As California goes, so goes…the world?

Earth’s 5th largest economy has put forth its 2019-2020 Integrated Resource Plan (IRP) – Proposed Reference System Plan (173 page pdf), and it suggests that solar and energy storage will “dominate” through 2030 and beyond. The purpose of the document is to lay a path, based on hard research of both costs and technical feasibility, to move the state toward 100% renewable electricity and, net negative CO2 by 2045.

On the slide titled (below), ‘Summary of Annual Resource Buildouts from 46 MMT “Default”‘ the model shows exactly how much volume was considered in an annual basis from various resources. In another area, the 46 MMT model as suggests that by 2030, ~11 – 19 GW of battery storage will be deployed for the main purpose of shifting solar generation into the nighttime. The total (baseline + selected) battery storage RA capacity contribution is ~13 – 16 GW.

In the document are multiple modeled cases, with the 46 million megaton (MMT) of emissions as the current recommended model. It was noted, that while not equivalent, the state’s 60% renewable portfolio standard by 2030 and the 46 MMT model had similar procurement outcomes.

Per the document, all batteries considered in the IRP are 4 hour batteries, though it suggests that lithium ion will transition into 6 to 8 hours batteries by 2030. A battery recently approved by the New York State Public Service Commission is a 316 MW / 2528 MWh 8 hour energy storage facility.

Part of the reason for the very large increase from prior IRPs for solar and energy storage is that both technologies have decreased in pricing much faster than projected (below image) – modeling that utility scale costs are roughly half of the 2017 IRP values. As well, in 2018, the preferred IRP noted that the Marginal GHG Abatement Cost was $219 per metric ton, and had fallen almost 50% to $113 per metric ton.

GHG emissions are modeled higher in 2024 relative to 2023, in large part due to the retirement of the Diablo Canyon Nuclear Power Plant. A capacity shortfall in 2021, followed by retirement of the 2 GW of capacity from the plant in 2024-5, results in all available gas power plants being retained for CAISO ratepayers through 2026 in all core policy cases.

Batteries are rapidly becoming less expensive and might soon offer a cheap short-term solution to store energy for daily energy needs. However, the long-term storage capabilities of batteries, for example, in a yearly cycle, will not be economically viable. Although pumped-hydro storage (PHS) technologies are an economically feasible choice for long-term energy storage with large capacities — higher than 50 megawatts (MW) — it becomes expensive for locations where the demand for energy storage is often smaller than 20 MW with monthly or seasonal requirements, such as small islands and remote locations.

In a study published in the journal Energy, IIASA researcher Julian Hunt and his colleagues propose MGES to close the gap between existing short- and long-term storage technologies. MGES constitutes of building cranes on the edge of a steep mountain with enough reach to transport sand (or gravel) from a storage site located at the bottom to a storage site at the top. A motor/generator moves storage vessels filled with sand from the bottom to the top, similar to a ski lift. During this process, potential energy is stored. Electricity is generated by lowering sand from the upper storage site back to the bottom. If there are river streams on the mountain, the MGES system can be combined with hydropower, where the water would be used to fill the storage vessels in periods of high availability instead of the sand or gravel, thus generating energy. MGES systems have the benefit that the water could be added at any height of the system, thereby increasing the possibility of catching water from different heights in the mountain, which is not possible in conventional hydropower.

“One of the benefits of this system is that sand is cheap and, unlike water, it does not evaporate — so you never lose potential energy and it can be reused innumerable times. This makes it particularly interesting for dry regions,” notes Hunt. “Additionally, PHS plants are limited to a height difference of 1,200 meters, due to very high hydraulic pressures. MGES plants could have height differences of more than 5,000 meters. Regions with high mountains, for example, the Himalayas, Alps, and Rocky Mountains, could therefore become important long-term energy storage hubs. Other interesting locations for MGES are islands, such as Hawaii, Cape Verde, Madeira, and the Pacific Islands with steep mountainous terrain.”

If energy and transportation planners stop seeing their sectors as separate markets for batteries—a World Resources Institute researcher argued last week—there will be more than enough energy storage to go around.

“An electric vehicle, because of the battery, is really both a mobility asset and an energy asset,” said Camron Gorguinpour, WRI’s global senior manager for electric vehicles, “and so we really want to start looking at the duality of electric vehicles rather than really just trying to focus on one thing.”

Vehicle-to-grid technology is not a new idea—China jumped on it early—but it looks like an increasingly promising idea as electric-vehicle adoption takes off.

