When the PJM Interconnection* proposed that energy storage needed 10 hours duration to qualify for capacity payments, that seemed to make no sense.

No other grid operator had proposed such a requirement—essentially disqualifying battery storage—in its plan for complying with an order from the Federal Energy Regulatory Commission to allow energy storage to participate in all markets where it is technically capable of doing so (including capacity markets).

Now we have an analysis that debunks PJM’s proposal.

Storage with 4-hour duration can provide up to 4,000 MW of capacity of “equivalent reliability value” to that supplied by conventional power plants in PJM, according to a study by Astrapé Consulting.

Astrapé used the SERVM model for its analysis, a model it has used for similar evaluations it has performed for other regional grid systems such as ERCOT, MISO, and SPP.

Astrapé’s report concluded:

A 4-hour duration requirement would correctly represent the capacity value of storage under current market conditions and would remain accurate until the amount of installed storage in PJM increases by two orders of magnitude.”

The “two orders of magnitude” refers to the 40 MW of 4-hour non-hydro storage that Astrapé determined is currently operating in the PJM region, compared to the 4,000 MW potential.

The capacity payments at issue are intended to ensure that adequate reserve capacity is available to meet demand at occasional times of extreme demand, such as extremely hot or cold days.

But when storage is excluded from the capacity market, that causes the market-clearing price for capacity to be higher, increasing customers’ electric bills. Meanwhile, lower compensation for storage can limit otherwise cost-effective deployments of solar and wind power, which pair well with storage.

In its analysis, Astrapé followed an elegant approach illustrated in Figure 1. In step 1 as shown, Astrapé modeled the addition of conventional capacity to reduce the “loss of load expectation” (LOLE) to 0.1, a “generally accepted reliability criterion” that “represents a single day of firm load shed in a 10-year period.” In step 2, Astrapé modeled the addition of energy storage, reducing LOLE below 0.1. In step 3, Astrapé modeled the removal of conventional capacity until LOLE was again 0.1. This yielded a ratio of storage capacity added to conventional capacity removed.

Georgia Power is set to boost its state’s battery energy storage sector, with the company’s plan to own and operate 80MW of battery energy storage now approved by the Georgia Public Service Commission (PSC).

Georgia Power’s 2019 Integrated Resource Plan (IRP) has been approved by the Georgia Public Service Commission (PSC), in a unanimous decision. The plan includes energy storage, 72% more renewable generation by 2024, and approval of the company’s environmental compliance strategy.

Allen Reaves, Georgia Power’s senior vice president and senior production officer, said: “Working with the Georgia PSC, we are positioning Georgia as a leader in the Southeast in battery energy storage, which is critical to growing and maximizing the value of renewable energy for customers as we increase our renewable generation by 72% by 2024.

“Through the IRP process, Georgia Power will continue to invest in a diverse energy portfolio including the development of renewable resources in a way that benefits all customers to deliver clean, safe, reliable energy at rates that are well below the national average.”

Under the approved IRP, Georgia Power will both own and operate the 80MW of new battery energy storage, add 2,260MW of new renewable generation to the company’s energy mix and retire five coal-fired units across the state.

New energy efficiency programs for customers, including both an income-qualified program and aniIncome-qualified energy efficiency pilot program, were also approved in this plan.

Georgia Power filed requests with the PSC to both raise residential rates and seek approval for its IRP earlier this month, while elsewhere in the US, utilities in New Mexico and Tennessee have also filed major new plans that include significant mention of energy storage.

Gas peaker plants may be among the first casualties of a new Minnesota law requiring utilities to include energy storage as part of their long-range plans.

The provision, part of an omnibus jobs and energy bill, “puts energy storage on a level playing field with natural gas plants and other resources,” said Ellen Anderson, executive director of the University of Minnesota’s Energy Transition Lab. “Utilities will have to acknowledge the capabilities storage can provide as an alternative to, say, a fossil fuel plant.”

The most likely victim could be peaker plants, which operate when utilities face high demand for short durations, such as hot summer days, she said.

A 2017 study commissioned by the Energy Transition Lab found that peaker plants are a “marginal resource for meeting capacity needs” and that storage, and solar-plus-storage, are “becoming increasingly cost competitive.” By 2023, the report predicts, the cost of storage becomes less than building new peaker plants.

Minnesota’s investor-owned utilities are in different phases of presenting their integrated resource plans before the state Public Utilities Commission. The first utility to unveil an integrated resource plan since the law passed is Xcel Energy, which included energy storage in its forecasts.

