Energy & Commodities

Shrinking Supply, Growing Demand: The U.S. Bulk Power System Nears a Breaking Point

How did Texas become a bellwether for U.S. grid stability?

In February 2021, millions of Americans watched as Winter Storm Uri caused power blackouts across Texas during one of the coldest stretch of days on record. The sudden freeze crippled ERCOT, the state’s grid operator: gas pipes supplying power plants froze, wind turbines stopped spinning and the electric heaters in millions of homes went cold. Three of the fastest growing metropolitan centers in the country were brought to their knees and more than $300 billion in economic damage was inflicted upon the state.

How did Texas, the energy capital of the western hemisphere, fall victim to a disastrous cascade of power failures? What can we learn from the crash of dispatchable generation, which coincided with skyrocketing demand? The obvious answer is the storm: an anomalistic event that crippled an energy network made vulnerable by residents’ heavy dependence on electric heating.

This was more than an extreme climate event but a symptom of a fundamental issue that is common beyond ERCOT. There are clear signals that by 2030, blackouts like this could become a reality year-round across the United States (U.S.). Storm Uri hit Texas in a flash, but those coincident circumstances of rising electric demand and dwindling dispatchable supply are quietly setting the scene for nearly identical events across U.S. Regional Transmission Networks (RTOs). Although this process has none of the “drama” of an ice storm, the outcome for ratepayers and local economies will be the same.

Publicis Sapient partnered with Sector & Sovereign Research (SSR) to examine U.S. energy supply fundamentals from the bottom-up, by facility technology and commissioning date. Our analysis suggests almost two-thirds of U.S. dispatchable generation capacity is likely to retire by 2035, well above forecasts from the Energy Information Administration (EIA). Over the same period, adoption of Electric Vehicles (EV) and widespread advancement of electrification policy will drive peak load well above the historical maximum (789 GW) observed in 2007 and 2012 (Exhibit 1).

As U.S. energy security becomes more precarious, stakeholders must set aside ideological differences to collaborate on practical solutions that balance long-term climate goals against near-term economic and physical risks facing ratepayers.

Historically, an average of around 11 GW/year has been added to dispatchable generation capacity in the U.S. to fill the looming supply gap. To close the gap seen in the chart above, we need to triple that (to ~29 GW/year) to offset what we expect in retirements.

However, the picture is complicated by the uneven shape and seasonality of demand during the typical day, or across the calendar year. For the moment let us set aside the effects of increased base demand due to building electrification and examine the impact of EVs alone. If just five percent or 10 percent of LDVs were charging simultaneously, and we layer that atop historical figures for hourly load, the resulting demand would exceed reserve capacity levels (firm capacity less then 15 percent margin) in most of the U.S.’ regional power markets (Exhibit 4).

Exhibit 4: % Hours Historical Peak Load (see note 1) + EV Charging Would Exceed Firm Capacity

('22 firm capacity less than 15% reserve by RTO; assumes charging at 10KW)

Pushing against the current: How utility operators can mitigate outages and the economic fallout

The trends at work in the U.S. generation mix signal that capacity shortfalls are likely to significantly outpace current projections. Our bottom-up analysis of the U.S. fleet suggests 63 percent of today’s firm capacity will retire by 2035, and filling the gap between supply and growing demand will require tripling recent replacement levels of dispatchable resources. Filling this gap with renewables is impractical given intermittency challenges and the high relative cost of battery storage.

At the same time, gross electricity demand is expected to increase 10 percent by 2030 from EV adoption alone. If overall power demand follows traditional seasonal patterns and we assume that just five to 10 percent of LDVs were charging coincidently, every U.S. regional transmission organization would fail to maintain reserve margins at some point during the year. Furthermore, for several regional operators those capacity challenges are more concerning during the winter months—contrary to the sector’s popular focus on meeting summer demand.

A grid operating within reserve margins is inherently less reliable and more exposed to failure, particularly during extreme weather events. The approaching intersection of these supply and demand trajectories will present stakeholders with many challenges, but it will also create opportunities for solutions that balance climate goals and operational risk. These include services and channels for incentivizing residential customer demand response, as well as creative solutions for commercial and industrial partners that have their own emissions reduction goals. Beyond their direct customers, system operators must also bring regulators and policymakers along on the journey to ensure a uniform understanding of the generation supply tradeoffs required to guarantee system reliability.