Work has started on the first multi-megawatt battery storage project in Germany.

RES Deutschland is building the 10 MW project for utility VBB in the German municipality Bordesholm.

The battery storage will provide grid stabilization and back-up power fed from 100 per cent renewables to Bordesholm if there is a main grid disruption or upstream grid failure.

Bordesholm currently meets 75 per cent of its electricity demand from renewables which are directly connected to the grid. VBB is aiming to raise this figure to 100 per cent by 2020.

In addition to providing control power, VBB’s battery with a storage capacity of 15 MWh can continue to provide power to Bordesholm if there is a grid outage.

VBB Managing Director Frank Günther said: “This is a unique solution for an island network linking into a public power supply network. With this smart solution, the use of coal and nuclear power plants can be avoided in the future. New, modern battery storage plants can ensure the required system stability by using only renewable energy.”

The Bordesholm project is funded as a pilot project by the EU and the state of Schleswig-Holstein, which is promoting the development of storage technologies.

“With this standalone solution, the battery storage becomes a flagship project, which forms a very important component on the way to a supply from 100 per cent renewable energy,” said Dominique Guillou, managing director of RES Deutschland.

Matthias Leuthold, head of energy storage at RES Germany, added: “Battery storage systems are central elements of the German Energy Transition 2.0. In the coming years, due to the increasing displacement of thermal power plants by renewable energy sources, the provision of primary control power with battery storage systems will continue to gain importance in Germany.”

The VBB-project is the first multi-megawatt battery storage project in Germany. The commissioning of the battery storage is scheduled for spring 2019. After the completion of this pilot project, research institutions and universities will be able to use the data generated from the battery storage to transfer new findings to other network projects.

As the largest state-owned public utility in America, in one of the most progressive states in the country, the New York Power Authority doesn’t have the option of taking a “wait and see” approach on cleantech.

Plus, NYPA’s business model enables it to invest in and deploy new technologies in bold ways, according to President and CEO Gil Quiniones.

New York’s investor-owned utilities are also deploying innovative technologies. But NYPA can generally take more risks and move faster because it doesn’t have to go through the Public Service Commission’s regulatory process.

“We tend to be able to be the first mover and the first tester of new initiatives,” Quiniones said.

GTM spoke with Quiniones last week for an update on NYPA’s 2020 strategic plan, ahead of his keynote interview with Shayle Kann, senior vice president at Energy Impact Partners, at the Grid Edge Innovation Summit taking place June 20-21 in San Francisco.

One of Quiniones’ top priorities is rolling out NYPA’s major new investment in EV infrastructure.

Last month, the public utility announced up to $250 million for EV-related investments over the next seven years. NYPA’s board of trustees has already approved $40 million for specific investments between now and the end of 2019, including around 200 DC fast chargers along major thoroughfares, the installation of EV chargers at New York’s JFK and LaGuardia airports, and the establishment of “model communities” to test various customer engagement programs.

“NYPA is interesting because we serve 47 municipal utilities and four cooperatives (these are small distribution utilities owned by cities or towns). So we will pick two or three to…test various customer engagement strategies to see what sticks in terms of promoting adoption for electric vehicles,” said Quiniones.

How NYPA will spend the remaining $210 million to be deployed by 2025 has yet to be determined. That decision will depend a lot on lessons learned from the first phase of the program, Quiniones said.

A chemical compound commonly used to boost crop yields could be the answer to helping the world increase its consumption of renewable energy.

In a world first, Siemens is opening a £1.5m pilot project in Oxfordshire employing ammonia as a new form of energy storage.

The German industrial firm hopes to prove that ammonia can be as useful as more established storage technologies, such as lithium-ion batteries, when it comes to managing the variable output of wind and solar power.

The proof-of-concept facility at Harwell will turn electricity, water and air into ammonia without releasing carbon emissions. The ammonia is stored in a tank and later either burned to generate electricity, sold as a fuel for vehicles or for industrial purposes, such as refrigeration.

Dr Ian Wilkinson, programme manager for Siemens’ green ammonia demonstrator, said: “Storage is recognised as the enabler for intermittent renewable power.

“This is where we’re different from usual storage, we’re not just looking at power. Usually it’s [storage] just filling in the gaps when the sun’s not shining and the wind is not blowing. We’re looking at other uses, mobility and industrial uses.”

Siemens believes ammonia has an advantage other over emerging storage technologies, such as “liquid air” and flow batteries, because it is repurposing existing technology and hardware.

The world produces about 170m tonnes of ammonia a year, the vast majority of which is used by farmers as fertiliser. Most of that is made from natural gas, emitting greenhouse gas in the process, but the Harwell plant does not use fossil fuels.

In a world first, the UK recently saw a liquid air energy storage (LAES) plant switched on in Bury near Manchester, soaking up excess electricity generated by an adjacent landfill gas facility for later use.

It marks the first time the nascent technology has been deployed commercially, and developer Highview Power believes LAES could soon rival other technologies such as batteries in the rapidly growing global energy storage market.

Capable of lasting for up to 40 years, LAES operations have a much longer lifespan than most batteries, and the technology has the potential to play a key role as the global electricity system shifts ever more towards clean, intermittent and renewable forms of generation.

The technology works by cooling air to -196C to turn it into liquid form, allowing it to be stored in high pressure tanks. When extra power is needed, the liquid is pumped and heated to turn it back into a gas, where it can be used to drive electricity turbines.

