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The grid’s shape-shifter: Why demand response is becoming an indispensable part of grid modernization

Demand response is having its existential moment — possibly the first of several — as traditional, more basic forms of peak load shifting and shaving, such as air conditioning and water heater cycling, evolve into more sophisticated, flexible, and dispatchable resources.

Demand response (DR) now covers a range of technology, program and project types, from smart thermostat programs, to managed charging of electric vehicles (EVs), to non-wires alternatives used to defer or replace expensive grid upgrades. A bit like storage, it can be seen as an ever-unfolding Swiss Army knife, complementing and supporting other distributed energy resources (DERs) — such as solar, storage and EVs — as we transition to an increasingly clean and modern grid.

But, that very diversity makes the scope and impact of the DR market difficult to measure, as the Smart Electric Power Alliance (SEPA) discovered when it first set out two years ago to gather hard data on utilities’ DR use and programs.

Our most recent Utility Demand Response Market Snapshot reported a DR potential — based on enrollment in different utility programs — of 18.3 gigawatts (GW). Actual dispatched capacity was a more modest 10.7 GW.

What untapped potential and challenges lie in that gap? Certainly, we know these figures — compiled from data submitted by 155 utilities — represent only part of a bigger and more complicated picture. Different utilities define and measure DR in different ways, and the utility market does not include all wholesale market or third-party DR programs, or some of the more cutting-edge, emerging applications.

The unknowns and questions keep multiplying. What happens when energy storage can respond to a utility’s call for a DR event? Or when customers are asked to actually increase their consumption in response to grid conditions such as solar overproduction?

The challenge here is that lines are beginning to blur between DR and DERs, DR and integrated demand management planning, and DR and dynamic or time-varying rate designs.
Similarly, residential DR programs — particularly, smart thermostat programs — are converging with other smart home technologies, which in turn are driving new trends toward aggregation of resources, and greater customer choice and engagement.

How do we quantify a resource that is constantly evolving and appears to shape-shift with every new application? A few examples from the Demand Response Snapshot show how utilities and third parties are pushing the boundaries of traditional DR while reflecting the difficulties of sizing and describing the market.

Expanding DR potential at the grid edge

The most dramatic demonstration of DR’s potential to engage customers and aggregate energy resources came during the total solar eclipse of Aug. 21, 2017. Grid operators feared the path of the eclipse — and resulting drop in solar output across the country — might result in a cumulative loss of 9 GW of power for the affected utilities. Recruiting hundreds of thousands of customers across the country, Nest leveraged its popular smart thermostats to cycle down air conditioning in sync with the eclipse, saving 700 megawatts (MW) of energy.

As we venture further into the age of the internet of things, DR applications are increasing and implementation costs are continuing to decline. Smart thermostats and other smart home devices are lowering the costs and technical barriers for customers who want to be more aware of their energy usage and engaged with their utilities.

The SMB market: Connected thermostats — with multiple installations linked via the cloud — are now making it possible for small and medium-sized business (SMB) customers to avoid the expensive energy management systems they previously needed to participate in DR programs. In addition, these connected systems can also help these small businesses see substantial energy efficiency (EE) savings.

Whole homes and buildings: Smart thermostats are increasingly being bundled with customized packages of other non-energy “smart home” and “smart building” products and services, including grid -connected water heaters, EV charging stations, and smart plugs. For commercial buildings, thermostats can be connected to other critical services, such as weather feeds and building management services.

DR and the duck

Rapid adoption of renewables and the overgeneration of solar in California, Arizona and Hawaii have opened opportunities for new DR capabilities. In Arizona, for example, excess solar generation is sending midday energy prices into the negatives.

Which is where time-of-use (TOU) or time-varying rates come in, providing a model of how price signals can be used to shape and shift load, as is occurring in some DR programs. About 14 percent of all U.S. utilities offer residential TOU rates, most of which have peak and off-peak pricing with a ratio of slightly greater than 2:1.

Historically, voluntary enrollment in these rates has been less than 5 percent. However, solar adoption is causing some utilities to rethink the design of residential TOU rates to manage the “duck curve,” that is, the mid-day drop in demand and steep, early evening ramp that high levels of solar can cause.

