One of the biggest criticisms of power produced by renewables is that the wind does not always blow and the sun does not always shine. Since renewable electricity generation can be intermittent, it is at a disadvantage compared to coal, natural gas, and nuclear power plants that produce steady power. As a result, energy storage is considered the missing link between intermittent renewable power produced by technologies, such as solar and wind, and a 24/7 reliable supply of renewable electricity. In addition, no other power industry technology can serve so many vital roles: renewable production smoothing; energy shifting and arbitrage; fast ramping ancillary services; alternatives for peaking generation, transformers, and line upgrades; voltage and frequency support; microgrid supply; electric vehicle charging support; etc.

Over the last decade a surge in lithium-ion battery production has led to an 85% decline in prices, making electric vehicles (EVs) and energy storage commercially viable for the first time in history. Batteries hold the key to transitioning away from fossil fuel dependence and are set to play a greater role in the coming decade.

NextEra Energy, North America’s leading wind and solar generator, is adopting an aggressive approach on the falling cost of energy storage by evaluating the addition of batteries to its existing solar facilities. At the beginning of the year, NextEra’s earnings call showed that the company’s stock has gained more than 50% in the past year, as it deployed 2.7 GW of new and repowered renewables, including 700 MWac of solar power and 340 MW/1.3 GWh of energy storage in 2019.

A small but growing number of utilities across the United States are taking a similar approach to NextEra and adding storage at existing solar plants. In doing so, they can claim the Investment Tax Credit (ITC), tap additional revenue streams, and maximize the existing grid infrastructure.

In fact, NextEra CFO Rebecca Kujawa noted on the same earnings call, “We are designing our own management systems. We believe that some of the real value-add that we are going to be able to provide to customers – that will differentiate us from the competition – is battery system management. This management system and optimization is going to be part of the secret sauce of our batteries.”

Installing and maintaining renewable energy resources can be viewed as an “essential service”, according to the California Solar + Storage Association (CALSSA), based in one of six major state jurisdictions in the US to have ordered citizens indoors for the time being.

The California State Public Health Officer and Director of the state’s Department for Public Health has ordered that all individuals obey instructions to “stay home or at their place of residence, except as needed to maintain continuity of operation of the federal critical infrastructure sectors”. While described widely as a lockdown, the ruling is described at state level as a “shelter in place” directive.

CALSSA said that while the government information is constantly being updated and must be adhered to, with the association prepared to keep on top of monitoring that dynamic situation and give advice accordingly, it considers that solar and storage installation and maintenance work meets that all-important criteria.

The association’s dedicated resources page for COVID-19 advice referred to a list issued by the State of California of ‘Essential Critical Infrastructure Workers’. It includes electricians and those in the construction industry, particularly those providing services that are “necessary to maintaining the safety, sanitation and essential operation of residences”.

‘Busier than ever’ for customer interest, but circumstances dictate a slowdown
In light of the guidance from CALSSA, one energy storage system provider based in California, ElectrIQ, emailed Energy-Storage.news to say that while COVID-19 has caused “confusion and concern” in the marketplace, the company continues to get its product out into the field.

“Covid-19 has definitely caused confusion and concern in the marketplace,” said Aric Saunders, executive vice-president for sales and marketing at ElectrIQ.

Over the past few years, a series of renewables-plus-storage projects announced across the USA created headlines and raised eyebrows due to the extremely low combined PPAs involved. Starting in 2015 with a US$139 /MWh PPA signed by KIUC of Hawaii, we then saw the next landmark reached in 2017 with a US$45 /MWh agreement by Tucson Electric Power of Arizona – only to be surpassed last year by the US$40 /MWh Eland PV-plus-storage project in California.

Comparing that to the generation costs of a conventional peaker easily reaching US$200 /MWh, PV-plus-storage makes an increasingly compelling case. It’s no big surprise, therefore, that around 40 of these systems are already in operation in the USA, combining about 533MW of storage with 1,242MW of solar capacity, mostly in California, Hawaii and Florida, as reported by the Institute for Energy Economics and Financial Analysis (IEEFA).

