This article is the fourth in a series titled “Real Talk on Reliability,” which will examine the reliability needs of our grid as we move toward 100% clean electricity and electrify more end-uses on the path to a climate stable future. It was written by Sara Baldwin, the senior director for electrification at Energy Innovation.
Georgia Power’s 2023 updated integrated resource plan warned state regulators that dramatic near-term load growth from data centers required “immediate action” to meet capacity needs by the end of 2025. The utility proposed new natural gas power plants, fossil fuel power purchase agreements and a modest residential demand response program.
But one of Georgia’s largest energy users, Microsoft, with three existing data centers in the state and several more planned, contested Georgia Power’s claim, raising concerns the utility over-forecasted near-term load to procure excessive, carbon-intensive generation.
This tension is playing out nationwide: Electricity demand is increasing after more than two decades of nearly flat load growth and utilities are revising prior forecasts, predicting a doubling or more over the next decade. Rapid growth is causing panic over capacity and infrastructure shortfalls, prompting calls to delay planned coal plant retirements or build new natural gas.
But these fossil intensive supply-side solutions are expensive and slow to build. They’re also incompatible with utility net zero emissions commitments. Supply-side solutions can meet growing demand, but utilities committed to delivering reliable, affordable and resilient clean energy are skipping over proven demand-side solutions to manage near-term load growth while meeting these objectives.
As demand growth fuels a crisis of confidence, utilities and grid operators should prioritize least-cost, least-risk demand-side solutions to deliver valuable grid services. Similarly, policymakers and regulators should adopt policies to encourage their widespread adoption and overcome misaligned incentives.
Five smart approaches can help utilities and their regulators get serious about demand-side solutions to the load growth challenge.
A rapidly shifting load landscape
Utilities and grid operators face load growth from new data centers, revitalized manufacturing, electrification and cryptocurrency mining. Not all demand sources are created equally. Data centers and cryptocurrency mining are large loads requiring huge amounts of energy nearly instantaneously. Others like transportation electrification have longer lead times and steadier growth, making them easier to forecast and plan for. Some are more elastic and capable of quickly scaling back or shuttering operations in response to changing electricity prices, whereas others may be more inflexible.
The Brattle Group reports data centers alone represented 19 GW of U.S. electricity peak demand in 2023 —nearly double New York City’s 2022 peak load of 10 GW. The Electric Power Research Institute forecasts data centers could consume up to 9% of U.S. electricity generation by 2030. Goldman Sachs estimates they will need 47 GW of new capacity and $50 billion in cumulative investment through 2030.
Meanwhile, climate-driven extreme weather is shifting grid planning paradigms. “Everyone is clutching their pearls over data centers and crypto, but every time we have a polar vortex or a heat wave, similar load increases materialize to serve human needs like heating and cooling, but in a much shorter time span,” says electric reliability expert Alison Silverstein. “We cannot assume demand is immutable. With climate change-driven weather shifts, demand has become less predictable and at times terrifying.”
Demand-side solutions are poised to perform
Demand-side solutions encompass a wide range of technologies and applications with “potential to moderate the growth of both electricity consumption and peak load,” according to the Brattle Group.
Demand-side management, demand response and energy efficiency programs can help consumers reduce and modulate electricity consumption in response to economic or reliability signals in exchange for economic benefits. A 2019 Brattle Group study indicates the U.S. has 200 GW of cost-effective DR potential by 2030, more than triple existing capability, worth more than $15 billion annually in avoided system costs.
DR programs are ascendant, especially in areas facing extreme weather conditions. Following Winter Storm Uri in 2021, Texas utility CPS Energy launched a new smart thermostat program enabling it to modify demand using during high energy use. Similarly, Arizona utilities tapped more than 100,000 customers during a 2023 summer heat wave to provide 276 MW of electricity — equivalent to half the capacity of an average-sized combined cycle natural gas plant.
Well-designed DR programs benefit participating customers. Westchester County, New York, has received around $1.5 million to date from NuEnergen for the county’s enrollment in summer DR programs. Ameren Missouri and Enel X incentivize businesses for participating in programs “to maintain a reliable and cost-effective electric grid … in response to periods of peak demand on the grid.”
Energy efficiency programs can also help to manage demand. Replacing inefficient resistance heating and air conditioners with highly efficient heat pumps or building envelope sealing delivers benefits including better resource adequacy, lower wholesale prices and customer bills, fewer grid infrastructure requirements and reduced air pollution.
Given the time and money required to build new generation and transmission, Silverstein argues “we can’t build our way out of this. Now is the time to activate more energy efficiency and demand-side solutions, which are cheaper and faster to deploy, and can also buy us time to make prudent supply-side resource adjustments.”
Shifting from solely supply-centric to increasingly demand-centered
We’ve only scratched the surface on demand-side programs. Today’s DR programs total just 60 GW of capacity — about 7% of national peak-coincident demand. Some states have less than 1% of peak being met with demand-side solutions.
The grid is designed to ramp supply-side resources to meet shifting demand, not the other way around. Demand side solutions face challenges in their ability to scale, and many utilities and grid operators face institutional barriers to tapping the full potential of demand side solutions.
Investor-owned utilities earn returns on capital expenditures and forgo shareholder profits when they rely on decentralized resources that avoid those investments. Bulk system planning and distribution planning are siloed and lack coordination. Wholesale market rules favor supply-side solutions for grid needs. Regional transmission operators lack distribution system visibility, preventing forecasting and planning for demand side resources at scale. Customers must be willing and able to participate, which hinges on trust and economic incentives.
Five approaches can overcome these challenges
First, improve utility and grid operator visibility of demand-side resources through options including:
- Adopting Distributed Energy Resource Management Systems, or smart building management systems, utilizing more sophisticated models and control devices;
- Allowing third-party aggregators;
- Developing distribution system plans; and
- Creating publicly available distribution system capacity maps.
States requiring utility IRPs can require detailed distribution system plans and establish frameworks to ensure both reflect the other. Developing granular load forecasts can inform demand-side programs providing energy savings, alongside reliability and other benefits.
Second, enable data sharing across the transmission and distribution systems. The North American Electric Reliability Corporation issued data-sharing recommendations in 2017 to support better DER integration into bulk power system planning and operations. NERC called for substation-level data with aggregated DER data, transformer ratings, relevant energy characteristics, power factor and/or reactive and real power control functionality. Shared models should communicate with one another and utilize data in the same way. Ensuring privacy and security protections requires agreements among all participating parties as to what gets shared, in what format, and who gets access.
Third, center energy customers in program and rate design. According to Silverstein, the full potential of demand-side solutions requires “respectful, negotiated limits with customers, who should be treated as partners and compensated fairly — their economic incentives should be commensurate with any perceived or actual sacrifice and with the value they deliver to the electric system.” Programs should be designed to scale participation and optimize benefits for the grid and all customers.
Fourth, adopt utility performance incentive mechanisms that put demand-side resources on a level playing field with supply-side resources. PIMs help shift profit-motives by aligning profits with performance on certain metrics, like successful DR or energy efficiency programs.
And fifth, consider new approaches to attract flexible and grid-supportive loads. Rates and tariffs compelling customers to respond to grid conditions could obviate more expensive alternatives down the line. Revising cost allocation approaches for large new loads can mitigate their impacts and cover upfront infrastructure costs. In an era in which multiple new loads compete for the same space on the grid, utilities should reward those willing to go the extra mile in being good grid citizens.
As electricity demand grows, so too should the role of cost-effective demand-side solutions. Doubling down on them in the near-term will unlock their full potential over the long-term, benefiting consumers, the grid, and the climate.
