Yesterday, Los Angeles Department of Water and Power (LADWP) Board of Commissioners voted unanimously to approve a power purchase agreement (PPA) with 8minute Solar Energy for a solar power plus energy storage facility located in Kern County, California. Now that the LADWP commission has approved the project, it will move to a vote with the Los Angeles City Council before it can be delivered to the Mayor’s desk for a final signature. The project’s guaranteed commercial operation date is December 31, 2023 – about 12 years after it was initially filed in early 2012.

The LADWP portion of the 25 year PPA is for 375 MWac of solar power coupled with 385.5 MW / 1,150 MWh of energy storage, while Glendale Water and Power took the other 25 MWac of solar plus 12.5 MW / 50 MWh of energy – totaling 400 MWac of solar plus plus 300 MW / 1.2 GWh of energy storage. LADWP will pay about $1.1 billion over the 25-year contract.

When pv magazine USA originally reported on the project, it was suggested that it would be up to 400 MWac of solar plus 200 MW / 800 MWh of energy storage – which would be priced, in aggregate, at 3.297¢/kWh. The final version of the project delivered will in fact be a 300 MW / 1.2 GWh energy storage installation – with an aggregate pricing of 3.962¢/kWh.

The project was originally offered at a record US price of 1.997¢/kWh for solar power alone, but the prices have increased with the energy storage adders – so we, technically, might no longer have a record low solar power price with this project. One might argue that the NV Energy contract 8minute signed for 2.376¢/kWh is still the cheapest “solar” in the USA, with this project being the cheapest “solar+storage” whose price has been revealed to date.

The image below, from a presentation by team members shows the project broken into Phase 1 and 2, each 200 MWac of solar and 100 MW / 400 MWh of energy storage. At the bottom of the image, the energy storage expansion is described – noting a 0.665¢/kWh adder, and that the two projects would meet 3.8% of the city’s renewable portfolio standard in 2025.

Kern County, California has many thousands of pages of PDFs describing the environmental aspects of the project. The project brought together 22 real property agreements – including many transmission easements, as well as land options and purchase agreements. The LADWP page hosts a 930 PDF that includes the contracts, and a lot of great information.

The total amount of electricity to be produced by the facility is still a bit fuzzy.

The 200 MWac Eland 2 project contract states the site is expected to deliver 856,094 MWh of electricity in the “initial stub year”, with 80% of that value guaranteed – but an option that 120% might be delivered (below image). As well, if there is “excess energy”, that is electricity that is greater than the 120% value, the customer is obligated to purchase such electricity – but at a discounted price of 1.154¢/kWh.

Energy storage embodies the symbiotic nature of renewable energy more than any other singular source. It’s like a jacked-up version of a pilot fish, bringing out the full generating potential of the resource that its paired with.

It should come as no surprise that as solar energy grows and expands, especially in the residential market, storage is right there, growing alongside it. This view is cemented by Wood Mackenzie Power and renewables’ new report the Q3 2019 U.S. Energy Storage Monitor, which shows that the United States deployed 35 MW of new, residential, energy storage in Q2 2019.

That represents the highest single-quarter mark ever and a nearly 33% increase over the previous high of 26 MW in a single quarter, set a year ago in Q2 2018. It’s also 41% higher than Q1 figures.

In total, 76 MW of storage was deployed in the second quarter of 2019, with this figure representing both front-of-the-meter (FTM) and behind-the-meter (BTM) resources. These 76 MW represent 165 MWh, with 83% of all MWh coming from BTM projects. California’s residential market accounted for 23% of all MWh deployed in the quarter at 39.2 MW, the most of any state and followed by Hawaii at 10.7 MWh and the PJM service area excluding New Jersey at 3.7 MW.

While residential storage is booming like never before, that success is not matched by the remaining sectors, though that does depend on how one defines success. This is because year-over-year energy storage deployments are up 20%, however the market fell 49% quarter-over-quarter. This Fall is mostly driven by a stagnation in FTM deployment, as residential/nonresidential figures are modestly smaller than their Q1 peers.

However, all of that doom and gloom is brought up just to say that Wood Mackenzie does not expect to see a downwards trend in future deployment, in fact the opposite is true. While FTM deployment fell 77% quarter-over quarter, the figure is still 17% higher year-over-year and the FTM pipeline grew by 66% in Q2, driven by continued large-scale utility procurements and developer interest in ISO markets.

