Grid edge
Gov funding

The power sector at a crossroads: A tale of two utilities

It’s time for electricity providers to choose virtual power plants.

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Two people works on a solar panel project on the roof of a home.

Photo credit: Joe Raedle / Getty Images

Two people works on a solar panel project on the roof of a home.

Photo credit: Joe Raedle / Getty Images

After 20 years of flat electricity sales, electricity demand is rising. With the passage of President Biden’s Inflation Reduction Act, 200 new clean energy manufacturing facilities have been announced and the market has seen a significant uptick in sales of electric vehicles and heat pumps.

While electricity demand rises and old power plants reach end of life, utilities are learning what growth looks like again. Utility companies have a strong preference for conventional approaches for managing a centralized grid, but higher rates and a need for speed are encouraging companies to look at lower cost approaches like virtual power plants. These approaches can reduce the peak demand on the system and use existing infrastructure more efficiently. 

Virtual power plants, or VPPs, are utility-scale, utility-grade aggregations of distributed energy resources, such as rooftop solar and storage, smart appliances, and flexible commercial and industrial loads that deliver grid services. Fundamentally, VPPs can help balance supply and demand of electricity with a level of dexterity that traditionally was only used to flex supply.

While it may be tempting for utilities and other electricity providers to default to the status quo of deploying only centralized grid assets, doing so in this period of transition puts the reliability of the grid at risk and could result in unnecessary rate increases at a time when one in six Americans are behind on their energy bills

The fastest, least-cost path to a higher capacity, more efficient, and cleaner grid will require integrating distributed assets like VPPs that can be deployed quickly, while centralized assets like nuclear and geothermal are constructed and interconnected to the grid over time.

Let’s illustrate this choice with two fictional utilities taking two realistic paths. On both paths, utilities face rising peak demand for the first time in a decade as we electrify heat, industrial processes, and — critically — transportation. Nationally, we’re expecting peak demand to rise by nearly 10% within this decade. At the same time, old coal-fired power plants are reaching the end of their lives. To offset retirements and equip the grid for demand growth, both utilities must add a massive amount of new electricity resources to the grid.

The first utility develops a conventional plan to rely on peaker plants for the hours or days that stress the grid. Natural gas-powered peaker plants typically operate less than 10% of the time in any given year — only during spikes in demand. These peakers emit air pollutants and greenhouse gases, and they are disproportionately located in lower-income communities.

To transport the power in record-setting quantities, this utility and its partners upgrade the transmission lines, substations, distribution lines, and feeders to handle higher loads. The costs of this equipment and construction are charged to American ratepayers in their electricity rates -– with a 5% to 9% margin baked in for the utility’s profit. All operating costs are passed down to customers at cost.

The second utility takes a more modern approach and implements a VPP. The VPP pays consumers and businesses for being flexible with connected devices they are already buying — like rescheduling EV charging to occur overnight, shifting water heating outside of peak hours, and integrating rooftop solar and distributed batteries into grid operations. 

In taking this path, the second utility smooths out peaks in demand and spends about 40% less than the first spent on peakers and grid upgrades. This utility returns those savings to its ratepayers. Of the money spent on the VPP, the large majority flows to the consumers who get paid to participate. Those incentives help offset the cost of devices such as EVs, smart water heaters, and solar-plus-storage systems.

To make sure all Americans benefit from VPPs, and that these systems deliver more benefits to those most in need, the utility or its financing partners help low-income or low-credit score customers pay for smart, connected home equipment with on-bill financing or pay-as-you-save programs with debt backstopped by the Loan Programs Office at the U.S. Department of Energy. The utility works with local electrician unions to install and maintain the new equipment, and with local nonprofits for community outreach and program design.

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Fast forward just five years. The second, more modern utility with the VPP has a continuously increasing pool of potential capacity as American consumers and businesses continue to adopt DERs. Each year between 2025 and 2030 — even in the absence of new interventions — Americans are expected to purchase 20 to 35 gigawatts of distributed generation, four to six GW of flexible demand from stationary loads, and seven to 24 gigawatt hours of stationary behind-the-meter storage. And that’s not to mention the additional 20 to 90 GW of nameplate EV charger capacity and 305 to 540 GWh of storage in EV batteries. 

Meanwhile, the first, more conventional utility struggles with larger and harder-to-predict swings in power demand and makes the difficult decision of using rolling blackouts during peaks because of supply shortfalls or grid bottlenecks. Perhaps due to permitting delays, transmission interconnection queues, or state policymakers who won’t tolerate continuous rate increases, the utility can’t add peaking capacity or upgrade its lines and equipment fast enough. Regional economic development suffers when companies can’t build their facilities, much less the accompanying workforce. And consumers are limited in the home and auto upgrades their utilities will allow.

This is not hyperbole; we are seeing glimpses of these outcomes today. 

California and Texas have narrowly avoided rolling blackouts with emergency calls for demand reduction — it’s no wonder they are among the five U.S. states where utilities have procured at least 10 VPPs, including projects from David Energy, Octopus Energy, Tesla, and more. In Vermont, Green Mountain Power built its own distributed storage VPP and has saved millions of dollars as a result, even when batteries are leased at a very low monthly cost to households as a substitute for generators. Rural electric coops from North Carolina to Minnesota have enrolled upwards of 20% of customers in load flexibility programs.

Shifting from the conventional to the modern approach requires changes in how utilities plan, manage, and measure grid performance. And it also requires changes in how utilities are compensated for grid performance. The utility revenue model is a major reason why VPPs and other grid-enhancing technologies that leverage existing assets are underutilized today. Under many conventional regulatory frameworks, utilities get paid for the investments they make, not the benefits they deliver. These are misaligned incentives that will require policy changes to fix. But utility regulators are modernizing, too.

It's time to modernize our grid, our utilities, and our electricity regulations for faster and wider adoption of VPPs on the path to clean energy abundance. Electrification can be a challenge or it can be an opportunity. It’s our choice to make. 

Jigar Shah is the director of the Department of Energy’s Loan Programs Office. The opinions represented in this contributed article are solely those of the author, and do not reflect the views of Latitude Media or any of its staff.

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virtual power plants
Department of Energy (DOE)
energy transition
demand response