The term “market disruptor” is seemingly thrown around for every new technology with promise, but it will be quite prescient when it comes to energy storage and U.S. power markets.
New energy storage projects in the U.S. are making solar power competitive against existing coal and new natural gas generation, and could soon displace these power market incumbents. Meanwhile, projects in Australia and Germany show how energy storage can completely reshape power market economics and generate revenue in unexpected ways.
In part one of this series, we discussed the three ways energy storage can tap economic opportunities in U.S. organized power markets. Now in part two of the series, let’s explore how storage will disrupt power markets as more and more capacity comes online.
New projects in Colorado and Nevada embody “market disruption”
True market disruption happens when existing or incumbent technologies can only improve their performance or costs incrementally and industries focus on achieving those incremental improvements, while an entirely new technology enters the market with capabilities incumbents can’t dream of with exponentially falling costs incumbents can’t approach.
As energy storage continues getting cheaper, it will increasingly out-compete other resources and change the mix of resources that run the grid. Recent contracts for new solar-plus-storage projects signed by Xcel Energy in Colorado and NV Energy in Nevada will allow solar production to extend past sunset and into the evening peak demand period, making it competitive against existing fossil fuel resources and new natural gas.
In fact, energy storage can increasingly replace inefficient (and often dirty) peaker plants and gas plants maintained for reliability. This trend isn’t limited to utility-scale power plants – behind the meter (i.e., small-scale or residential) energy storage surged in Q2 2018, installing more capacity than front-of-meter storage for the first time.
Energy storage’s economic edge will accelerate in the future. Bloomberg New Energy Finance forecasts utility-scale battery system costs will fall from $700 per kilowatt-hour (KWh) in 2016 to less than $300/KWh in 2030, drawing $103 billion in investment, and doubling in market size six times by 2030.
Tesla’s Australian “Big Battery” shows how storage will upend the existing order
But energy storage won’t disrupt power markets simply because of its continued cost declines versus resources it could replace, but also because of its different deployment and dispatch characteristics. It won’t merely replace peaker plants or substation upgrades, it will modify how other resources operate and are considered. This will require a change in regulations at all scales for the power grid, as well as in power market rules.
Consider the Hornsdale Power Reserve in South Australia, otherwise known as the “Tesla Big Battery.” This 100 megawatt (MW)/129 megawatt-hour (MWh) project is the largest lithium-ion battery in the world. Through South Australian government grants and payments, it contributes to grid stability and ancillary services (also known as “FCAS”) while allowing the associated Hornsdale Wind Farm owners to arbitrate energy prices. A recent report from the Australian Energy Market Operator shows that in Q1 2018, the average arbitrage (price difference between charging and discharging) for this project was AUS $90.56/MWh.
This exemplifies “value staking” where the Hornsdale Power Reserve takes advantage of all three ways storage can earn revenue in organized markets with a hydrid compensation model under its single owner/operator (French company Neoen). Hornsdale is already impacting FCAS prices in Australia, with prices tumbling 57% in Q1 2018 from Q4 2017.
Because energy storage provides countless benefits at both the local and regional level, in ever-more overlapping combinations, it will create contentious debates and innumerable headaches for power market regulators in coming years. In 2014, observers were treated to a family feud, as Luminant (generation utility) and TXU (retail power provider) argued against battery storage being installed by Oncor (poles-and-wires utility) for competitive reasons. More recently, Luminant has argued against AEP building energy storage to relieve transmission bottlenecks to remote communities in southwest Texas because they are “tantamount to peak-shaving and will result in the distortion of competitive market signals.” In California, policy makers are struggling with how to adjust rate structures so behind-the-meter storage projects can meet the state’s emissions reduction goals tied to the subsidies they receive.
Meanwhile, batteries are being combined with more than transmission, wind, and solar projects. In Germany, a recently closed coal-fired power station is being used simultaneously as a grid-tied storage facility and “live replacement parts store” for third-generation electric vehicle battery packs by Mercedes-Benz Energy. German automotive supplier Bosch and utility EnBW have installed a storage battery at EnBW’s coal-fired Heilbronn plant to supply balancing power market when demand outstrips supply.
Today, inflexible coal plants often receive these type of “uplift” payments when they are committed by power markets to meet demand or for reliability reasons, but can only offer resources in much bigger chunks then economic dispatch would warrant. This puts billions of dollars at stake the eastern U.S., where power market operator PJM is considering dramatic changes in rules to pay higher prices to these inflexible plants. What if in the future, these plants might be required to install or sponsor a certain amount of energy storage capacity in order to set marginal power market prices?
Event today, hybrid combinations of storage and other resources are changing the game in subtle but important ways. Mark Ahlstrom of the Energy Systems Integration Group recently outlined how FERC’s Order 841 allows all kinds of resources to change the way they interact with wholesale power markets, their participation model, in a unforeseen and unpredictable ways. For example, the end-point of a point-to-point high-voltage DC transmission line could use a storage participation model to bid or offer into power markets. Some demand response resources are already combining with storage today “to harness the better qualities of each resource, and allow customers to tap a broader range of cost-reduction and revenue-generating capabilities.”
A recent projection from The Brattle Group underscores this point, forecasting that Order 841 could make energy storage projects profitable from 7 GW/20 GWh, with up to 50 GW of energy storage projects “participating in grid-level energy, ancillary service, and capacity markets.”
Power market disruption is the only guarantee
Eventually the hybrid storage model may become a universal template for all resources, creating additional revenue through improved flexibility. For example, a hybrid storage-natural gas plant could provide power reserves during a cold start – even if a gas plant was not running, reserve power can come from energy storage while the gas turbine fires up.
If fixed start times for some resources, which are constraints that are accepted facts of life today, could be eliminated by hybridizing with storage, then standard market design might start requiring or incentivizing such upgrades to reduce the mathematical complexity and improve the precision of the algorithms that dispatch power plants and set prices today.
As utility-scale batteries continue their relentless cost declines, it’s hard to completely imagine exactly what the future might hold but energy storage is guaranteed to disrupt power markets – meaning this sector warrants close attention from savvy investors.