The nuclear plant powering debate over storage

Artist's view of the Hinkley Point C nuclear plant. Image: EDF Energy.

Artist’s view of the Hinkley Point C nuclear plant. Image: EDF Energy.

By Jason Deign

A surprise U-turn over a UK nuclear power plant has ignited debate over whether renewables, backed by storage, might not be a better alternative.

Last month the UK’s new, post-Brexit administration raised eyebrows after announcing a further review of Hinkley Point C, a controversial nuclear power plant that was supposed to have been given the final go-ahead on July 29.

UK officials rushed to issue assurances after the postponement threatened to spark tensions with China and France, the international partners in the GBP£18bn project.

“The UK needs a reliable and secure energy supply and the government believes that nuclear energy is an important part of the mix,” soothed Greg Clark, business, energy and industrial strategy secretary, in press reports.

The government said it would now make its final decision “in early autumn,” he said.

A backtrack on the nuclear commitment?

It is unclear whether the setback is an indication that the UK government, now led by Theresa May, intends to backtrack on the nuclear commitment made by the previous administration.

Although May is said to be less enthusiastic about the project than her predecessor and French partner EDF Energy has wobbled over the benefits of moving forward with the plant, a final ‘no’ could sour trade relations with China.

It would also nix prospects for the creation of 25,000 jobs and £100m a year for the regional economy of South West England, which lags significantly behind that of the UK.

However, the delay in moving forward with the plans has heightened debate over the cost of the project… and whether renewables with storage might not be a better option in the long term.

Hinkley Point C was originally set to benefit from a contract for difference guaranteeing £92.50 per MWh of energy produced.

Wind and solar to be cheaper

But the UK government itself expects wind and solar power to be cheaper than this by the time the plant is built, coming in at around £50 to £75 per MWh.

Meanwhile Bloomberg New Energy Finance has calculated that “Britain could scrap the … nuclear power plant at Hinkley Point and get the same amount of electricity from offshore wind turbines for roughly the same investment.”

The analyst firm’s calculations predict the nuclear reactor’s price tag could buy 5.7GW of offshore wind, almost twice the generating capacity of Hinkley Point C, which would provide roughly the same output a year.

Getting the same output from onshore wind, a more mature renewable technology, would be much cheaper.

Bloomberg said: “The … assessment includes only the capital cost of erecting various forms of generation, not operating expenses or the price of fuel.

Sidestepping the question of storage

“It also sidesteps the question of what would have to be invested to create storage at a giant scale capable of smoothing out power delivered from renewables when the sun isn’t shining and the wind isn’t blowing.”

But an opinion piece in influential business daily The Telegraph this month pooh-poohed the idea that storage costs might be a barrier to renewables integration on the UK grid.

“Research into cheap and clean forms of electricity storage is moving so fast that we may never again need to build 20th Century power plants in this country, let alone a nuclear white elephant such as Hinkley Point,” it said.

Other observers have expressed similar views.

Writing in Energy Post, University of Exeter MSc Energy Policy course director Bridget Woodman said the Hinkley Point C decision delay was an opportunity to re-think UK energy policy.

Measures to encourage renewable systems

“Now is the time to start considering … measures to encourage more flexible, smaller-scale, renewable systems incorporating demand-side measures and new technologies such as storage,” she said.

The debate has profound implications for the future of energy storage in the UK and elsewhere.

While Hinkley Point C has attracted significant criticism because of its potential cost to the public, energy storage has never benefited from subsidies in the UK and support for renewables generally is rapidly being phased out.

If it can be shown that renewables and storage can deliver large-scale, base-load generation at a cost that beats nuclear, then there could be serious doubts about whether new reactors will ever be built.

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Azores project key for island microgrid credibility

Gorona del Viento: poor performance means other island microgrids are under scrutiny. Photo:

Gorona del Viento: poor performance means other island storage projects are under scrutiny. Photo:

By Jason Deign

A project on Graciosa, Azores, has become key for the credibility of island-based storage following concerns over another plant more than 1,500km away.