According to Bloomberg New Energy Finance, the global energy storage market could double in size six times over the next decade or so, growing to a cumulative 125GW/305GWh and attracting $103bn in investment by 2030.

Highview Power therefore hopes to be at the forefront of the energy storage boom, and is currently planning to add another LAES site in the UK in the near future.

Could the technology in the future rival batteries as a realistic, low cost and scalable proposition for the burgeoning energy storage market? BusinessGreen went to have a look.

Kiran Kumaraswamy of Fluence Energy –Grid-Scale Energy Storage—Market Applications Outlook (PDF) showed off the business application side of energy storage today. Namely, the presentation looked at how a leading supplier of solutions must learn to bend and twist as the markets dictate needs.

Incidentally, Fluence was part of the team that delivered a 30 MW/ 120 MWh lithium-ion energy storage power plant, in a grid emergency situation, within six months, on a 1 acre parcel where a fossil fuel power plant couldn’t be permitted.

Kumaraswamy’s presentation echoed others noting that different marketplaces had different product demands and that it was important to have a unique perspective in each utility marketplace. Reminders of the fact that solar power exists in nearly 50 unique state marketplaces, and that in order to work with various groups you have to “depict the value of storage to their network”.

The above slide was preceded by real life examples of economic arguments to two western U.S. utilities. These two slides very much complemented the language put forth by Abdelrazek of Duke Energy (covered yesterday), who spoke of developing a tool that would guide his teams in determining where energy storage could most economically be deployed within the grid.

One might assume we are in the economically low-hanging fruit portion of the energy storage evolution.

The technical capability of an energy storage plant, showed off below by Kumaraswamy, underlies the risk to the gas peaker plant market. A 100 MW energy storage facility has the ability to offer four times as much energy services within the same 100 MW nameplate.

Remember – GE is laying off members of these highly skilled and talented teams.

At various points every month, every quarter and every year we look forward to the data releases of the US Department of Energy’s (DOE) Energy Information Administration (EIA), as they represent the formal, official and most detailed data on energy in the United States.

At the 2018 EIA Energy Conference, the tightly delivered 15-minute presentations varied from oil, and gas, to electric and automated cars, with a touch of efficiency and energy storage – and of course a whole lot of data. EIA staff members dutifully worked their stations interacting with conference attendees and shared great conversations at the networking lunches.

Specifically, the topic of energy storage was all about growth and how the industry is no longer just talking about energy storage, but deploying projects in the real world with real benefits, consequences and savings

Lisa Cabral, of the U.S. Energy Information Administration, delivered Energy Storage: a U.S. overview (PDF). At a high level, Lisa’s presentation showed that the CAISO and PJM ISO reigons dominated the 664 MW of power and 742 MWh of of large-scale (over 1 MW) energy storage that is now operational. This was driven by state policy and market rules, and the large majority of this volume is lithium-ion batteries.

Many of the slides create a clear picture of the evolution of the industry since the early 2000s – expanding regions, product type (spoiler above), pricing,  as well some future market size projections.

The diversity of applications speaks of the many ways we’re going to come to depend on this solid-state electricity and energy source.

One slide that we most recently saw a large shift around was the residential/small scale volume relative to the big players. Just last week, GTM Research showed us that residential storage grew almost 9x over Q1 2017, representing almost 28% of all energy storage MWh deployed. We’ve been expecting this of course, as the customer has spoken.

Potomac Economics, the Independent Market Monitor (IMM) for the ERCOT market, released its “2017 State of the Market Report for the ERCOT Electricity Markets,” which contains several important insights for market participants and offered seven recommendations for market improvements.

First, the IMM found that energy prices increased 14.7% over 2016, to $28.25 per MWh. This price is still significantly less than 2011’s average annual price of $52.23 per MWh and even 2014’s average annual price of $40.64 per MWh. The 2017 price increase correlates with a 22% increase in the cost of natural gas, the most widely-used fuel in ERCOT, as fuel costs represent the majority of most suppliers’ marginal production costs.  The IMM also found price convergence to be very good in 2017, with the day-ahead and real-time prices both averaging $26 per MWh.  However, the absolute difference between day-ahead and real-time prices still increased from $7.44 per MWh in 2016 to $8.60 per MWh in 2017.

Average demand also increased, rising 1.9% from 2016, with demand in the West Zone seeing the largest average load increase at 8.3% (possibly due to oil and natural gas production activity in that zone). Despite this increase in average demand, peak demand in ERCOT reached 69,512 MW on July 28, 2017, which is lower than the ERCOT-wide coincident peak hourly demand record of 71,100 MW, set on August 11, 2016.  Even with general price and demand increases, market conditions were rarely tight as real-time prices didn’t exceed $3,000 per MWh and exceeded $1,000 per MWh for just 3.5 hours in all of 2017.

Congestion Costs Skyrocket

Surprisingly, the IMM found congestion in the ERCOT real-time market increased considerably, contributing significantly to price increases in 2017 with total congestion costs equaling $967 million – a 95% increase from 2016.  The IMM stated that this increase is due to three main factors: (1) limitations on export capacity from the Panhandle; (2) planned outages associated with the construction of the Houston Import Project; and (3) the aftermath of Hurricane Harvey.

While congestion was more frequent in 2017 than in 2016, congestion on the North to Houston constraint declined after June due to the completion of a new 1,200 MW combined cycle generator located in Houston. The completion of the Houston Import Project in 2018 should reduce congestion in this area even further.