To understand energy storage’s contribution to this boom, we need to break down the combined PPA into a solar and a storage share. Let’s take the aforementioned Eland project for example, in which the PPA without storage would have amounted to US$20 /MWh (“base” price) and a US$20 /MWh “adder” was offered for the storage system, resulting in a PPA of US$40 /MWh for all MWhs delivered. While a PV LCOE at this level is no big news anymore, US$20 /MWh for energy storage seems absurdly low. How is such a low storage adder possible, you might ask, considering that LCOS (Levelised Cost of Storage) is very likely to remain above US$100 /MWh for the next couple of years?

We asked ourselves the same question and decided to drill down into the Eland project (above), consisting of 400MW of PV (AC) and 300MW / 1,200MWh of energy storage located in the Californian Mojave desert, to find the answer.

Reverse-engineering the actual remuneration for the storage system
It is important to understand that the storage adder component of the PPA should not be compared to the LCOS as it is not equal to the actual remuneration for the energy provided by storage. To put the adder into relation to storage costs, we need to “reverse-engineer” this remuneration per MWh, i.e., how much is paid for each MWh discharged from the energy storage system, and we can do this in five steps.

Firstly, we need to account for the fact that the storage adder is paid for all MWhs delivered by the project, not only for the MWhs discharged from the storage system. Taking a sample day from the Eland project, the amount of energy discharged from storage (1,200MWh) is significantly smaller than the amount of energy delivered by the solar-plus-storage system in total (4,700 MWh), i.e., the energy for which the project is remunerated. In other words, the renumeration for 1 MWh of stored energy is distributed over several MWh delivered by Eland in total, in this case, 3.9 MWh. Hence, the ratio of total energy remunerated over energy discharged from storage, 3.9, needs to be multiplied with the storage adder to calculate the actual remuneration for energy discharged from the storage system. That results in an “adjusted adder” per energy from the energy storage system of US$20 USD/MWh * 3.9 = US$78 /MWh.

With many climate protection advocates as well as the industry itself calling on Europe’s lawmakers to recognise the importance of energy storage, a “significant slowdown” in 2019 is expected to be countered with a more positive outlook going forwards.

Yesterday (23 March 2020), the European Association for Storage of Energy (EASE) and analysis firm Delta-EE released the latest annual edition of its European Market Monitor for Energy Storage (EMMES). It shows that 1GWh of energy storage was deployed across Europe in 2019, a “significant slowdown” compared to the previous year, when over 1.4GWh was installed.

Market dynamics across the continent are complex – the main form of remuneration for large-scale energy storage in particular is to be found in providing frequency regulation and other ancillary services to grid operators, rather than in bulk storage and dispatch of energy from batteries. This front-of-meter segment, where battery systems are connected directly to the grid, saw a slowdown as frequency containment reserve (FCR) markets are becoming saturated in former leading regions such as the UK and Germany, the report found.

At the Energy Storage Summit hosted in London by our publisher Solar Media, for example, Jochen Schwill, CEO of Next Kraftwerke, an aggregator that plays into those markets, said that weekly prices paid for services in Germany have halved, while there is no market for longer duration storage.

“The prices in these markets has reduced from €16 (US$17.26) per MW per hour back in 2015 down to €6 per MW/hour today so it’s a big reduction in this price and Next Kraftwerke is a German aggregator, so they were taking the batteries to the market – and the German market is seriously slowing down in the past [couple of] years,” Corentin Baschet, head of market analysis at market research and technical consulting services company Clean Horizon, told Energy-Storage.news in an interview.

Europe’s FCR market is now interconnected, with six countries involved (Germany, France, Austria, Belgium, the Netherlands and Switzerland – with Denmark set to also join soon) and this has increased the efficiency with which batteries can quickly balance the supply and demand for electricity across the continent.

The energy storage industry in the US is experiencing delays and could be staring in the face of potential job losses, according to a poll conducted by the national Energy Storage Association (ESA).

“The COVID-19 virus has placed unprecedented stress on the physical and economic health of communities around the world, and in just a few short weeks has upended our daily personal and work lives for an undetermined period ahead. For individuals working in the energy storage industry, the story is no different,” a statement sent out yesterday from the ESA read.