The Younicos project on Graciosa is set to go live within weeks amid speculation that another attempt to power an island off renewables, in El Hierro, Canary Islands, has failed to meet expectations.

El Hierro’s Gorona del Viento plant, which combines an 11.5MW wind farm with a pumped hydro storage system, was launched with much fanfare in 2014. Its initial aim was to replace 80% of diesel generation needed for the island grid.

Last month, the plant operator revealed the EUR€82m Gorona del Viento had allowed El Hierro to run continuously off nothing but renewable energy for 55 hours.

And last week Gorona del Viento said the plant supplied 67% of the island’s power throughout July and had set a new record of 76 hours with 100% renewable production.

Covering between 70% and 80% of demand

“The hydroelectric plant is a system that can cover between 70% and 80% of El Hierro’s annual electricity demand,” said Gorona del Viento’s CEO, Juan Pedro Sánchez, in a press note.

Some observers dispute this claim, however. Two years ago, engineers linked to the project warned it would never be able to cover more than 55% of island electricity demand.

And Hubert Flocard, named as an ex-director at the Nuclear Physics Institute of the French National Scientific Research Centre (Centre National de la Recherche Scientifique), recently called the project “a technical semi-failure.”

Based on data from last year, he said: “The renewable fraction for the three most favourable months, July to September, has been 42%. For the half year, the figure is even more disappointing, with only 30% renewables.”

The figures meant Gorona del Viento’s energy production was costing several times more than the diesel it replaced, he said.

Limited wind resource

As well as “limited wind resource, which according to data could not have allowed a renewable fraction larger than 50%,” Flocard said the plant’s government contract could stop it from optimising environmental performance.

Overall, Flocard predicted Gorona del Viento would only be able to cover 46% of El Hierro’s electricity demand.

The respected blog Energy Matters, which Flocard is a collaborator on, has echoed this research with regular updates on Gorona del Viento and an ongoing analysis of data from network operator Red Eléctrica de España.

In July, Energy Matters contributor Roger Andrews called Gorona del Viento a “failed project” after reviewing the first full year’s worth of operational data on the plant.

The whole project was based around a volcanic crater “which it was believed would provide enough energy storage when filled with water and linked to a lower reservoir to smooth out fluctuations in wind generation,” he said.

“No one bothered to do the sums”

“Unfortunately no one bothered to do the sums and check the wind records,” he surmised.

“Had they done so they would have found that the storage was adequate to fill El Hierro’s demand for only about two windless days and that low-wind periods on El Hierro can last for months.”

Gorona del Viento is not known to have responded to the research carried out by Flocard or Energy Matters. Nor did the company respond to a request for further information from Energy Storage Report.

However, for Rogers, who has also questioned the economics of the Eigg island microgrid project in Scotland, the results of the Gorona del Viento project are a damning indictment of renewable energy’s potential overall.

“Intermittent renewable energy is not going to replace dispatchable fossil fuel generation without adequate energy storage backup,” he said.

A prohibitive amount of energy storage

“And since the amount of energy storage needed is almost always prohibitive it follows that an energy future based entirely on intermittent renewables is not a realistic prospect.”

It is against this backdrop that the island of Graciosa in the Azores is preparing to launch another project that aims to replace diesel generation with intermittent renewable energy.

The Graciosa hybrid power system, for island utility Electricidade dos Açores, will feature a 4.5MW wind park and 1MW solar plant connected to a 2.6MW lithium-ion battery system equipped with Leclanché cells.

Project developer Younicos claims: “Diesel generators will only be needed for back-up in weeks with very poor weather conditions.

“This means we can cover an annual average of up to 65% of the island’s power demand with renewables.”

More of a success than El Hierro

Younicos is confident Graciosa will be more of a success than El Hierro because of the choice of storage medium.

