Energy storage now upending assumptions on California, and to some degree, Texas grids. California is on some kind of a tear – with Wind/Water/Solar energy regularly producing more than 100 percent of grid demands, even as temperatures rise and ACs are ramping up.
We seem to be witnessing some kind of a phase-change in how variable renewables and storage interact, creating something new.
Other states across the Heartland soon to follow.
DTE Energy announced Monday it will build a battery energy storage facility at the recently retired Trenton Channel coal plant.
DTE Energy CEO and Chairman Jerry Norcia said this is the largest coal plant to energy storage conversion project in the Great Lakes Region.
“And that means it will be one of the largest battery arrays in the Midwest,” Norcia said. “That’s a first for us just like this plant was a first of its region at that time.”
The facility is expected to be completed in 2026.
The center will have the capacity to store up to 220 megawatts of electricity, enough to power up to 40,000 homes. It will store electricity during times of excess generation and will distribute the power during times of high demand.
DTE has received $140 million in tax incentives from the 2022 federal Inflation Reduction Act. Norcia said that money will be passed back to customers.
“If you look at our prior plan, before the Inflation Reduction Act, it was a billion dollars more expensive four our customers than it is today,” Norcia said. “The Inflation Reduction Act basically provides tax incentives that we can pass on to our customers in the form of lower bills.”
The project is part of DTE’s CleanVision Intergrated Resource Plan. It will also help Michigan’s statewide energy storage target to have 60% renewable energy by 2030 and 100% clean energy by 2040.
“Michigan is the first state in the Midwest to establish an energy storage standard, which is now the third most ambition in the nation,” said Michigan Gov. Gretchen Whitmer. “DTE’s new center here in Trenton will help us meet 10% of the statewide storage goal all by itself.”
“The future is already here — it’s just not very evenly distributed.” That observation, from the great science fiction writer William Gibson, often provides a useful framework for thinking about technological change. It certainly seems to be relevant to the fast-evolving US power grid today.
Lithium-ion batteries have long been seen as a key technology for maintaining the stability of electricity grids increasingly reliant on solar and wind power. But until recently, this use case was talked about more as a future prospect than an immediate reality.
This year, however, grid-connected batteries in parts of the US, particularly California and Texas, have started to play a significant role in helping to balance the system, shifting load away from the times of day when the net load is heaviest to times when it is lighter.
In much of the US, batteries are not yet performing that crucial load-shifting role. But California and Texas are pointing the way to the future for other US power markets, and other countries around the world. As the share of variable renewable generation in electricity supply grows, the value of battery storage rises.
California is where the contribution made by battery storage systems is greatest. On the CAISO grid, which serves most of California, output from battery storage last week hit a new record high of 7.5 gigawatts for a few minutes around 7.40pm on May 16. That is actually higher than the record output from wind on CAISO, which hit a peak of 6.4 GW two years ago.
California’s stationary storage capacity has soared in recent years, rising 20-fold from 500 megawatts in 2018 to more than 10.3 GW today, with a further 3.8 GW planned to come online by the end of 2024, according to the state’s energy commission.
The build-out of solar power, which is most productive around the middle of the day and in the early afternoon, has created California’s notorious “duck curve”, with net load lowest during those hours and highest after sunset. Net load on CAISO is often negative, and earlier this month, it hit a new record low of minus 5.3 GW, at around 1.20pm Pacific time on the afternoon of 5 May.
In those circumstances, it makes excellent sense to charge batteries during periods of oversupply and discharge them in the evenings. At those times of peak excess supply, wholesale power prices are often negative.
Business models for stationary storage have typically been based on the provision of ancillary services such as frequency regulation, responding quickly to fluctuating conditions to keep the grid stable, rather than shifting load through the day. Now that is changing.
“In CAISO, we’ve definitely moved from storage being primarily justified for grid services to energy arbitrage: net-load smoothing,” says Chris DaCosta, Wood Mackenzie’s research manager for CAISO and the Western grid region.
A similar shift is emerging in Texas. As in California, output from battery storage on the ERCOT grid in Texas reached a new record this month, discharging about 3.2 GW at around 8pm Central time on May 8. Like California, Texas has been adding new stationary storage capacity at an accelerating pace. In 2022, about 1.17 GW of battery output capacity was installed in Texas. In 2023, it was about 2.66 GW, and this year we expect it to rise again to 3.56 GW.
Storage is the second-largest technology in the queue for interconnection to the grid in Texas, at 37% of the total as of the end of last year, only slightly behind solar. Gas-peaking capacity made up just 1% of the queue, and combined-cycle gas-fired plants just 3%.
Robert Whaley, Wood Mackenzie’s director for North American power, wrote in a note last year: “Storage provides unique characteristics that gas capacity cannot duplicate in the face of a growing duck curve in the [Texas] system.”
Combined-cycle gas-fired plants cannot be held in reserve to run only in the evenings, and peaking plants may not be able to turn on quickly enough if wind output drops suddenly.
In much of the rest of the US, the economics to support load shifting don’t yet line up the way they do in California and Texas. But as other grids become more dependent on solar and wind, that will change.
Batteries are still expensive and compete for basic minerals like copper. The recent UM study shows there’s not enough copper being mined for just an EV transition. Grid transformers have a 5 year wait. Don’t forget that batteries have to be charged. I would guess that some of that charging is done with gas. That actually makes sense where you’d want batteries’ fast ramping power ready and to take stress off peaker generators.
Does the word “Duh!” mean anything to you? Over time every EV battery gets greener as the grid gets greener. In 2014 charging my Leaf had a much higher carbon footprint than it does in 2024 as Texas has added more and more wind/solar/storage to the grid.
Combustion vehicles still rely on a dirty supply chain for the fuel they put in their tanks, and most of that energy is wasted on engine heat anyway. My Leaf doesn’t use energy when at a stoplight and even recovers some energy on the downhill.
As for grid-scale batteries, they charge when the energy on the grid is cheaper, like all of that excess generation by wind and solar. They then discharge when energy is high priced, displacing more gas/peaker power.