And speaking of projections, Wood Mackenzie anticipates that 2019 will finish with 478 MW deployed, a 54 percent increase over the 311 MW deployed in 2018. Looking further into the future, Wood Mackenzie predicts that the storage market will grow by roughly tenfold between 2019 and 2024, bolstered by supportive policy structures and new opportunities for storage to provide wholesale market services.

The dramatic fall in cost, occuring alongside the mass roll-out of home storage systems in Germany since 2013, has highlighted the potential of decentralised batteries in virtual power plants to utility companies and grid operators.

Since 2017, every second residential PV installation in the European state has been accompanied with a battery pack, and there are now roughly 150,000 home storage systems with an estimated capacity of about 1GWh in circulation. Decentralised batteries are “one of the hottest topics in energy research,” according to Dr Kai-Philipp Karies, Jan Figgener and David Haberschusz, energy storage researchers at RTWH Aachen University in Germany.

In an article for Volume 20 of PV Tech Power, the quarterly technical journal from our publisher Solar Media, the researchers argue that battery storage systems are at “the edge of profitability” across several market segments today. The article looks at the emotional and economic drivers behind Germany’s residential storage boom and unpacks the complex business case for commercial storage. It also highlights the role multi-megawatt batteries could have in supporting national transmission grids and phasing out fossil fuel generation.

When it comes to the latter, the researchers note that Germany and the UK are the two “most important” markets in Europe. The UK – which is more susceptible to energy instability due to its island grid – can “prevent, or at least mitigate” national grid blackouts like the one incurred in late August by deploying “increasing amounts” of utility-scale battery storage systems. In Germany, three of the four grid transmission operators have submitted bids to the German grid regulator to test ‘grid-boosters’ – in other words, battery systems with a total capacity of 1.3GW.

Practical insights gained from the operation of grid-operated battery systems will provide lessons for a future which must cater to an increasing number of electric vehicles, according to the academics.

Good things don’t always come easily. Microgrids are no exception.

“The process of developing microgrids can be costly. It begins with a feasibility study reaching hundreds of thousands of dollars, even before any design, procurement and installation,” said Kay Aikin, CEO of US-based Introspective Systems.”Moreover, those feasibility studies are filled with disclaimers, and closing the gaps of uncertainty is crucial. Microgrid designs are unique, and therefore it is difficult to scale up the process of those studies without the use of technology.”

Fortunately, artificial intelligence (AI) and machine learning (ML) can help. Aikin’s company, along with Israel-basesd Brightmerge, are incorporating both into a microgrid software platform that determines microgrid feasibility and creates optimal design specs and operational controls.

The partners have several pilot projects underway with the goal of bringing the software platform to alpha stage in the second quarter of 2020 and rolling out production systems in 2021.

One pilot project is moving forward faster — a solar-plus-storage microgrid on Maine’s Isle au Haut that’s due to break ground soon. “We’ll build the system over the next 2-1/2 months with the aim of having it up and running by mid-November,” Aikin said in an interview. The island is served by an aging undersea cable connected to the mainland 20 years past its useful life that could fail at any time.

Transactive energy and microgrids
The Introspective Systems-Brightmerge microgrid software development project is governed under a contract Introspective Systems recently finalized with the Israel-U.S. Binational Industrial Research and Development (BIRD) Foundation. Its unit, BIRD Energy, has been awarding grant funding for projects proposed jointly by US and Israeli companies since November 2009.

Brightmerge and Introspective Systems won a grant in December 2018 to develop and test dynamic grid pricing with edge load responsive device control. The grant was part of $6 million in funding BIRD Energy awarded to seven projects to be carried out jointly by Israeli and US organizations.

Distributed energy resources (DERs) is an expansive term, including everything from backup generators to microgrids.

In some states with 100 percent clean energy mandates, like California and Hawaii, the focus is on solar — lots and lots of it — and the tools needed to integrate this massive new grid edge resource.

Batteries are another important tool in the kit, but so are air conditioners, water heaters, refrigerators, pumps, and other behind-the-meter flexible loads — not to mention electric vehicles.

Distribution utilities are going to need all of these DERs to manage the paradigm shift to come as renewables grow to a majority of the grid’s energy. But integrating DERs that are customer-owned and outside direct utility control is a challenge on many levels.

There are some commonalities in how utilities, regulators and DER providers are progressing in the most forward-thinking states. But the work is hard, it takes a long time, and it hasn’t yet yielded the expected outcomes in all cases.

California
California has been and remains at the forefront of the country’s DER revolution.