The company told Energy Storage Report it believes battery-based systems are the most easily deployable, cost effective option for producing clean power today.

Younicos spokesman Philip Hiersemenzel said: “We already proved that we can keep a grid stable using up to 100% intermittent renewables for hours and indeed days in our technology centre in Berlin.

“As soon as Graciosa becomes operational in autumn, we’ll be proving it every day in real life. Our main challenge with Graciosa was financing. We knew the technology would work 10 years ago and we proved it three years ago.

“Today I’m confident we could build similar systems anywhere in the world in under 12 months, provided that the financing is there.”

A payback of under 15 years

At €24m, the Graciosa project is just over a third of the cost of Gorona del Viento, giving it a potential payback period of under 15 years, according to Younicos.

It is also aiming to serve a smaller level of demand than the project on El Hierro.

Graciosa’s 4,500 inhabitants use about 13.5GWh a year, compared to the 46GWh or so of consumption on El Hierro, which has a population of more than 10,000. This lower bar may help Graciosa in achieving its targets.

But it can hardly afford to miss them, either. With island microgrids now under scrutiny, it is key for the Graciosa project to achieve the level of renewable energy coverage its backers claim… and at a cost that beats diesel.

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Brexit fallout: higher UK energy storage costs

The UK's departure from the European Union is making storage more expensive.

The UK’s departure from the European Union is making storage more expensive.

By Jason Deign

One immediate result of the UK’s decision to leave the European Union is likely to be higher energy storage costs, Energy Storage Report has learned.

The June 23 vote to split with the Union, led by England and Wales, sent sterling tumbling against the dollar. Each pound was worth USD$1.48 on the day of the referendum, versus $1.31 yesterday, an almost 12% drop.

Sterling has also fallen almost 9% against the euro, from €1.30 on June 23 to €1.19 yesterday. This means the cost of importing storage technologies has likely risen by around 10% in the last month.

Nor is it clear whether sterling’s malaise is likely to improve over time.

Joseph Wright of Pound Sterling Forecast this week said: “Moving forward I’m expecting the financial data to continue to disappoint on release, mostly due to the uncertainty created by the Brexit.

Pressure on the pound as the year goes on

“This is likely to apply pressure on the pound as the year goes on.”

Other analysts are similarly downbeat, particularly as UK officials struggle to contain concerns over the British economy.

Bloomberg yesterday reported: “The pound dropped versus most of its 16 major peers after Bank of England policy maker Martin Weale said he’s begun to favour immediate stimulus for the UK economy.”

Elsewhere, The Independent said payouts from a European development fund had been suspended in the wake of the referendum.

The most obvious problem that exchange rate unrest will create for UK energy storage is for companies bidding for National Grid’s 200MW of Enhanced Frequency Response contracts.

Enough time to consider a weakened pound

The closing date for tender responses was on July 15 and it is not clear if that deadline, a mere 16 working days after the referendum, will have given vendors time to fully incorporate the impact of a weakened pound into their costs.

Having to pay significantly more for imported technology could represent a heavy burden for vendors already struggling to pay back the capital cost of projects within the four-year initial contract period stipulated by National Grid.

The companies and technologies selected in the bidding will likely not be revealed until National Grid publishes the results on August 26.

However, it is known the tender was heavily oversubscribed, with more than 70 suppliers offering a combined capacity of more than 7GW.

National Grid has not stated how much it is prepared to pay for the frequency response services in the tender.

Current costs for ancillary services

As a guide, though, it has published current costs for ancillary services, which average GBP£11 per MWh and in some cases go up to £20 per MWh, and has indicated it could be willing to pay up to twice that amount.

It is not obvious whether currency exchange uncertainties could tip the balance in favour of native UK energy storage manufacturers, which in any case are few and far between.

UK-based RES is known to have been pondering a bid within the tender and has already supplied storage systems for National Grid. Its battery systems will likely be sourced from abroad, though.

