Customers in Long Island, New York, that install commercial energy storage systems of up to 5MW and residential solar-plus-storage will be eligible for incentive payments of US$250 per kWh of storage installed.

That’s while a US$55 million pledge from state Governor Andrew Cuomo lasts, with close to US$15 million of funding to be spent this year and the remainder to be paid out over the next three to five years.

Cuomo said that the incentives for energy storage “will help Long Islanders grow their clean energy economy and create jobs while also improving the resiliency of their grid in the face of more frequent extreme weather events”.

Building out resiliency on Long Island will help the state further its renewable ambitions, with Cuomo having ushered in what was dubbed a ’Green New Deal’ for the state, including 3,000MW of energy storage to be deployed by 2030. Up to US$350 million of direct investment could be made into supporting energy storage deployment and businesses, Energy-Storage.news reported in April.

Even before that, New York was already on the path of its Renewing the Energy Vision (NY REV) programme, examining how to modernise and re-energise with renewable and more energy efficient solutions one of the world’s grandest old grids.

NYSERDA emailed Energy-Storage.news yesterday to announce the latest Long Island funding, with the agency making incentives available through its NYSERDA Retail Energy Storage Incentive Program. The agency’s release highlighted the key role energy storage can play in reducing the impact of peaks on the grid, something traditionally associated as the main strength of inflexible fossil fuel generation. The support for energy storage is being pushed in conjunction with utility Public Service Electric and Gas Long Island (PSEG-LI).

It’s pretty clear that renewable energy is more than price competitive with traditional energy sources such as coal, gas, and nuclear. Want proof? Look at the under 2 cents per kWh 25 year PPA the Los Angeles Department of Water and Power signed recently.

But we all know that the sun doesn’t always shine and the wind doesn’t always blow. To make matters worse, sometimes there is more renewable energy available than there is demand for electricity. To solve both issues, utilities and renewable energy providers are depending more and more on batteries that store excess electricity for later use.

Such time shifting strategies make renew able energy more dispatchable, meaning it is available when demand requires, regardless of whether the sun is out or a breeze is stirring, but they have their limits. Typical battery storage installations today can provide electricity for 2 to 4 hours at most. After that, it’s lights out, quite literally. So where do we go from here?

Community Choice Aggregation

Nick Chaset is the CEO of East Bay Community Energy, a community choice aggregate formed in 2018. Its mission is to buy cleaner power than utility PG&E can supply while keeping prices affordable and promoting well-paying jobs. According to Green Tech Media, CCAs have taken millions of customer accounts from California’s larger investor owned utilities.

Last week, Chaset signed an agreement with the city of Oakland to replace a jet fuel powered peaker plant near San Francisco Bay with a 20 megawatt, 80 megawatt-hour lithium-ion battery system. The question is, what happens in Oakland after the new battery is drained of power at the end of four hours?

Chaset has some thoughts on that question and shared them with Green Tech Media. “Right now, there’s still tremendous opportunity for the 4-hour [-duration] investments, which we’re going to continue to make,” at the contract signing in Oakland. “What you’ll see is, through 2030 probably, it’s storage, 4- and 6-hour batteries, [that] gets you where you need [to be].”

A Wood Mackenzie study of four existing natural gas-powered peaker plants found that a 6-hour battery could have handled 74% of the actual peak operations in 2017. The remaining events lasted too long for batteries to handle.

The upshot is that currently available battery technology can plausibly take over much of the peaker role, GTM says, but not the bulk power function served by larger combined-cycle gas plants. At some point, clean resources will need to supply larger amounts of power on demand for an extended period of time, especially in the evenings as solar generation tapers off.

The transport sector has been quick to embrace electrification with robust adoption of lithium-ion battery storage technology in mobility, and grid infrastructure is following suit. Now, it appears the maritime industry is getting in on the action.

IHS Markit energy storage research and analysis manager Julian Jansen confirms the trend, telling pv magazine “Aggressive carbon reduction goals by governments and industry, as well as the need to reduce fuel consumption and maintenance costs are driving the use of battery technology in marine vessels. Battery technology can be utilized either as part of hybrid systems or to fully electrify ships.”

Such progress was evident at the three-day Electric and Hybrid Marine World Expo, held in Amsterdam last week.

