Energy storage markets are charging up
With growing deployment of distributed generation and renewable energy, the energy storage market is projected to grow rapidly in the next decade and beyond. McKinsey & Company estimates the market could increase fivefold from its 2015 levels in the next 20 years as technology evolves, energy intensity improves and costs decrease.
In this interview, Matt Rogers, leader of McKinsey & Company’s Sustainability and Resource Productivity practice, shared key findings on the economically attractive applications of energy storage that are already more prominent than one might think.
In a recent article, "The New Economics of Energy Storage," Rogers's team looked at over 1,000 customer load profiles, dozens of battery technology options and hundreds of local electricity tariffs to identify the viability, type and size of profitable energy-storage solutions.
The team is building on this research to develop a heat map of the United States showing where favorable market conditions can be found.
Clean Energy Finance Forum: Could you tell us about McKinsey’s recent research on the economics of energy storage?
Matt Rogers: What we are trying to do is understand the different use cases for energy storage across the economy.
We started by looking at 14 particular use cases across three to four geographies, identifying the use cases that provided attractive early returns for market entry. We then analyzed behind-the-meter, commercial and industrial applications for different customer types and asked the question: “Under what particular rate structure, whether it is time-of-use, different rate tiers, demand-charge, or no-demand-charge, is energy storage economical?”
CEFF: How did your team assess the profitability of various energy storage options?
Rogers: "Economically attractive," in this case, meant looking at payouts in two years for the customer investing in storage at a particular facility in a particular geography. This means a cash-on-cash return profile on the investment, with investment being the total cost to get the storage technology installed and running.
CEFF: Could you explain the energy-storage-dispatch model you built for the analysis? (Editor's note: See graph below.)
Rogers: In the current model, we looked at real cities and real load curves while using real rate structures for the local utility. We were trying to understand how the return profile differs by customer type — how the load shape for a hospital or a hotel differs from the load shape for a restaurant or a school — and where the incentives structure is such that it makes storage feasible.
CEFF: What did you find to be the key determinants of storage profitability?
Rogers: In the model, the profitable or non-profitable energy-storage-deployment scenario outcomes depended on a number of factors. The rate structure in a particular market makes a big difference. How high are the average versus peak rates? And how big are demand charges as the share of the total amount paid by the customers? Rate structure ends up being a significant differentiator across cities. And then within cities, load curves make a big difference. Some load shapes are coincident with the highest price in the market. Some have frequent peaks while others have infrequent peaks.
This requires us to look at how the customers are going to dispatch the storage — and how frequently they have to dispatch it to make it work. Ultimately, it’s the intersection of rate structure and load profile that determines where the returns are high.
CEFF: Are there any other takeaways from the model you would like to highlight?
Rogers: What’s been quite interesting to us as we looked at it was the number of markets where the returns are attractive today. Storage presents a much bigger market opportunity today than we had expected when we started our research. When we started looking at this, our initial thoughts were that this would be in the money by 2025. But the reality is that in many markets, it’s in the money today.
CEFF: According to the report, in some particular applications, non-lithium ion technologies, including lead-acid products and flow cells, appear to be more economical than competing options. Could you speak more about these technologies and the challenges they face today?
Rogers: We’ve looked at many different technology types across many regions. Flow cells end up being economical when the duration of the storage required is longer. So, if we only need to hold energy for one to two hours, lithium-ion cells make sense. If you have to have to hold energy for five to seven hours, flow-cells end up being a better option to deliver fewer cycles and longer storage. The actual markets are quite different for the two [technologies].
Lithium-ion [battery companies have] done a great job at getting their unit costs down and making the products easily accessible and installable. When I started my work for the United States government, we were convinced that flow cells would have a much larger market because they should be lower cost, but they haven’t proven to be lower cost yet. So, until and unless they get their installed costs down, they are going to have less of a market than they might otherwise.
Lead-acid batteries are ubiquitous. Everybody can buy them. Manufacturers have been getting their costs down. But installing and maintaining packages of lead-acid batteries is a non-trivial task. Thus, lithium-ion solutions have made themselves more easily plug-compatible and cost-effective for many applications.
CEFF: Based on your research and experience, why do you think policies and incentives fail to optimize energy storage deployment in most markets?
Rogers: We are just in the early days of creating regulatory models that create appropriate incentives for energy storage. We have only had economic energy-storage solutions for a short period of time. And most markets have had plenty of capacity and haven’t had to worry about energy storage.
Therefore, ancillary services markets that create the incentives for energy storage options just aren’t that well developed yet. Most markets haven’t gone through the process of trying to figure out how you price storage in markets for voltage support or grid balancing.
Increasingly, with penetration of more distributed energy resources, including renewables, the need has become more apparent. We just haven’t seen the process of setting new services’ prices develop as of yet.
What we end up with is traditional pricing based on where the market rate structures are today, focusing mostly on market demand charges. However, over time, the market can and will develop prices that create incentives for using this technology, especially as storage solutions become more commonly deployed.
CEFF: Per the report, PJM Interconnection deployed over 160 megawatts of energy storage in 2015 – more than any other electricity system operators. Why is PJM ahead of the curve? Do you believe others will follow?
Rogers: PJM has done more than some of the other regional interconnects to establish prices for ancillary services and has encouraged the development of new technologies. That’s why we’ve seen more installs in PJM. There are some very good [lessons learned] from PJM that I expect we’ll see in other markets as well.
CEFF: What are some of the key challenges faced by electricity market professionals in evaluating the economics of energy storage? How can we overcome them?
Rogers: In the energy market, it is particularly hard to evaluate new technologies that offer new use cases. As unit costs come down and storage becomes more economically attractive, more applications will become exciting. Today, we are seeing many use cases being developed.
In our model, we were dealing with simulations using real customer data, but what we really want to see are batteries in real use with real customers in the real world to understand real costs and dispatch challenges in real market conditions. If we get that information, we could then have a much better understanding of what the market size is — and what technology is most suitable for a given use case and geography.
There are close to 2,000 different rate structures in the United States, so the challenge is getting down to understanding how a particular technology works for a particular load shape with a particular rate structure in a particular geography.
What we are trying to do with the research we did is develop a heat map for the country to determine which jurisdictions, use cases and load profiles are most attractive today.