The association had sent out a short survey last Wednesday, 18 March finding out from 175 respondents that “the impact has been immediate and potentially devastating to our industry”.

Almost two-thirds (62%) of respondents are “already experiencing delays in project development,” while an actual two-thirds (66%) expect to “incur delays soon”.

Of that latter figure, 44% are experiencing short-term impacts (defined as a month’s worth of delays) already, while more than a third (37%) anticipate six months or more of delays in project deployment.

What can be done?
The ESA highlighted the benefits that energy storage brings, including increasing grid efficiency and lowering the cost of power supply, adding longevity to existing grid infrastructure, allowing for more clean energy resources to be added and enabling backup for when blackouts occur. This is added to the employment of some 60,000 people across the US and around US$1 billion a year of economic activity that energy storage accounts for.

The novel coronavirus (Covid-19) outbreak has caused a slowdown of China’s economic growth, and with China being a global manufacturing hub, is having a negative impact on the world economic growth as well. The majority of the factories remain closed or are not able to attain full production capacity due to shortage of staff and raw materials. These actions have negatively impacted stock markets across the world. Corresponding to the spread of this coronavirus outbreak, risks are on the rise.

The current scenario in China is going to have an effect on the global clean energy sector, including renewable energy sources, battery energy storage, electric vehicles (EVs), and renewable heat and cooling. China is a world leader in renewable energy investment, which can be seen in the country’s wind power installation; wind turbine manufacturing and solar photovoltaic (PV) manufacturing. The country is increasing its portfolio of renewables, decreasing coal consumption, and enhancing efficiency in an effort to deal with carbon emissions. The Chinese Government has also been involved in numerous measures to boost strong battery manufacturing with the aim of being a leader in the global battery market.

China’s battery manufacturers, supported by the government’s industrial expansion vision, are coming up with massive battery production plants. CATL and BYD, two of the largest battery manufacturers in China, are widening their production capacities abroad backed by the Chinese Government. Lithium-ion (Li-ion) batteries are the undisputed market leader in the electrochemical storage projects across the world. The global lithium-ion battery market is dominated by players such as Panasonic, LG Chem, Samsung SDI, BYD and CATL. Their position will strengthen over the next five years but with a tilt towards Chinese suppliers, led by BYD and CATL.

As of December 2019, the number of Li-ion battery megafactories that are in pipeline to 2029 stood at 115, with 88 of them in China. Europe’s planned Li-ion battery capacity is 348GWh by 2029, while China’s pipeline stands at 564GWh by 2028. The total Li-ion battery capacity which is under pipeline is equivalent to 39 million electric vehicles (EVs) by 2029. Encouraging government policies, huge manufacturing base, protectionist measures, along with rising demand for batteries augur well for the Chinese battery market.

Europe’s energy storage boom stalled last year due to a slowdown in large-scale schemes designed to store clean electricity from major renewable energy projects, according to the European Association for Storage of Energy (Ease).

A new study by consultants Delta-EE for Ease found that the European market grew by a total of 1 gigawatt-hours in 2019, a significant slowdown compared with 2018, when the energy storage market exceeded expectations to grow by 1.47GWh.

The slowdown in 2019 has emerged amid rising concern that the outbreak of the coronavirus may stall the rollout of clean energy technologies in 2020, dealing a double blow to the clean energy industry.

The 2019 downturn was particularly marked for large-scale energy storage projects which connect directly to energy grids, and can help make better use of renewable energy by storing the clean electricity to use when wind and solar power is not available.

These large, utility-scale projects often require planning permission, government financial support or procurement tenders to move ahead. Meanwhile, the rollout of home battery kits, which relies far less on policy support, remained a fast-growing market.

Patrick Clerens, the Ease secretary general , said: “The message is clear: even if energy storage is a key enabler of the energy transition and clearly seen as a major tool to achieve the emissions targets linked to the Paris agreement, more support is needed.”

The report expects the EU’s clean energy package, which has legislated support for clean energy technologies, to be key to creating a framework for investing in energy storage.