German battery manufacturer Akasol AG, for example, promoted its role in powering the new hybrid superyacht developed by Italian company Cerri Cantieri Navali S.p.A., with its first generation AKASystem 15 OEM battery system used in the vessel.

Battery powered yacht

Akasol said the yacht can travel short distances with an electric cruising peak of 8 knots and can anchor under electric power with the lithium-ion battery system for up to 17 hours. The German company also presented its second generation AKASystem OEM PRC, which it said will offer 33% more energy than its precursor and can achieve 2 C charge rates.

Nidec ASI S.p.A. was also steering toward clean power boating with the launch of new batteries for the sector at the exhibition in the Netherlands. Its new batteries differ from others on the market due to a “single large string” feature the company says will make it possible to reduce the number of modules in each battery pack and the number of converters.

“Marine transport alone produces 13% of greenhouse gas emissions and on current projections emissions are expected to rise by at least 50% by 2050 under a business-as-usual scenario,” said Anil Srivastava, CEO of storage provider Leclanché.

Utility Georgia Power wants to own and operate 80MW of battery energy storage systems in its service area, building on the state’s early recent steps to investigate the value of storage both in front of and behind the electricity meter.

Georgia Power has just made a request to raise residential rates in order to invest in the state’s “energy future” by 7% next year, filed with the Georgia Public Service Commission (PSC). In doing so, the utility said it has already spent or committed “nearly US$18 billion… to strengthen the reliability and resiliency of the state’s electrical system and to comply with federal regulations”.

Environmental compliance plans, air and water quality issues, as well as extensive storm restoration efforts are all drivers for this investment, while the company is like other utilities, trying to create smarter energy plans for its customers, Georgia Power said. Its 2.6 million customers currently pay 16% below the national average for power and residential rates have actually fallen slightly since 2011, the company argued.

“The company will continue to invest in a diverse mix of energy resources, including renewable energy,” the release said, adding that Georgia Power has 1,500MW of renewable resources online and around the same amount again under development (+1600MW).

Georgia Power’s 2019 Integrated Resource Plan (IRP) spells out plans to have more than 4,750MW of renewable energy resources in its portfolio by the end of 2024, if approved by the PSC. According to the utility, battery energy storage systems (BESS) are “critical to maximising the value of renewable energy resources”.

“The company seeks this opportunity to demonstrate the deployment, integration, operation and grid optimisation of storage to gain valuable insight into how to maximise the value of storage for customers,” Georgia Power said, with the PSC expected to vote on the IRP plan on 16 July 2019.

New York state is providing $55 million in funding for energy storage including commercial and residential storage projects on Long Island.

Announcing the funding Wednesday, Gov. Andrew Cuomo said there would be an initial rollout of about $15 million in incentives from the New York State Energy Research and Development Authority.

Energy storage projects supported by this initiative would help to advance the state’s goal of achieving New York’s target of 3,000 megawatts of energy storage by 2030.

“With our nation-leading clean energy goals and aggressive strategy to combat climate change, New York continues to set the example of climate leadership for other states across the country,” Cuomo said in a statement.

“These incentives for energy storage will help Long Islanders grow their clean energy economy and create jobs while also improving the resiliency of the their grid in the face of more frequent extreme weather events,” he added.

The $15 million in incentives is to be immediately available to Long Island residents and businesses for commercial and residential projects through NYSERDA’s Retail Energy Storage Incentive Program. These incentives will support energy storage at customer sites for systems paired with solar or standalone systems.

The rest of the funds will be allocated in three to five years.

The energy storage will help to enhance the efficiency of the electric grid in order to maximize the benefits of renewable energy resources, including wind and solar.

The funding is available for both commercial and residential incentives.

Renewable energy is one of the most attractive investment options for American companies today. Just ask Starbucks, which recently contracted for enough wind and solar power to supply 3,000 of its coffee shops with clean electricity.

American businesses and global investors are increasingly turning to a low-carbon portfolio—a fact reflected in our new survey of the nation’s leading financial institutions, which found high near-term confidence for renewable energy growth over the next three years and a strong appetite for energy storage.

When asked their reasons for this bullish outlook, survey respondents cited the low cost of renewable energy, expanded requirements that states derive a certain portion of their energy from renewable sources, increased demand from corporations, the potential for new carbon legislation, and a desire to benefit from sunsetting tax credits.