The major aspects of Xcel’s plan call for retiring all its remaining coal plants within the next decade, operating the Monticello nuclear plant until 2040, and adding 4,000 megawatts of solar and 1,200 megawatts of wind. The plan calls for the acquisition of one combined cycle natural gas plant and the construction of another, along with an aggressive energy efficiency program.

Xcel goals call for reducing carbon by 80% by 2030 and for producing no carbon through energy production by 2050.

Released July 1, the plan anticipates that energy storage in the 2030s will provide more dispatchable power and play a greater role supporting reliability. Price declines and technology advances between now and then will make utility-scale storage “an integral resource used to meet this need,” the report said.

At the same time, the report warns that energy storage has limitations in a system with much greater variability due to renewable generation. The answer to the problem of intermittency in renewable energy will not be energy storage.

“The current state of battery storage technology does not have the ability to match the duration of such events without significant (and very expensive) over-build of those resources,” the report states in an executive summary.

Colorado-based start-ups Simple Energy and Tendril have merged to create Uplight, a one-stop shop software platform for utilities’ customer-facing software needs, with ESS industry player AES Corporation taking a stake in the new company as a “strategic partner”.

The merger with Simple Energy is the latest in a rapid period of growth for Tendril, precipitated by securing a majority investment from American private equity firm Rubicon Technology Partners in December 2018. The home energy management start-up has since acquired FirstFuel Software, Energy Savvy and EEme.

The new company claims to be the first to unite all key solutions for delivery, management and optimisation of the customer energy experience, by bringing together leaders in utility-branded marketplaces, demand-side management, analytics and utility customer experience personalisation.

Uplight already provides software to more than 75 utility clients across 40 states, according to a company statement.

Rubicon Technology Partners will be the majority stakeholder in the combined company, while AES Corporation also has a significant stake; the Fortune 500 company was Simple Energy’s largest shareholder and made a US$53 million strategic investment in the new company as part of the merger.

The energy storage technology provider and system integrator emailed Energy-Storage.news with a statement that it has already used Uplight’s platforms in demand response and energy efficiency programmes and that “the AES teams that develop community solar and energy storage solutions will be working with Uplight to enhance their solution offerings around those technologies”.

Adrian Tuck, formerly CEO of Tendril, will be CEO at Uplight.

Also this week, British software company Smarter Grid Solutions (SGS) has also been finetuning its offering. It unveiled the advanced version of its popular distributed energy resource management system (DERMS) software ANM Strata on June 12. Equipped with advanced tools for data analytics, visualisation and application programming interfaces (APIs), ANM Strata 2.0 has the ability to connect to other software systems at utilities and the operators of distributed energy resources (DERs).

Energy-Storage.news received information last week on a handful of successful battery installations at commercial customer sites, from NantEnergy in the US and from Alfen in Europe.

The Netherlands-headquartered system integrator and technology provider Alfen has supplied a 2.5MWh battery energy storage system to the headquarters of Smappee, the energy management technology company which recently struck a deal to roll out its EV smart charging solutions globally.

Smappee, which claims to have already deployed over 70,000 EV charge units, is building a cleantech hub at its headquarters in Harelbeke, Belgium, dubbed ‘Snowball’. It includes an energy laboratory, housing a cleantech accelerator programme and flexible office space for cleantech companies including startups. The offices and facilities will be powered by a combination of different renewable and energy-efficient solutions.

Alfen’s energy storage system will enable Snowball to effectively self-consume solar energy generated onsite and to balance the load – including electric vehicle charging and grid-balancing services. At a future date, off-grid or islanding capabilities could be added, Smappee CEO Stefan Grosjean said. Alfen also created a new 5MVA grid connection at the Smappee site to connect with the local distribution grid, as well as delivering complete, integrated storage solution.

Energy costs savings, backup capabilities drive value for US customers
From the US meanwhile, NantEnergy, which towards the end of 2018 acquired the energy systems and services business of Japanese technology provider Sharp, has touted a recent track record of successfully executed projects for C&I customers in the US states of California and New Mexico.

Sharp’s SmartStorage platform, which NantEnergy acquired, has been used in a few high profile commercial projects in the US, with Jigar Shah’s Generate Capital among the developers and financiers to use them to deliver energy costs savings – and sometimes backup power – to customers.

BILLINGS — Construction on a $1 billion energy storage system in central Montana could start as soon as next year after its sponsors said Friday they reached a financing agreement with a Danish firm that invests in renewable energy.

Carl Borgquist, president of Bozeman-based Absaroka Energy, said the involvement of Copenhagen Infrastructure Partners of Denmark marks a significant step forward for the 400-megawatt project near Martinsdale.

