months rather than years, dependent upon the type of response provision, the individual site and works required.

Zingher advises those considering a DSR provision to ask commercial partners the following questions: 1. What are the net/gross revenues per MW (check the percentage and the starting price offered) 2. What references are available from other live sites?

3. For which programmes and seasons do providers have capacity available?

4. Are there penalties for non/under performance during an event?

5. Is it a manual or automatic start up?

6. Does their hardware and software integrate with your IT network?

7. What are the setup charges or licence fees for hardware & software?

8. What is the lead time declaring the site live in a programme?

9. What level of control will they / you have over the assets during an event?

10. Do they offer Triad management services and at what success?

Open Energi operates primarily within the dynamic frequency response markets across industries including industrial and commercial, utilities and the public sector.

Its customers provide flexibility in both directions – up or down – to help balance the frequency of the power system.

The aggregator has also launched an initiative alongside sustainable development organisation Forum for the Future called 'The Living Grid', a platform which it hopes will help drive uptake of battery storage and demand-side response.

Commercial manager Chris Kimmett believes that the faster demand response services hold the most value.

“Frequency response is a key challenge for National Grid and our message to customers is that it is the place to be,” says Kimmett.

His advice to companies considering DSR? “Do it in a very structured way and bring people on board with you. Demand response can be complicated. It needs energy insights to join up the dots, so the clearer you can make the underlying reasons for demand-side response provision within internal communications, the better.

“Bringing people in – from operations, to management to finance, and championing it along the way can really help expedite the process. Then you can drive change and scale up activities more quickly.”

Generator and business energy supplier Dong Energy’s UK generation comes exclusively from wind. As with all energy companies, Dong has to balance its position within the balancing market – and new rules make it more expensive if does not.

Dong believes customers can help mitigate that cost by turning down consumption or switching to standby generation.

It has therefore entered the DSR market with a simple product called Renewable Balancing Reserve that requires no firm commitment from customers.

Customers set the price at which they are willing to shift consumption – and Dong guarantees to take that price if it helps economically balance its position. Dong will also share with that customer any additional savings it makes as a result of their actions.

“We want to balance intermittent generation by using customer demand – and make it easy for them to participate and understand the value of their flexibility,” says Alana Johnson, products and flexibility manager at Dong Energy.

“A customer can set different prices for different times of day, they can say they are only available in the evening or morning or just for one hour of the day. We can capture that and they can still participate,” says Johnson.

“There are no hard requirements on them, they have no penalties if they don’t respond.”

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