The International Energy Agency’s most conservative estimate puts 130 million electric vehicles on the road by 2030, and Gorguinpour said those vehicles will contain almost ten times the amount of energy storage needed by the grid.

The IEA’s most aggressive estimate, 250 million EVs, would mean 6 percent of the batteries in the automotive fleet could meet all of the grid’s energy-storage needs.

“When we talk about the dual nature of electric vehicles as energy and mobility assets this is really what we’re talking about,” he said.

If the energy and transportation systems can share batteries, it will reduce demand on resources such as lithium, critical minerals and rare earth elements, Gorguinpour said last week in a webinar hosted by Climate Action.

“If you don’t use vehicles for this purpose, you’re going to have to create stationary batteries which would then put pressure on the available resources to provide the necessary energy services,” he said, “so part of the strategy is again coupling different activities using common resources so that we’re not really putting a lot of pressure—well, more pressure than necessary—on available natural resources.”

Navigant Research has released a new report providing market forecasts for newly installed distributed energy storage systems (DESSs) in terms of power capacity, energy capacity, and revenue across 26 countries. The report forecasts the sector to grow twentyfold by 2028 due to cost declines, government incentives, and increased solar PV integration.

The distributed energy storage industry has seen significant growth over the past five years. Breakthroughs in adjacent digital technologies, including artificial intelligence, blockchain, and predictive analytics, are facilitating the emergence of DESSs as a key enabling technology for aggregated distributed energy resources (DER) solutions.

“DESSs are inherently flexible, can be deployed rapidly, and have the potential to generate multiple value streams,” says Ricardo F. Rodriguez, research analyst with Navigant Research. “They can also provide multiple grid and customer benefits, like reducing congestion on the network or limiting the need for peak capacity resources.”

Utility involvement, along with cost declines, government incentives, and increased solar PV integration are the primary growth drivers responsible for increased DESS deployments.

Yet despite increasing momentum, long-standing uncertainties concerning feasible uses and cost-effectiveness remain. Consequently, DESSs are expected to remain concentrated in select markets in the near term before spreading to new areas as system costs decrease and business models continue to be refined.

The report, Country Forecasts for Distributed Energy Storage, provides forecasts for distributed-scale ESSs deployed globally in terms of power capacity (MW), energy capacity (MWh), and revenue generated from the development of new projects in 26 countries.

These forecasts cover systems providing all major distributed-scale energy storage services and applications. The report details developments in 16 major countries.

Forecasts include the most common technologies for distributed-scale energy storage for 2019-2028. An Executive Summary of the report is available for free download on the Navigant Research website.

Lazards has released their two levelized cost of hardware reports – 2019 Levelized Cost of Energy (pdf) and the 2019 Lazards Levelized Cost Storage (pdf) analysis. At a high level, both solar power and energy storage have shown continued price declines, but the numbers are of course much more complex.

Solar power’s utility scale price declines have slowed over time. The report suggests an unsubsidized utility scale solar power plant is going to generate electricity at a cost between 3.6 and 4.4¢/kWh. This price has fallen 89% over the past ten years, an average of 20% decline per year over the period. Over 5 years, that decline fell to 13%, and over the last year that price decline was 4-10%.

When adding in the 30% Investment Tax Credit for the US market, utility scale projects fall an additional 0.1-0.2¢/kWh.

Energy storage has also seen across the technology spectrum price delines, with lithium ion outpacing other sources of storage. However, the technology is still expensive with its use cases dictating when it can be used in a financially viable manner. The energy storage report’s financial modeling shows Levelized Project Internal Rates of Return (IRR) ranging from 35% for a standalone 100 MW / 100 MWh facility in the California Independent System Operator (CAISO) region, down to a 7.7% IRR for a 100 MW solar + 50 MW / 200 MWh storage sized facility in the Texas ERCOT region.

The above chart breaks down the various services that energy storage can offer, and shows how it varies greatly across use cases even in the same markets. For instance, in CAISO you see hardware participating in the wholesale market earning revenue from resource adequacy, spinning/non-spinning reserves, frequency regulation and demand response. While we see residential and commercial/industrial solar+storage making almost all of their money from bill management – which is demand charge management of time of use arbitration.

Last year’s report showed that new wind and solar power were cheaper than certain already running resources (coal and nuclear, and some gas), unsubsidized, in the United States. This year, that modeling expanded globally and shows that solar power on its own can beat gas peaker plants on their own – without storage – in most any market. This is setting us up to see a new report showing how solar+energy storage peaker plants are ready to dominate. This is already happening in key markets in the USA.