Next up, he said, is to make arrangements with utilities or others interested in using the Montana facility to complement their own electricity generation.

“That’s our last step before we’re able to go under construction and start putting concrete and steel in the ground,” Borgquist said.

The Gordon Butte Pumped Storage Hydro Project was first proposed in 2010 and is intended to make wind turbines and other renewable energy sources more reliable , by storing the electricity they produce until it’s needed.

Described as a “hydro battery,” it would use excess power produced by wind farms or other sources to pump water from a reservoir uphill to a second reservoir. The water would be released during periods of high electricity demand, turning hydropower turbines to generate power.

Many utilities use power plants fueled by natural gas to fulfill a similar role. They’re needed to balance electricity across the power grid as demand rises and falls over time.

A spokeswoman for Copenhagen Infrastructure Partners confirmed the firm’s involvement in the project. Senior Partner Christian Skakkebaek said in a statement that pumped storage hydro “will be a key resource as the global transition to renewable energy continues to accelerate in states such as Montana.”

Construction could take up to four years and require 300 to 400 workers, Borgquist said. Once the project is operational, it will have a permanent workforce of two- or three-dozen employees, he said.

The Federal Energy Regulatory Commission issued a license for the facility in 2016.

There are more than 20 gigawatts of pumped storage capacity across the U.S., according to the National Hydropower Association. An additional 31 gigawatts of capacity have been proposed, primarily in Western states, according to the association.

Battery storage projects are taking off in the US, with a substantial leap expected in the coming years, as the country could triple its utility-scale battery storage power operating capacity by 2023.

According to an update from the US Energy Information Administration, 1623 MW of new utility-scale battery storage capacity is set to come online by 2023, up from a current total of 899 MW. Total capacity is expected to be around 2.5 GW of utility-scale battery storage by that year, nearly tripling the current capacity.

Considering other battery projects that may be currently unreported, or projects that may still be introduced and come online during that timeframe, it’s easy to see how storage could go beyond 3x the current capacity.

Utility-scale battery storage power capacity more than quadrupled from the end of 2014 (214 MW) through March 2019 (899 MW), so a similar rise through 2023 shouldn’t come as a surprise.

Renewable energy and battery costs are both falling — the EIA notes “pairing utility-scale battery storage with intermittent renewable resources, such as wind and solar, has become increasingly competitive compared with traditional generation options” — and the adminstration also points to agreeable state policies and a Federal Energy Regulatory Commission order as major factors in the rise.

The two largest operating utility-scale battery storage sites at the moment both provide 40 MW of power capacity, though a number of much larger projects are set to come online in the next few years, including the Manatee Energy Storage Center in Florida, which should open in 2021.

While the EIA says FPL’s 409 MW/900 MWh Manatee center will be the largest battery in the US — and the world — there’s going to be plenty of competition for that title. For instance, the Gemini Solar Project in Nevada is awaiting approval, and that 531 MW/2125 MWh battery system would top Florida’s effort.

California, Illinois, and Texas alone make up nearly half of the total installed battery storage in the US thus far. The EIA revealed the top ten states in utility-scale storage, and a few others may come as a surprise:

It can be hard to keep up with the steady drumbeat of energy storage policy updates emanating from the Northeast, and New York in particular, but last week’s announcement of $55 million allocated for Long Island deserves a second look.

The specifics of the incentive — $250 per kilowatt-hour for residential storage or commercial systems up to 5 megawatts — parallel similar opportunities offered to customers elsewhere in New York as part of a $280 million package launched in April. The earlier tranche was funded by a systems benefit charge that Long Islanders don’t pay; instead, their storage dollars are coming from the Regional Greenhouse Gas Initiative.

Besides a separate funding structure, Long Island’s geography and grid infrastructure make it a valuable test case for energy storage, as part of Gov. Andrew Cuomo’s ambitious decarbonization program.

“Long Island strikes me as one of the best and earliest locations to reach a completely carbon-free grid, given its solar, storage and offshore wind capabilities,” said Jason Doling, assistant director for distributed energy resources at the New York State Energy Research and Development Agency.

NYSERDA hopes to disburse the storage funds in the next three to five years, with the goal of establishing a local installer base and a sustainable and growing market by the end of that period.

Island limits create storage opportunities
The water separating Long Island from the mainland imposes obvious constraints on delivering electricity to a population that totaled 7.5 million as of the last census. Summer tourism season brings extra stress, regularly forcing the Long Island Power Authority, which owns the grid infrastructure, to truck in portable diesel generators to meet demand.