Among other UK-based firms, Cumulus Energy Storage is commercialising copper-zinc battery systems for grid-level storage but is not known to be participating in the National Grid tender… or to have UK manufacturing.

Highview Power Storage, meanwhile, has a novel liquid air energy storage design although this is currently at pre-commercial stage and unlikely to be suitable for National Grid’s frequency response requirements.

Not good for National Grid’s needs

And the UK tech firm Dyson has a foot in energy storage thanks to its acquisition of Sakti3 but, again, the technology is early-stage and not likely to be a good fit for National Grid’s needs.

As a result, it looks unlikely bidders in the National Grid tender will be able to avoid the consequences of sterling’s devaluation against other major currencies.

Nevertheless, Felicity Jones, a partner with Everoze Partners, an energy consultancy based in the UK and France, said the Brexit impact is unlikely to be a show-stopper for the National Grid tender because prices are so competitive.

“The very tangible impact on battery projects is that the cost goes up, since a weak pound makes it more expensive to buy batteries from abroad,” she said.

For the National Grid tender, she said: “Prices will be low, but they could possibly have been lower.

“Weak sterling will increase the bid price, except for players that are big enough or had enough foresight to hedge that currency risk beforehand.”

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Why analogue utility rates in a digital world?

Doug Staker of Demand Energy.

Doug Staker of Demand Energy.

By Doug Staker, Demand Energy

They say anything can happen in a New York minute. Could one of these minutes change the way we look at demand management, though? After all, from an energy standpoint, not all New York minutes are the same.

Depending on the time of day, electricity in New York can vary significantly in price.

It’s hardly surprising: at certain times, Consolidated Edison (Con Ed), the utility serving New York City, has massive energy needs, peaking at around 13GW. That’s nearly a third of typical peak demand in the entire state of California.

At the same time, base-load production capacity is threatened by the possible closure of the Indian Point Energy Center nuclear plant.

New York Governor Andrew Cuomo’s laudable aim is to replace nuclear fission at Indian Point with nuclear fusion… from the sun. Cuomo is putting USD$1bn into installing 3GW of solar power across New York State by 2022.

A great source of energy

Solar is good for jobs, the environment, and, thanks to cheap panels, the economy. But while it’s a great source of energy, it’s not a consistent source of power.

Grid operators need to make sure the speed at which the grid delivers energy matches the demand in any given minute. Demand fluctuates from a low at 4am to a peak typically in the late afternoon or early evening.

But in some parts of New York City, the peak may occur between 7pm and 11pm. It costs more to serve customers at these times, and, conversely, large system cost savings are possible if peak demand can be reduced.

So utilities look to reduce peaks by imposing demand charges, which are essentially like a speeding ticket.

A commercial user is charged a monthly ‘mileage’ fee for energy usage (in kilowatt hours), with a kind of ‘speeding ticket’ added based on the fastest rate that they use energy (in kilowatts).

Needing to address local conditions

These speeding tickets don’t really address local conditions, though. Con Ed has a system-wide peak that occurs between 2pm and 6pm.

But if you look across the utility’s more than 50 networks, different areas peak at different times. Downtown peaks between 11am and 3pm, midtown peaks from 2pm to 6pm and many residential areas from 7pm to 11pm.

These differences are not factored into demand charges or even New York City’s Demand Management Program (DMP), which gives customers an incentive to provide bulk load reductions during the system peak of 2pm to 6pm.

Participating in the DMP may benefit the Con Ed network overall, but it doesn’t encourage customers to reduce their demand outside of the afternoon system peak.

And it doesn’t provide for targeted reductions if the area load peaks at a different time, as it does in the Brooklyn/Queens residential neighbourhoods.

An analogue, one-size fits all approach

Hence, while the DMP is effective in some regards, it remains an analogue, one-size-fits-all approach in a digital world.

