Understanding the Three Major Demand Flexibility Paradigms in the United States

Our power system is undergoing a major shift away from the traditional centralized electricity generation model, towards a more dynamic, decentralized energy landscape capable of bidirectional power flow. As more homes and businesses adopt distributed energy resources (DERs), there are more opportunities to leverage these demand-side resources to support the grid. 

There are currently three major paradigms used to coordinate the flexibility of DERs as grid resources: time-of-use rate plans, utility grid services programs and wholesale electricity markets. For the owners and operators of demand-side resources, understanding the evolution of the demand flexibility landscape and how these different paradigms interact is key to maximizing each asset’s value to the grid. 

The evolution of utility programs

Historically, utilities have taken the lead on demand-side load shaping efforts. Utilities introduced the first demand response (DR) programs in the 1970s when they started calling their large commercial and industrial customers during spikes in electricity demand to ask them to reduce their usage in exchange for discounted electricity pricing. In the 1980s, these programs were formalized with pricing agreements and participation requirements. In the early 2000s, we saw the first hints of semi-automation beyond a grid operator calling a customer to turn down usages. Since then, utilities across the country have developed multiple large demand response programs, usually focused on providing emergency support to prevent blackouts during a grid crisis. Read more on the history of DR.

Today, utilities are increasingly tapping into the potential of their customers’ DERs to shore up resource adequacy and improve grid reliability through their demand response and other grid services programs. Utilities have been leaders on testing smart thermostat DR programs, and more recently, piloting programs with residential batteries and electric vehicles (EVs).

Leap participates in utility DR programs across the country and often can stack them with additional wholesale market programs to maximize grid services revenues.

The introduction of wholesale grid services

Following the emergence of wholesale electricity markets, in recent years the country’s seven regional transmission organizations (RTOs) and independent system operators (ISOs) have also begun to allow flexible demand-side resources to act as a competitive resource that could bid into markets similarly to supply-side resources.

The landmark FERC Order No. 2222 will unlock demand-side potential by requiring ISOs and RTOs to enable aggregations of DERs to participate on a level playing field in wholesale energy markets. As a result, more homes and businesses will be able to offer flexibility to the grid and capture greater value from their energy assets. With this regulatory change, wholesale markets are increasingly well-positioned to shape electricity demand curves outside of the control of the utility.

In December 2022, FERC reported that DR totals in wholesale markets had increased by 1.8 GW to 32.4 GW from 2020 to 2021, representing a 6% annual increase. This is larger than the peak demand of all of New England.

Time-of-use (TOU) pricing

The rapid growth of smart meters across the U.S. has opened up a lot of new potential for demand flexibility. Today, according to FERC’s 2022 assessment, nearly 65% of customers have smart meters. With smart meters, electricity consumption can be tracked at a more granular timescale throughout the day. 

Many utilities are taking advantage of this by moving towards more dynamic rate structures that encourage customers to shift their energy usage away from peak periods by charging them more when the cost of generating electricity is high. Time-of-use (TOU) rates adjust the rate customers pay for electricity over the course of the day, splitting the day into discrete peak and off-peak periods. Many rates for residential customers are set in advance and easy to understand, providing a straightforward economic incentive for customers to adjust their energy consumption patterns.

Some TOU rates for commercial and industrial customers incorporated demand charges for system-wide demand peaks or peaks at the site. These provide more complex tariff structures and can be a key mechanism for large customers to shift load during peak periods.

Navigating geographic complexity

With the diversity of programs, tariffs and the regional balkanization of the grid, how these paradigms for DER coordination interact will vary by geography. In New York for example, Leap works with residential and commercial customers to stack revenue in utility and wholesale programs. While in California, Leap coordinates residential batteries that incorporate incentives from TOU rates and wholesale programs that cannot be readily stacked with utility DR programs. In Texas, Leap integrates the Emergency Response Service (ERS) program with a real-time energy product with NRG. These are a few of the many examples of how Leap integrates values across these different paradigms today.

Next time: We’ll leverage data from the U.S. Energy Information Administration (EIA) and Leap’s market expertise to look at how technology providers can maximize their participation across the paradigms in different regions.