Clerens said the package was “an important step” which should allow energy storage “to reach its full potential fast”.

Robin Adey-Johnson, the author of the Delta-EE report, added: “Storage remains a young market and the regulatory landscape is trying to catch up. So, year-on-year fluctuations in market growth are not unexpected. But we see strong underlying drivers and we expect further market expansion in the early 2020s as regulation stabilises and revenue streams mature.”

The International Renewable Energy Agency (IRENA) has attempted to define the value of energy storage in a bid to nudge policymakers into introducing financial rewards which drive deployment of the technology and hence accelerate the energy transition.

The multilateral body’s Electricity Storage Valuation Framework (ESVF) attempts to address the issue of “missing money”, which occurs when the value of energy storage is not recognized sufficiently for investors to get projects off the ground.

The high cost of large scale energy storage facilities, notwithstanding advances made with lithium-ion systems, makes the need to recognize the value such installations can offer more urgent, although IRENA predicts total installed costs could fall 50-60% by 2030 if manufacturing can be optimized and the volume of raw materials required reduced.

IRENA says offering multiple services from energy storage is key to unlocking the technology’s value. The value to be gained by offering energy arbitrage – buying when the wholesale power price is low, storing it and releasing it to satisfy high demand – can be significantly boosted by also offering grid ancillary services such as frequency regulation, voltage control and black start support – rapid energy supply after black-outs – especially if such services are financially rewarded.

For example, a portion of a facility’s energy storage capacity could be withheld from arbitrage and kept for operational grid reserves, provided payment for the latter was persuasive enough.

March 20 (Renewables Now) – Gresham House Energy Storage Fund Plc (LON:GRID) said today it has entered a conditional agreement to buy a 50-MW battery storage project in South Yorkshire, England.

The project, located near Thurcroft, will be Gresham House’s largest utility-scale battery storage scheme once commissioned in the second quarter of 2020. The fund bought the asset from developers Gresham House DevCo Ltd and Noriker Power Ltd for an undisclosed sum.

The Thurcroft project is one of the identified assets in an exclusivity pipeline listed in Gresham House Energy Storage Fund’s initial public offering (IPO) prospectus from October 2018. The battery-only site will bring revenues mainly from asset optimisation, earning income from the wholesale market and the National Grid’s balancing mechanism, the buyer said.

Once the latest purchase is completed, Gresham House will expand the utility-scale battery storage projects in its investment portfolio to 224 MW. The fund also plans to further grow this portfolio by acquiring a 50-MW battery storage project at Wickham Market and switching on a 10-MW extension of its 40-MW Glassenbury facility in Kent. It also said it is conducting due diligence on expanding an existing project to over 50 MW.

Two years ago, when New York state announced the first round of winners in its annual renewable energy procurements, upstate wind farms were the star of the show — including one of the largest wind projects ever put forward east of the Mississippi River.

Jump to today, and solar utterly dominated New York’s latest onshore renewables round, reflecting the general direction in which the U.S. power market is expected to move over the next few years.

In its third annual land-based renewables round, the New York State Energy Research and Development Authority, or NYSERDA, selected 21 large-scale projects totaling 1.3 gigawatts to receive around $1 billion of state support. The projects will be built over the next few years.

The list of winners includes just one large wind project — a 145-megawatt development backed by Terra-Gen — alongside a handful of refurbishments of existing wind farms, known as repowerings, that will add a fairly small amount of new generating capacity.

The rest of the projects are all large-scale solar arrays, from a series of 20-megawatt projects to the massive 270-megawatt South Ripley solar development in western New York that will be built with 20 megawatt-hours of storage by developer ConnectGen.

Other big winners include NextEra Energy Resources, which went home with 380 megawatts of solar capacity spread across two projects, and SunEast Development, whose haul includes eight projects totaling 220 megawatts. The round also saw the launch of veteran Canadian developer Boralex into the U.S. solar market, with four projects totaling 180 megawatts.

Wind fighting the tide of solar
2020 is expected to be the biggest year in history for American wind farm construction, as developers take advantage of the final year to complete projects qualified for the 100 percent federal Production Tax Credit (PTC).