Storage can defer distribution upgrades, ensuring power supply during peak hours in place of more capital-intensive investments. LIPA tested out this vision when it powered up a 5-megawatt/40-megawatt-hour battery last summer at a substation in East Hampton.

Separately, Cuomo’s administration has developed more stringent nitrogen oxide emissions regulations to target the worst-polluting peaker plants. Plants have until mid-2020 to come into compliance. Emissions reductions are possible by replacing fossil-fueled generators with storage, or adding storage to hybridize the plant.

This month, officials in Los Angeles, California, are expected to approve a deal that would make solar power cheaper than ever while also addressing its chief flaw: It works only when the sun shines. The deal calls for a huge solar farm backed up by one of the world’s largest batteries. It would provide 7% of the city’s electricity beginning in 2023 at a cost of 1.997 cents per kilowatt hour (kWh) for the solar power and 1.3 cents per kWh for the battery. That’s cheaper than any power generated with fossil fuel.

“Goodnight #naturalgas, goodnight #coal, goodnight #nuclear,” Mark Jacobson, an atmospheric scientist at Stanford University in Palo Alto, California, tweeted after news of the deal surfaced late last month. “Because of growing economies of scale, prices for renewables and batteries keep coming down,” adds Jacobson, who has advised countries around the world on how to shift to 100% renewable electricity. As if on cue, last week a major U.S. coal company—West Virginia–based Revelation Energy LLC—filed for bankruptcy, the second in as many weeks.

The new solar plus storage effort will be built in Kern County in California by 8minute Solar Energy. The project is expected to create a 400-megawatt solar array, generating roughly 876,000 megawatt hours (MWh) of electricity annually, enough to power more than 65,000 homes during daylight hours. Its 800-MWh battery will store electricity for after the sun sets, reducing the need for natural gas–fired generators.

Precipitous price declines have already driven a shift toward renewables backed by battery storage. In March, an analysis of more than 7000 global storage projects by Bloomberg New Energy Finance reported that the cost of utility-scale lithium-ion batteries had fallen by 76% since 2012, and by 35% in just the past 18 months, to $187 per MWh. Another market watch firm, Navigant, predicts a further halving by 2030, to a price well below what 8minute has committed to.

Large-scale battery storage generally relies on lithium-ion batteries—scaled-up versions of the devices that power laptops and most electric vehicles. But Jane Long, an engineer and energy policy expert who recently retired from Lawrence Livermore National Laboratory in California, says batteries are only part of the energy storage answer, because they typically provide power for only a few hours. “You also need to manage for long periods of cloudy weather, or winter conditions,” she says.

Local commitments to switch to 100% renewables are also propelling the rush toward grid-scale batteries. By Jacobson’s count, 54 countries and eight U.S. states have required a transition to 100% renewable electricity. In 2010, California passed a mandate that the state’s utilities install electricity storage equivalent to 2% of their peak electricity demand by 2024.

Although the Los Angeles project may seem cheap, the costs of a fully renewable–powered grid would add up. Last month, the energy research firm Wood Mackenzie estimated the cost to decarbonize the U.S. grid alone would be $4.5 trillion, about half of which would go to installing 900 billion watts, or 900 gigawatts (GW), of batteries and other energy storage technologies. (Today, the world’s battery storage capacity is just 5.5 GW.) But as other cities follow the example of Los Angeles, that figure is sure to fall.

While software has been described by many as the single most important aspect of how an energy network integrates, manages and then uses energy storage, two industry heavyweights have said that selling software licensing alone was not a viable business model for them.

Rolling out the controls and management software by itself is a perilous business proposition, according to Karim Wazni, MD of Aggreko Microgrids and Storage (formerly Younicos until it was bought out and became part of rental energy solutions group Aggreko).

Having deployed 220MW of battery storage projects worldwide to date across nearly 50 projects, many of which it worked on as a full system integrator including hardware and software provision, Aggreko M&SS-Younicos had found that the value of the software alone could not be divorced from the overall aims of the project.

“It’s [software is] only valuable if you can package it in a system that delivers benefits that the customer can measure. I think it’s been challenging to prove a profitable business model based on software licensing,” Wazni said.

“So, it’s through the realisation of these benefits in a service model that we actually leverage the value of this software, so we’ve ported, we’ve included the software coming from Younicos and we’ve integrated [it] into our overall power management system, so we can then realise the benefits of the combination of thermal, storage and solar.”

Value is in the integrated offering
Andy Tang of the executive team at Greensmith Energy, also the target of a recent successful takeover bid by Wärtsilä, told Energy-Storage.news that he and his team also did not believe “that in this industry, there’s a strong case for a software-only business model”.