As we build a smarter grid that can leverage high-speed communications, distributed generation, and intelligent energy storage, we can do more to align demand with supply.

New York’s commercial customers can already take advantage of day-ahead hourly pricing for their energy supply. Why not do something similar with demand charges?

Demand charges based upon hourly costs would do a better job of aligning load reductions with system value. While some believe ‘real-time pricing’ to be overly complex, it has been the model for electricity supply for years.

A move to more granular demand charges would help deal with solar resources peaking between 10am and 2pm. Very few grids have peaks that occur midday; most peak in the afternoon and evening.

The cost of supplying power during peak hours

The cost of supplying power during the peak hours is not only more expensive than off-peak, it’s also when line losses are the highest.

By using a battery system to absorb solar production during the morning and time shifting that capacity to when it can offset expensive peaking power, users can create tremendous value.

And policymakers can drive more solar installations by commercial customers that currently cannot take advantage of demand charge reductions due to solar power’s inability to create firm power.

A final issue is grid resilience. Reducing system demand by a few hundred kilowatts may not be a big deal at midday when the sun is shining and all of New York’s solar panels are working flat out.

But those same kilowatts could be really valuable if the grid is close to capacity. This benefit isn’t factored into the DMP.

Much greater grid benefits and customer value

Today’s technology can use market signals to provide much greater grid benefits and customer value.

Given enough information about the market, intelligently managed storage systems can be charged and later dispatch energy to suit almost any set of circumstances, efficiently and automatically.

That would enable them to react instantly to local grid conditions and keep loads within reasonable limits on an hour-by-hour or even minute-by-minute basis.

All that is needed is for the system to know the value of each kilowatt at a given location and point in time. Admittedly, getting that level of information is challenging, but today’s technology is more than up to the task.

Distribution utilities tend to think that their system costs are fixed. They have to build to meet the peak capacity. When a system is forecast to become overloaded, they have to develop programs like DMP to reduce loads at peak.

Or they have to build new infrastructure, even though in New York City the uppermost 2GW of peaking demand occurs for a mere 156 hours (or about 0.018% of) a year. It’s clearly not a very efficient model.

A managed storage inventory

By adding storage, New York can have a managed inventory capable of moving energy around and helping to build a more efficient delivery system.

Developing innovative rates that will align price with variable costs means commercial customers can be encouraged to deliver load reduction or self-generated power during peak periods.

If these innovative rates were to be voluntary, limited to weekdays between 8am and 11pm, and commercial users received savings beyond the current demand charge methodology, then it could be a big incentive to install storage.

Such a move would let New York City produce and use a much greater level of renewable energy without stressing the grid.

This is not just a New York problem. Grids around the world are facing the same challenge, making the evolution of New York’s demand charge structure an area of global interest.

As another New York saying goes: “If you can make it here, you can make it anywhere.”

AMS to start series B fund hunt this month

Advanced Microgrid Solutions is on the hunt for new investors after growing its business using batteries supplied by Tesla. Pic: Tesla Motors.

Advanced Microgrid Solutions is on the hunt for new investors after growing its business using batteries supplied by Tesla. Pic: Tesla Motors.

By Jason Deign

Advanced Microgrid Solutions (AMS) of San Francisco, USA, is readying for a new fundraising round that could kick off as early as this month.

The much-hyped project developer is looking to bring in more than the USD$18m it achieved in its last financing effort, which closed just under a year ago.

“We are about to launch our series B and that will be concluded this year,” chief commercial officer Katherine Ryzhaya told Energy Storage Report.

The money will be used to speed up the growth of the company, which currently has 2.5MWh of storage in operation and aims to have installed more than 5MW and 3.5MWh by the end of this year, according to Ryzhaya.

“With the series B we will only be scratching the surface of the opportunity within the US,” she said. “We also have customers with a focus on the UK and Japan.”