Yet while the near-term outlook is strong, the expected rate of growth after 2022 is less certain. In order to stay on track, the renewable sector will need a modernized grid; electricity markets that fairly recognize the value of flexible, pollution-free renewable power; and a level playing field in the tax code.

One year ago, the American Council on Renewable Energy (ACORE) launched its $1T 2030 campaign to promote $1 trillion in U.S. private sector investment in renewable energy and enabling grid technologies by 2030. Today, I’m pleased to report that we have made a credible start and this goal remains within reach.

Despite trade tensions, flat national electricity demand, and a challenging political climate, the private sector invested nearly $57 billion in renewable energy and enabling grid technologies in 2018. The bulk of this capital is flowing to onshore wind and solar projects. However, investment in enabling grid technologies, such as energy storage, is not where it should be, even as we seem to be on the verge of a boom as investors and businesses determine the best ways to value and finance these important additions to our grid.

Utilities in New Mexico and Tennessee have both released plans for new solar, storage and gas infrastructure.

The New Mexico plan is more immediate as it is linked to the closure of the San Juan coal power station in June 2022. The utility PNM has asked the state’s regulator to approve “the securitization of the unrecovered investment in the plant” and backing for replacement infrastructure.

It has suggested 280MW of gas peaker plants, 350MW of solar and 130MW of battery storage.

The plan is the result of PNM’s modelling. Compared to the continuation of operations at San Juan it expects to save customers US$7.11 per month in 2023.

“Each step we take toward 100% emissions-free must balance the cost, the environment, and reliability,” said Pat Vincent-Collawn, chairman, president and CEO, PNM Resources the parent company of utility PNM. “The San Juan replacement plan we put forth will not only save customers money but will have one of the largest solar facilities in the US and one of the highest percentages of battery storage anywhere in the country.”

Meanwhile, the Tennessee Valley Authority (TVA) has filed its latest Integrated Resource Plan. The utility’s 20-year plan includes up to 2.4GW of energy storage by 2028 and up to 5.3GW by 2038. It suggests a range of 1.5-8.0GW of new solar capacity by 2028 and 14GW by 2038.

The rollout of that energy storage pipeline will be dependent on the cost reductions achieved in the sector. The IRP states: “The trajectory and timing of additions will be highly dependent on the evolution of storage technologies.”

The figures include utility-scale and distributed solar and storage installs as appropriate. While various scenarios were mapped out, “solar expansion plays a substantial role in all futures”, according to TVA.

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Battery storage is gaining a foothold in the California peaker plant market previously served by fast-acting natural gas generators.

Replacing gas peakers notches an early victory for the energy storage industry, but it is not sufficient to decarbonize the grid. Short-duration batteries have a physical limitation: They cannot deliver power indefinitely, and longer-duration options are rare at commercial scale.

That raises the question of what comes next as California, joined by a growing cohort of states, moves toward a legislative mandate of zero-carbon grid power by midcentury.

Nick Chaset grapples with that question as the CEO of East Bay Community Energy, a local organization empowered to source clean electricity for Alameda County, across the bay from San Francisco. His organization recently signed a contract to replace a decades-old jet-fuel-burning peaker in downtown Oakland with a 20-megawatt, 4-hour-duration lithium-ion battery plant.

Despite its smaller capacity and limited run time, that battery will step in to provide local capacity in place of the fossil-fueled asset.

“Right now, there’s still tremendous opportunity for the 4-hour[-duration] investments, which we’re going to continue to make,” Chaset said in an interview after the contract-signing ceremony. “What you’ll see is, through 2030 probably, it’s storage, 4- and 6-hour batteries, [that] gets you where you need [to be].”

After that, the path is less certain.

Near-term vision: Build the batteries
Peaker plants make easy targets for the clean energy industry. They act as a form of physical insurance against blackouts, costing ratepayers hundreds of millions of dollars even though they rarely participate in the grid. When they do, they burn dirtier than other resources.

Solar and wind power cannot replace peakers, because they do not dispatch on command. Batteries can, however, and they enjoy certain advantages when it comes to siting in load pockets like urban areas where a new thermal plant may not survive environmental permitting. Moreover, batteries can participate in grid activities when they are not needed for peak power, defraying their cost as a reliability asset.