The solution: TOU peak-period prices are being shifted to later in the evening, or off-peak pricing is being reduced in the middle of the day.

California’s three investor-owned utilities will start transitioning residential customers to default TOU rates over the next two years. Driven, in part, by the state’s high level of solar adoption, the rates incorporate a delayed, five-hour peak period from 4 p.m. to 9 p.m., instead of the previous peak period, which started from 11 a.m. All three utilities have been conducting pilots and customer outreach in preparation for the default TOU rollout, and they are examining different DR technologies to help address customer concerns about higher utility bills.

DR and EVs

Electric vehicles could soon become as ubiquitous as smart thermostats and play an equally significant role in resource aggregation and customer engagement. Some analysts have predicted that by 2030 EVs could be guzzling up to 100 terawatt-hours of power a year. That load, should it materialize, will need substantial managing to avoid huge peaks or drops on distribution systems, for example, if several EVs in a neighborhood all charge or stop charging at the same time.

The leading edge here is managed charging, in which a utility or third party can control when and to what extent customers charge their vehicles, to shift or shape load on a distribution system.

San Diego Gas & Electric’s (SDG&E) Power Your Drive program provides customers in apartments, condominiums and workplaces with access to charging stations with an EV rate structure that reflects the hourly cost of electricity. Dynamic hourly pricing is set the day before, and customers use a phone app to enter their preferences for a maximum energy price or amount of hours to charge. SDG&E’s dynamic rate for EVs will vary to reflect the market price of producing electricity, making it cheapest to charge when renewable resources like wind and solar are plentiful.

Maui Electric also offers residential customers a discounted EV-TOU rate from 9 a.m. to 5 p.m. when solar and other renewables are readily available. The utility’s JUMPSmartMaui pilot with Hitachi and Nissan Leaf is even more innovative. Volunteer Leaf owners were provided with EV Power Conditioning Systems in their homes. This Hitachi technology charges the vehicles during off-peak periods and discharges power to the volunteers’ homes. The system allows the utility to leverage EV charging to balance generation and power demand.

Locational DR

Non-wires alternatives (NWAs) are projects that use distributed technologies to defer or replace costly utility investments in either new generation or grid upgrades. These projects typically include a number of DERs, and increasingly, demand response is a key part of system design.

SEPA’s DR research found that 50 percent of the utilities surveyed are interested in leveraging DR for NWAs, with 20 percent planning to implement such projects and 5 percent indicating they have already implemented locational forms of DR — that is, targeting DR projects to provide support to specific locations on the grid.

Central Hudson Gas & Electric: Central Hudson is coordinating a DR program — called Peak Perks — as part of a transmission and distribution planning effort designed to offset peak load growth in three distinct areas of its service territory. For residential customers, the program includes direct load control equipment using Wi-Fi thermostats with two-way communications. Commercial customers get load control switches, and customized curtailment agreements. The utility set its first year target at 5.3 MW, but achieved 5.9 MW.

Consumers Energy, Swartz Creek project: This pilot kicked off in 2017 at the request of the Natural Resources Defense Council (NRDC) to explore opportunities for using residential and commercial energy efficiency, and residential DR to avoid or defer distribution system investments and provide cost savings to customers. Still in progress, the project’s goal is to reduce peak load by 1.4 MW by the end of 2018, or 1.6 MW by the end of 2019.

These and other projects where DR and DERs converge reflect yet another, critical opportunity. Our industry has traditionally had a disconnect between customers, who may buy a smart thermostat to save money on their electric bills, and the impacts that aggregated DR can deliver to the grid and, coming full circle, back to consumers. But, the ongoing evolution of DR and its integration with other technologies could help utilities to increasingly engage customers as informed and active participants in grid efficiency, resilience and transformation.

The 2018 Utility Demand Response Market Snapshot was produced by SEPA in partnership with Navigant and PLMA (Peak Load Management Alliance). It is one of three reports in SEPA’s Utility Market Snapshot series available for free download here.

Brenda Chew will be providing further insights and data from the Demand Response Snapshot at PLMA’s annual conference, Nov. 12 in Austin.

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