A well-connected executive team

A well-connected executive team has helped AMS garner considerable success since it appeared on the energy storage scene in November 2014 with a contract for 50MW of projects for Southern California Edison (SCE).

The deal, surprising for a firm with no track record, was likely influenced by the fact that co-founder Jackalyne Pfannenstiel was a former chair of the California Energy Commission and the first woman officer at Pacific Gas and Electric.

Meanwhile CEO Susan Kennedy’s former role as chief of staff to California Governor Arnold Schwarzenegger almost certainly helped in getting the actor-turned-politician on board as an investor in series A funding last year.

The financing was led by venture capital firm DBL Partners, whose managing partner, Nancy Pfund, joined the AMS board of directors in May 2015.

Pfund was an early investor and ‘board observer’ at Tesla Motors for four years up until the company’s stock exchange launch in 2010.

Tesla Powerpack batteries for projects

Unsurprisingly, AMS has chosen Tesla Powerpack batteries for its projects, although Ryzhaya insisted there were good reasons for this.

“When we won our contract with SCE we held an RFP [request for proposals] for technology and Tesla came out head and shoulders above, not only on price but also technology,” she said.

The fact that the brand is well known is another potential bonus, she noted. “Customers are interested in having Tesla on site.”

AMS has an agreement to purchase up to 500MWh of battery storage from Tesla.

Part of this was due to go towards the deal with SCE, although Energy Storage Report understands deployment may have been delayed by the bankruptcy of AMS’s funding and delivery partner, the ill-fated solar company SunEdison.

Storage installations will still go ahead

In any case, said Ryzhaya, the storage installations will still go ahead. “The 50MW is our SCE contract,” she said. “We’re now working with private finance. We’re not affected by [SunEdison].”

One of the projects originally announced in conjunction with SunEdison was a deal to install up to 10MW of reserve capacity spread across 24 office buildings owned by the Irvine Company, a California real estate firm.

It is not known how many of these installations have been completed, but since then AMS has announced a number of other projects.

Last month, for example, the company trumpeted “the largest advanced storage project at an educational institution in the nation,” in the form of a 1MW, 6MWh installation at the Long Beach campus of California State University (CSU).

The project was due to be followed by similar-sized installations at the CSU’s Office of the Chancellor and Dominguez Hills campus.

Standardised contract and offering

“Additional CSU campuses will be able to enrol in the advanced energy storage project through a standardised contract and offering,” AMS said.

Just four days after the CSU announcement, AMS said it would be installing a 500kW, 1MWh Tesla Powerpack-based storage system at One Maritime Plaza, a San Francisco skyscraper owned by Morgan Stanley Real Estate.

The project is expected to be completed by January 2018 and should cut the building’s peak energy demand by up to 20%, said AMS.

All these installations are for what AMS calls ‘hybrid electric buildings’, which essentially seems to be in-house jargon for commercial and industrial-scale storage with a high level of automation.

In hybrid electric buildings, said Ryzhaya, batteries are charged overnight when energy is up to 20% cheaper and less carbon-intensive.

Without interruption to building power supplies

Software then allows aggregated battery systems to be discharged by the local utility whenever it needs to shave peak loads, without any interruption to building power supplies.

Building owners benefit from lower electricity bills, because when peaks are highest they are feeding energy into the grid rather than consuming it, and also get paid a rental fee by AMS for providing space for the batteries.

AMS, meanwhile, gets money from the utility for providing demand response services and also bills each building owner a service charge, although Ryzhaya said owners always had a net gain from the deal.

“The building owner is always making money,” she said. “We have a financial performance guarantee so even if the equipment does not work they still get a cheque in the post.”

AMS believes the model is unique and has even registered the phrase ‘hybrid electric buildings’.

However, it sounds a lot like the approach being taken by a number of other behind-the-meter energy storage players, including Demand Energy and Stem.

If that’s the case, then it’s no wonder AMS is on the lookout for cash; it needs to get to investors before its competitors eat its lunch.

