Energy storage deployment in 2023 set a record globally and more than doubled in the U.S., according to Bloomberg NEF’s Energy Storage Market Outlook. The report credited the rapid growth in energy storage to government targets and incentives, as well as the growing need to shift energy from the time of generation to times of peak demand. In addition to improving overall grid reliability, using energy storage to “shave” peak demand can also help insulate utilities from volatility in the pricing of electricity in wholesale markets.
Wholesale electricity prices in the U.S. were highly volatile in 2022 and likely contributed to the surge in energy storage deployments in 2023. The U.S. Energy Information Administration (EIA) said extreme weather events and increased fossil fuel costs drove wholesale electricity prices higher across all U.S. markets in 2022, and even though prices went back down in 2023, short term spikes remained a threat. The most severe example took place in the Electric Reliability Council of Texas (ERCOT), where persistent heat drove record summer demand and peak pricing exceeded $4,000 per megawatt hour (MWh).
Distribution utilities that buy electricity from wholesale markets typically protect themselves from short-term spikes in wholesale pricing by hedging—contracting in advance for electricity at lower, fixed rates, based on their forecasted needs. But demand is growing more difficult to predict with the increasing severity of weather events, the proliferation of distributed energy resources (DERs) and the unpredictability of electric vehicle (EV) charging. Utilities can use energy storage as an additional source of risk-mitigation, building up capacity to buffer against unexpected demand and the need to buy extra electricity at exorbitant prices on the spot market. Energy storage has been called the “Swiss Army knife” of solutions for today’s electric grid; increasingly, utilities are partnering with a developer to take the hassle out of financing, designing, owning, and operating an energy storage or solar-plus-storage system.
Shaving Market-Sized Peaks
Public utilities that are incorrectly hedged can cost ratepayers or members millions of dollars during a short span of market volatility. Retailers and investor-owned utilities (IOUs) have their own reasons—competition and regulators—for not wanting to pass along higher electricity costs to their ratepayers. But it’s not just short-term cost volatility that investments in power storage can help address.
The aggregation of power storage in a market reduces the need for fossil fuel peaker plants. These power plants, most of which burn natural gas, are expensive to fire up and run. But utility-scale energy storage capacity (battery storage) in the U.S. is expected to nearly double in 2024 to 30 GW and continue a steep climb through the end of the decade, when total power storage capacity is expected to approach 400 gigawatt hours (GWh).
Such capacity will inevitably help reduce the need for peaker plants and help decouple wholesale electricity pricing from the influence of natural gas prices, and those of other fossil fuels. But until the generation mix shifts, electricity pricing will be tied to the geopolitical and supply forces controlling the natural gas market. The EIA describes the situation like this:
“Price changes for natural gas have an outsized influence on electricity prices because natural gas prices tend to set the marginal price of electricity during most hours in most regional markets. PJM, the largest power market, reported in its 2023 State of the Market Report for PJM covering January through September that natural gas set marginal prices 84.3% of the time in the real-time market during the first nine months of 2023.”
Ultimately, energy storage capacity on distribution networks can also help relieve some of the short-term pressure on transmission and interconnection projects as well.
Decoupling from Market Pressures
Despite changes in the generation mix, steadily increasing demand is likely to exert continued upward pressure on wholesale electricity prices. The switch to electric heating in many parts of the U.S., the adoption of EVs, the reshoring of manufacturing and power-hungry data centers are a few of the major divers, and grid planners across the U.S. expect an increase of 38 GW of peak demand by 2028.
Distribution utilities that want to insulate themselves even further from increases in wholesale electricity pricing are combining energy storage with solar generation. The economics of solar-plus-storage are well-known for the behind-the-meter applications of commercial and industrial (C&I) electricity customers. The presence of demand charges or time-of-use rates are typically responsible for generating a good return on investment (ROI) for these systems.
Cooperative utilities face similar demand charges, and the dynamics are similar for any utility that is exposed to higher peak pricing on wholesale markets. In addition, thanks to the Inflation Reduction Act (IRA), coops and munis can now, for the first time, access federal incentives for the purchase of solar-plus-storage systems.
However, investments in these systems are not without risk and requires expertise and due diligence. The ideal battery energy storage system configuration (with or without solar PV) is important to maximizing the ROI, and the system must be managed with eyes on the electricity market and the grid. Having the right operating platform and intelligence is key to maximizing system profitability and performance.
Utilities that don’t have the expertise or the bandwidth to finance, design, own, and operate an energy storage or solar-plus-storage system in house can partner with a provider who will help at each step of the way. Many utilities, particularly coops and munis, have chosen to partner with a developer rather than self-finance, own, and operate.