SAN DIEGO–(BUSINESS WIRE)–Energy Storage North America (ESNA), the most influential gathering of policy, technology and market leaders in energy storage, today announced the winners of this year’s ESNA Innovation and Champion Awards. The awards were presented at the 7th Annual Energy Storage North America Conference and Expo, held at the San Diego Convention Center. This year’s winners will also be inducted into the ESNA Awards Hall of Fame, online here.

The ESNA Innovation Award winners were selected from the most geographically and technologically diverse group of Innovation Project Award nominates to date through a public, online voting process that received over 2,500 votes across three categories: Front-of-Meter, Behind-the-Meter and Microgrids. The winner in each category was recognized for their impact on the energy storage ecosystem, services supplied to customers and the grid, unique technology solutions, financing or partnerships.

ESNA Innovation Award Winners

Front-of-Meter Storage

Goderich Advanced Compressed Air Energy Storage Facility powered by Hydrostor – Goderich, Ontario
Behind-the-Meter Storage

Connected Solutions powered by National Grid – Waltham, Massachusetts
Microgrids

Nantucket Battery Energy Storage System powered by National Grid
ESNA Champion Awards recognize individuals from the utility and policy sectors who have demonstrated significant leadership in advancing the role of energy storage to achieve a cleaner, more reliable and more resilient electricity grid.

ESNA Champion Award Winners

Utility Champion

Martin Adams, General Manager and Chief Engineer, Los Angeles Department of Water & Power
Policy Champion

Alicia Barton, President and Chief Executive Office, New York State Energy Research and Development Authority
“The individuals and organizations we’re recognizing with this year’s ESNA Awards have made significant contributions to the growth and maturation of energy storage as a mainstream grid resource,” said Janice Lin, Energy Storage North America Conference Chair. “Their dynamic leadership and skillful execution serve as greatly needed role models for the global clean energy transformation.”

ESNA is grateful to its 2019 Award Ceremony sponsor KORE Power, as well its 2019 Platinum sponsors Con Edison Battery Storage, Doosan Gridtech, Energy Vault, Fluence, IBEW-NECA and Los Angeles Department of Water and Power; its Gold Sponsors: 8minute Solar Energy, EastPenn Manufacturing, EDF Renewables, Greensmith Energy, a Wärtsilä company, Li-Ion Tamer, LG Chem, SoCalGas; and its Silver Sponsors: DNV GL, GE, Munich Re, Maysteel, PXiSE, Southern California Edison, and Trane for contributing to the success of this year’s program.

In the latest update of Circular Energy Storage’s data on the lithium-ion battery end-of-life market we conclude the that over 1.2 million tonnes of waste batteries will be recycled in 2030. Although it sounds like a massive number, the recycling industry is in fact well prepared and will most probably fight for the volumes.

This is good news for the energy storage industry, as it is for all other businesses placing lithium-ion batteries on the market. More competition means better prices and hopefully both better service and more efficient processes. The so often quoted “lack of recycling” can be removed from the list of concerns anyone might have when investing in lithium-ion batteries.

So with that in mind for energy storage professionals, what else could possibly be worth to know about a market one will mostly deal with first in five or even ten years?

In fact there are at least three important things which are worth bringing to management’s attention today.

The recycling opportunity

For most European and North American companies recycling is a cost. Often for good reasons. First of all we are used to pay to get all kinds of stuff out of the building and retired batteries are normally no different. The recycling process requires a thorough disassembly of the packs and that special measures are taken for safe transportation. If the value from the recycled material doesn’t cover the costs it’s hard for any player to pay for the batteries, no matter how hard to competition might be.

But recycling of batteries in a 50MWh energy storage plant is very different from recycling of batteries from power tools, e-bikes or even electric cars.

50MWh equals about 250-300 tonnes of battery cells, depending on which chemistry has been used. That’s in fact more lithium-ion batteries than what many large battery collectors ever have had in their warehouses. And they are in one place to which they have been moved as batteries, not waste. To recycle 250 tonnes of batteries today can cost anything between €250,000 to €1 million.

