It is counterintuitive that, in the effort to reduce greenhouse gas emissions, we’re going to need to use a lot more electricity in our homes. We need to move many of the activities we now use fossil fuels for—driving, heating and cooling, cooking and heating our water—to renewably sourced electricity to meet emission-reduction targets. At the same time, many components of our transmission and distribution grids are decades old. Modernizing this support structure to meet increased demand is a critical requirement for progress in the fight to slow or reverse the rate of climate change.

But what, exactly, would a modernized grid look like? To a casual observer, maybe not much different than the poles and wires that have been part of the American landscape for more than a century— though perhaps more of those wires might be underground. Instead, the changes will be taking place within the transformers, substations and control rooms responsible for ensuring electricity arrives at its final destination safely and in sufficient quantities. These upgraded networks will also be tasked with the new challenge of enabling power to flow two ways, as millions more households begin adding electricity from their on-site solar panels and storage batteries back to the grid.

Environmental advocates say electrifying homes is critical to keeping global temperatures from rising more than 2.7°F (1.5°C) to 3.6°F (2°C). According to the electrification advocacy group Rewiring America, today’s furnaces, water heaters, dryers and stoves account for at least 95% of U.S. residential building emissions. So, switching those loads to electricity (or, in the case of electric resistance-based heating equipment, away from that technology and over to electric heat pumps) is essential to meeting climate change goals.

However, it’s not just existing home equipment that utilities will need to support in a greener future. We don’t think of cars as a home appliance today, but that will change over the next decade as electric vehicles (EVs) and their charging equipment start showing up in more garages and driveways across the country. Edison Electric Institute, the investor-owned electric utility trade group, estimates EVs will comprise more than 20% of annual vehicle sales—or more than 2.5 million vehicles—by 2030.

According to the U.S. Department of Energy’s FuelEconomy.gov, EVs use between 25 kilowatt-hours (kWh) and 40 kWh to travel 100 miles, so if you drive the U.S. average of 1,376 miles per month, that means an extra 280–550 kWh in monthly electricity use, much of it using home charging equipment. With the U.S. Energy Information Administration estimating the average household uses 893 kWh per month, this means demand could rise by 30% to 60%. That’s a lot of extra electricity for neighborhood transformers to support.

Bulk power needs

Experts say grid modernization needs to begin with the wholesale transmission system. Though these lines are already designed for bidirectional power flow, Daniel Brooks, vice president of integrated grid and energy systems for the Palo Alto, Calif.-based Electric Power Research Institute, says other necessary capabilities are currently lacking. These include:

• Synchrophasors to monitor real-time conditions (along with the ability to analyze resulting data in real time)
• Power-flow controllers to enable more efficient line use
• Topology control to open and close switches based on optimization software
• Greater integration of high-voltage DC systems to lower line losses over long distances

In addition to boosting the capabilities of lines that are already in place, we simply need to build more transmission to improve access to remote solar and wind farms and improve flexibility and resilience. For example, the country now is divided into three major transmission regions: the Eastern Interconnection that ranges from the Great Plains to the Atlantic coast, the Western Interconnection that stretches to the West Coast, and Texas. Brooks says we need more ways to ship power between these areas.

“You’re going to see development of interregional transmission, in order to provide either lower-cost or lower-emission power from regions that have it,” he said, citing the advantages of, for example, being able to move wind power from the Midwest to load centers in the Southeast or Southwest. This flexibility also could improve overall resiliency.

“As you get situations like what happened in the Southwest, where you had the extended cold snap, transmission is going to be needed to help manage some of those climate-based problems,” Brooks said.

Distribution upgrades

Flexibility continues to be a key goal when the discussion turns to modernization needs at the distribution level. While transmission systems might have been developed decades ago to enable bidirectional electricity flow, that’s not the case with local utility systems. Today, however, an increasing number of residential customers are turning their rooftops into power plants and adding battery-based storage systems that could provide important grid-support services.