The Golden State is by far the biggest market for solar, behind-the-meter batteries and plug-in electric vehicles. And its ambitions are grand, with a mandate for 100 percent carbon-free energy by 2045 matched by an impressive quiver of policies supporting DER growth, from laws requiring solar on all new homes starting next year to multi-billion dollar EV charging infrastructure investments.

But the past few years have been spectacularly challenging ones for California energy policy, led by Pacific Gas & Electric’s bankruptcy and the threat of more wildfires leading the state’s other big utilities toward insolvency.

A new report from Navigant Research tracks global energy storage developments, providing a database of projects sorted by country, region, market segment, capacity, status, technology vendor, systems integrator, applications, funding, investment, and key milestones.

As global electricity grids embrace the new energy economy, energy storage is becoming a necessity in grid infrastructure. In recent years, the landscape for this technology has grown increasingly sophisticated, marked by new types of projects being monetized through innovative business models. Click to tweet: According to a new report, Navigant Research has identified 2,092 energy storage projects globally.

“Several new companies have entered the market across the energy storage value chain while legacy companies have sought to bolster their presence,” says Ricardo F. Rodriguez, research analyst at Navigant Research. “The growing need to modernize global electricity grids and the evolution of business cases for deploying storage are expected to ensure continued market growth.”

Several key factors continue to increase the global need for energy storage deployments, according to the report. The restructuring of electricity markets will enable valuation of the flexible benefits of energy storage deployments, while variable generation sources such as solar PV and wind that are connected to power grids will require increased load balancing against demand. Areas with unstable grids and frequent outages will benefit from distributed energy storage systems (DESSs) and microgrids with storage, and load profiles are expected to play a critical role in the structure and operation of the power grid, which will influence the development of energy storage markets.

The report, Energy Storage Tracker 2Q19, provides a comprehensive resource of global energy storage projects. The Tracker includes a database of 2,092 projects and tracks the country, region, market segment, capacity, status, technology vendor, systems integrator, applications, funding, investment, and key milestones of each project. It also includes an analysis of the technology choice within each major region for energy storage, analysis of the leading regions for energy storage capacity and projects, and market share analysis for technology vendors for deployed and future projects. An Executive Summary of the report is available for free download on the Navigant Research website.

July 2019 saw the introduction of significant changes to the way in which Frequency Control Reserve (FCR) auctions are conducted. Gone are the weekly auctions, replaced by daily auctions in a move designed to create greater flexibility and improve international co-operation in these markets in Europe.

To understand the impact of these changes on the energy storage market – an important factor in balancing the wider electricity market – we must first understand how these FCR auctions work. Power markets across Europe are managed by various services designed to ensure that the frequency of the grid across these markets remains within an acceptable range. These services are designed to respond to and correct any frequency deviations back towards the norm of 50Hz to minimise the chance of blackouts occurring. Across Austria, Belgium, France, Germany, the Netherlands and Switzerland, this is carried out via a common auction of a service (the FCR).

This issue is particularly topical given recent events in Britain. In August a huge, sudden drop in frequency put parts of the train network out of operation for hours as power was cut off in some areas to keep the wider network operational.

How and why does this affect energy storage?
Well, storage is an important mechanism in controlling the frequency. In countries that participate in the FCR, there is a significant amount of hydro-capacity; only the Netherlands lacks this. Other storage also plays a role but is competing against pumped storage and hydro basins (this has not changed under the new rules). Either way, there are plenty of options to use energy storage as a lever to manage frequency.

These options have increased with the switch from weekly to daily auctions, as it allows parties to enter and exit the market more frequently. In contrast, generators that participate in a weekly auction need to commit to being around for the whole week.

Another significant reason why energy storage is important is that most of the FCR is made up of ‘spinning reserve’ – the extra generating capacity made available by increasing the power output of generators already connected to the power system. Spinning reserve can only be offered by storage and running plants, which rules out generating capacity that is not connected to the system but can be brought online after a short delay. With fossil generation out-of-merit for much of the time (coal and lignite plants), these plants have no need to keep running because they provide FCR to the Transmission System Operator (TSO).

Storage, then, is clearly an important player in the ongoing drive to balance frequency, so does Europe have enough capacity? The short answer is yes; Europe can currently meet its daily demand for FCR. Countries such as France and Switzerland have surplus capacity, whereas the Netherlands and Belgium are tighter. The joint auction ensures some level of stabilization across those markets, but transfer capacity between countries is limited, which causes local issues. For example, markets ‘decouple’ when transfer capacity is insufficient, or if local capacity is priced too high to be in the merit order of bids.