But essentially the material is valuable, at least when it comes to NMC batteries which in fact can yield as much as they might cost users to recycle them. How much of it that’s left on the table comes down to efficiency and customer leverage. Most probably few energy storage companies would be interested in getting into recycling themselves. But there is too much value at stake to not as early as possible sit down with potential recyclers and understand how both parties can save costs and thus increase incentives on both sides. A good example of this is how French energy company Engie partnered with the large material producer and recycler Umicore and placed an energy storage system on Umicore’s premises. When the batteries finally die they need to go nowhere.

Consumers Energy and Sunverge recently announced their collaboration to leverage Sunverge’s real-time control, aggregation, and orchestration platform with Sunverge Energy Storage technology for a Consumers Energy residential battery storage pilot.

Sunverge worked with Consumers Energy to evaluate the energy provider’s distribution circuits, and identify grid locations suitable to test the potential benefits and value from behind-the-meter battery storage. Consumers Energy used this analysis to select a circuit in Michigan’s Grand Rapids area to conduct the pilot.

“We are conducting this pilot to test and measure how aggregated battery storage may have the potential to offer benefits to Michigan’s electric grid and our customers,” said Ryan Kiley, executive director of product development for Consumers Energy. “The Sunverge platform’s ability to co-optimize grid services is key to our decision to work with them. In this pilot, we are testing to understand the different values that batteries could provide to the overall grid, such as potential investment deferral, resiliency, and reliability, while also providing backup of critical loads for pilot participants.”

“We are excited to be working with the Consumers Energy team to help them better understand how they may be able to leverage aggregated and orchestrated behind-the-meter storage to provide an overall grid benefit and support their goal of generating 40% of their energy from renewable sources by 2040,” said Martin Milani, CEO of Sunverge.

Consumers Energy is working to modernize Michigan’s electric grid and develop clean energy across the state.

RWE Renewables,a subsidiary of Germany-based RWE Group, has entered into a 30-year PPA with Georgia Power for RWE’s Broken Spoke Solar project, a 195.5-MW solar facility with a 40-MW, 2-hour battery. The project will begin supplying power in late 2021.

“We’re pleased to finalize this agreement with a company like Georgia Power, who has demonstrated a commitment to delivering clean, safe, reliable and affordable energy to its customers,” said Silvia Ortin, COO of onshore wind and solar PV Americas, RWE Renewables. “As of now, we have 3.3 GW of installed capacity in the U.S., plus an additional 1.4 GW of onshore wind and photovoltaic under construction. The Broken Spoke Solar plant will mark our first solar facility in Georgia and our largest solar project in the U.S. to date.”

RWE’s solar power plant is located in Mitchell County, in the southwest corner of the state.

“Broken Spoke Solar will include a 40-MW, 2-hour energy storage system, enabling firm delivery of energy from the facility,” said Christoph Hunfeld, head of asset commercialization of North America, RWE Renewables. “This integrated solar-plus-storage facility will increase energy delivery during peak demand times and simplify integration of locally produced energy into the Georgia Power grid.”

The most central mission of any utility is to supply reliable power, and that’s the one thing that Pacific Gas & Electric Company (PG&E) has shown that it can’t – or won’t do. Starting last month, the bankrupt utility has been proactively shutting off the power in waves to hundreds of thousands of its customers, with outages sometimes lasting as long as days.

But PG&E isn’t the only actor in Northern California’s power sector. The region’s community choice aggregators (CCAs) have taken a state-level requirement to secure resources to keep the lights on, and turned it into a solicitation for energy storage to provide resiliency in their communities.

Yesterday three CCAs in the San Francisco Bay Area – East Bay Community Energy, Silicon Valley Energy and Peninsula Clean Energy, along with Silicon Valley Power (SVP), the municipal utility for the city of Santa Clara, filed a joint solicitation seeking a total of 32.7 MW of batteries. These systems can be paired with existing or new PV systems.

To be clear, these entities need to procure resources to meet state-requirements designed to ensure that they have enough local resources to meet demand, called resource adequacy (RA). And they’ve been struggling to do this; the three CCAs are among 19 that asked state regulators a week ago for a waiver on their RA requirements, arguing that the market for eligible resources is “seriously constrained”.

But these public power entities are turning this into an opportunity. There’s nothing in the RA requirements that say that you need to be able to form microgrids, but that’s what these organizations are doing. Among a list of the types of resources that are eligible under the new solicitation is the following requirement:

All systems must be able to island from the grid to provide resilience to participating customers

And while RA can be met outside a utility or CCA’s service area, the four public power entities have expressed a definite preference for projects in their areas – which is likely so that if they do need to island, they can do so for the benefit of their customers, not somewhere else.