“The distribution system has been designed as a radial system. You’re basically delivering in one direction to the end-user,” Brooks said. “As that distribution system becomes bidirectional, there’s a lot of capability needed,” including digitalized substations, advanced switching capabilities, microgrids and, of course, cybersecurity protection.

He also cited communication needs, including expanding existing supervisory control and data acquisition systems out onto utility feeder lines.

For Ryan Katofsky, a managing director with the national clean energy business group Advanced Energy Economy (AEE), Washington, D.C., building this flexibility begins with smart meters capable of two-way communications in near real-time.

“You’re talking about collecting much more granular information and connecting that back to the utility,” he said. “A lot of customers have these meters, but we aren’t getting all we can out of them yet.”

That individual-customer data will become more important as customer adoption of solar and storage—often called distributed energy resources (DERs)—grows. While this equipment might belong to those customers, utilities see an increasing need to monitor how the power it generates flows onto their grids. Advanced distribution management systems and DER management systems are combinations of sensors and software. They can become grid managers’ eyes and ears on how systems are operating and enable aggregation of DERs to work as virtual power plants to provide voltage management and optimize power flow.

Beyond new controls and sensors, utilities also need back­-office upgrades to help them deal with all the data coming in from meters and grid management systems.

“You’re not sipping, you’re guzzling information, so you need the ability to integrate it and act on it,” Katofsky said.

Additionally, AEE advocates allowing customers to access their own smart meter’s data, either for their own use or to enable outside vendors to provide services such as managing when a battery system is serving a home’s demand or providing power to the utility.

“They want to have access to that data that’s going back to the utility,” Katofsky said. In many cases, this ability is already available thanks to the nationwide Green Button initiative, which also has been adopted by some natural gas and water utilities. “It essentially authorizes a customer to allow a third party to have access to that data.”

Bringing it home

Historically, electric utilities have seen their distribution networks ending at the customer’s meter, with all household equipment being the property owner’s responsibility to manage. That viewpoint is beginning to change, though, as grid managers see the need to match new variable-supply sources with equally dynamic load-management capabilities.

“Those behind-the-meter resources, aggregated together, are a big part of what we’ve got to modernize,” Brooks said. “They’re definitely going to be grid participants and a big part of how we plan and operate going forward.”

And, to Katofsky, this change in approach will also mean a change in mindset for utilities and the regional transmission operators and independent system operators who oversee transmission systems at the bulk power level.

“We should be thinking about utility customers differently,” he said, noting previous concepts of residential customers as inflexible in their demand patterns. “That demand is becoming more flexible, even with something like electric water heaters, which have vast potential as a controllable load.”

With a modernized grid, connectivity is much more sophisticated than was the case with the residential demand-side management programs many utilities offered in the 1980s and 1990s. Water heaters also were a target for demand reduction in those efforts, which often involved separating the heaters onto their own meter that the utility could control remotely. Today, this equipment often can be directly connected to the internet through a home’s Wi-Fi network for incremental adjustments, such as moving back temperature set points a few degrees rather than turning the unit off entirely. And with advanced forecasting capabilities, utilities can connect with a home’s smart thermostat to pre-cool the house during energy-rich sunny days so temperatures can be set back during early-evening peak­-demand periods.

In the future, utilities might even be able to tap into the power stored in our cars. To address the concerns regarding EV charging’s impact on the grid, charging equipment makers are already building in the ability for utilities to slow charging down so it’s spread out through overnight hours. Vehicles will still be topped off by the morning, but without stressing neighborhood transformers and other equipment. In the future, we could be paid to allow those batteries to be a resource when local electricity supplies are stressed.

This gets to one more critical requirement for a modernized grid—ensuring there are appropriate rates, incentives and other programs needed to move electricity suppliers and customers in the right direction.

“A lot will depend on getting the policies and regulations right,” Katofsky said, addressing the need to make sure that the way this market works lines up with what we need it to do. “It’s making sure utilities’ financial interests are aligned with the outcomes we want.” //