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Demand Energy announces project milestone

Demand Energy's DEN.OS software platform is helping New York buildings to benefit from the state's demand management programme. Pic: Demand Energy.

Demand Energy’s DEN.OS software platform is helping New York buildings to benefit from the state’s demand management programme. Pic: Demand Energy.


By Jason Deign

Demand Energy last week announced completion of the first five energy storage projects in New York’s Demand Management Program (DMP).

One of the five 100kW, 400kWh behind-the-meter energy storage systems installed in five separate Glenwood properties across Manhattan has already passed measurement and verification (M&V) testing.

M&V certification is currently underway with the other four projects within the DMP, which is managed by utility Consolidated Edison (Con Ed) along with the New York State Energy Research and Development Authority (NYSERDA).

The aggregated behind-the-meter systems, with batteries from EnerSys, are powered by storage system developer Demand Energy’s Distributed Energy Network Optimization System (DEN.OS).

“We have been working during the off-peak season to install and interconnect the next four systems which make up the first 2MWh of installations for Glenwood,” said Shane Johnson, vice president of client services.

Operating storage systems for four years

“We have been operating distributed energy storage systems for Glenwood over the last four years.”

Demand Energy’s software platform, DEN.OS, “can aggregate a mixture of distributed renewable energy systems to respond to Con Ed’s localised peak problems and allow Glenwood to respond to a variety of load conditions and the demanding requirements of the New York energy market,” he said.

To qualify for the DMP incentive program, Demand Energy had to demonstrate that its first battery energy storage system could deliver four hours of continuous output, from 2pm to 6pm, for a period of four weeks.

Demand Energy’s storage system cut loads at Glenwood’s Paramount Tower by 100kW continuously during the period covered during tests validated by NYSERDA’s independent contractor, Energy Resource Consulting.

Upon completion of this phase, the Paramount Tower system was moved into operation immediately to take advantage of the DMP operational season, which lasts from the beginning of summer until September 30.

Delivering demand charge reduction

Beyond this time, Glenwood is free to switch operating modes and move into delivering demand charge reduction and other load management operations during the off-peak season.

“At Glenwood we have always believed that we need to do our part and support load reduction on the grid during the critical summer power season,” said Josh London, vice president of management for Glenwood, in a press release.

“With the flexibility of Demand Energy’s system, we can participate in the summer DMP program and then use the energy storage system to reduce our demand charges during the off season.”

This “provides added stability to the local operating grid by flattening our building’s load,” he commented.

The remaining four systems started measurement and verification testing at the beginning of this month. The tests will be completed next week. Demand Energy is due to install another five systems for Glenwood over the summer.

Energy storage enrolled in the DMP

When completed, Glenwood, one of New York City’s largest owners and builders of luxury rental apartments, will have 1MW and 4MWh of aggregated behind-the-meter energy storage enrolled in the DMP.

The New York DMP was designed to deploy verifiable load reduction during the summer load season.

In particular, it aims to help reduce stress on the distribution grid within New York City for four hours during the weekday peak hours between 2pm and 6pm.

The New York energy grid can be strained during peak hours to a level of stress that can cause system disruption in the five boroughs of New York City.

All electric grids need to match load with supply in order to maintain stability, and the New York City region experiences peak loads that can vary by 2GW for a short duration of time during the summer air conditioning season.

The impact of Hurricane Sandy

Grid resilience is a big deal for the state following the impact of Hurricane Sandy in 2012.

Since then New York has been free of extreme weather but global warming has observers on tenterhooks ahead of a possible grid-stressing event this summer.

“We are fully behind the efforts being made by Con Ed and NYSERDA to improve the resilience of New York’s grid in the face of extreme weather conditions and load growth that could stress the grid,” said London.

“We see the DMP as a significant step in averting grid incidents in the event of a heat wave, which fortunately has not hit the city in the last two years but could well arise this summer.”