Addressing Texas grid reliability: Time to go nuclear?
By Texas summer standards, the heat in August 2023 seemed relentless but not without precedent. A string of 100-plus-degree days gripped the state, and the sound of air conditioning was constant.
The overseer of much of the state’s electricity grid, the Electric Reliability Council of Texas (ERCOT), issued eight conservation appeals during the month, encouraging retail electricity customers to reduce use of air conditioning and large appliances. Some days it was barely enough. Output from solar and wind facilities was low while thermal energy sources (natural gas, coal and nuclear) struggled to keep up with record-setting electricity demand, or load.
As the energy capital of the nation kept a wary eye on power reserves, ERCOT officials warned they might need to resort to rolling blackouts to keep the system from breaking.
In recent years, low-cost renewable energy sources such as wind and solar have flourished. However, when the wind doesn’t blow or the sun doesn’t shine, and there are inadequate thermal resources to fill the gap, the grid can become vulnerable.
An expanding economy and population, a growing footprint of manufacturing facilities and data centers and more frequent episodes of extreme heat and cold have contributed to Texas electricity consumption rising at an annual rate exceeding the national average.
Nuclear power advocates say that at a time of increasing use of renewables and heightened concerns over climate change, nuclear should become a more readily available part of the mix. Nuclear is reliable, energy dense and scalable. It also has zero carbon emissions. Comanche Peak Nuclear Power Plant No. 2 in Glen Rose, Texas, 85 miles southwest of Dallas, began operations in 1993. Since then, no other nuclear power plant has opened in the state.
Share of renewable energy triples
The share of renewables for Texas’ overall electricity consumption tripled from 2010 to 2023, a product of federal tax credits, falling installation and materials costs, bountiful wind and solar resources, and state-incentive-backed transmission capacity growth. Wind and solar accounted for roughly one-third of electricity produced in 2023 (Chart 1).
However, this does not mean renewables supplied nearly a third of energy needs every day. Renewables present a unique set of challenges to managing the power grid, including a frequent mismatch between peak load and peak supply.
As load peaks in the early evening during the summer, solar production declines, forcing natural gas-fired generation plants to rapidly increase output (Chart 2). The reverse occurs in the early morning, when gas facilities ramp up (as households start their day) and trail off as solar output emerges with the rising sun.
Similarly, load follows an uneven pattern on the coldest winter days, again not aligning well with the timing of solar output and often prompting the need for gas plants to ramp up quickly. (Chart 3).
Meanwhile, wind also presents resource availability challenges. When the wind doesn’t blow, the enormous and growing level of installed wind capacity is unavailable, and another power source has to take its place. Such uneven cycles on gas plants accelerate wear on the facilities, contributing to unplanned outages and maintenance downtime.
The thinning margin between thermal plant capacity and peak load has produced periods of high and volatile wholesale electricity prices across the state. Statewide wholesale electricity prices, which typically average below $100 per megawatt-hour, shot past $1,000 per megawatt-hour 15 times during summer 2021. Prices crossed the $1,000 threshold 182 times in summer 2023 with the greater prevalence of renewables and ERCOT’s cautious power reserve management.
These conditions have also created an opportunity during peak load periods for utility-scale batteries, whose capacity in Texas soared over the past two years. Battery technology is uniquely suited to discharge during critical periods, when solar and wind output fades. However, the current state of technology prevents their use as a source of baseload power, that is, dependably available and capable of running 24 hours a day, seven days a week.
Keeping the grid running
Nuclear provides a minor portion of Texas’ current generating portfolio. Texas’ two nuclear plants, combining for more than 5 gigawatts of nameplate (or total) output, fulfill the role of baseload power. To put that capacity in perspective, the state has 22 gigawatts of installed solar capacity and more than 38 gigawatts of installed wind capacity.
Conventional light-water nuclear reactors are not well equipped to meet the flexible energy needs of a grid with robust intermittent resources, since reactors are not designed to ramp up or down quickly in response to demand. A significant expansion of conventional nuclear capacity would increase the steady baseload supporting the electric grid and reduce the amplitude of the daily power demand cycle currently required of natural gas plants.
However, new nuclear facility developers confront high costs, regulatory requirements and pockets of public opposition.
While fuel and operating costs for conventional nuclear plants are relatively inexpensive, construction costs are enormous and the federal permitting process stretches over several years while billions of dollars in expenses are incurred, making cost recovery highly uncertain. Expansion of Plant Vogtle in Georgia, completed in 2023, marked the first nuclear reactor to receive regulatory approval in 30 years. It was seven years late and $17 billion over budget.
When considering capital costs, nuclear appears uncompetitive compared with alternatives. The financial advisory firm Lazard found the unsubsidized levelized cost of energy for a nuclear plant can be more than twice that of a combined-cycle natural gas plant, one that generates electricity from both primary generation and from converting waste steam to power. (Levelized cost is the net present cost over the lifetime of a generating facility, generally spanning 30 to 50 years).
In a reversal of long-term trends, public support in the U.S. for nuclear has increased over the past decade, with a narrow majority supporting it. Opponents remain fearful of risks following incidents such as the Fukushima Daiichi accident, when a Japanese power plant released radioactive material following an earthquake in March 2011.
As aging U.S. power generation facilities face rounds of permit extensions at state and federal levels, 12 reactors nationwide have been decommissioned over the past 10 years, most in response to local opposition.
Small modular reactors among new technologies
Despite barriers to approval, nuclear backers cite the power source’s carbon-free operations, reliability, generation capacity and energy density. Development of advanced nuclear reactor technology may address many of the challenges that have stymied growth of conventional nuclear.
The Department of Energy launched its Advanced Reactor Demonstration Program in 2020 to aid nuclear research and development in the hope of spurring new technology, including smaller and more flexible nuclear reactor options. The program has since announced multiyear awards totaling about $4.6 billion to three projects, including a demonstration project planned for Texas.
The Texas effort, expected to be completed by 2030, involves small modular reactors. Such units can be manufactured at one site then shipped and assembled at the point of use. A site can start hosting one module and add additional modules, allowing long-term scalability.
Typically, a small modular reactor has up to 300 megawatts of capacity and requires far less acreage than a traditional large reactor. Some designs are expected to be more flexible and should have the ability to ramp up and down to meet shifting load requirements, unlike conventional units.
One of the promises of the modular reactors is far lower upfront capital investment than conventional nuclear facilities. But there are concerns that the modular reactors may not be as cost effective as imagined, and cost per megawatt remains high compared with fossil fuel generation. In November 2023, another demonstration program fund recipient canceled its project, citing significant increases in previously projected costs.
While much of the cost increase can be attributed to inflation that plagued many infrastructure programs in 2023, concerns remain about the cost/benefit of modular reactors in Texas and elsewhere.
Management of nuclear waste is another challenge. Annually, traditional nuclear reactors in the U.S. produce about 2,000 metric tons of spent fuel in the aggregate, which is currently stored at the power plants in temporary pools or dry casks.
The long-term goal is permanent storage at an approved, central geologic repository, but progress on site selection has been at a standstill for two decades. Although modular reactors would likely produce far less spent fuel, concerns have surfaced that some units would create many more times the amount of spent fuel per unit of electricity generated than traditional reactors.
In addition to the federal efforts to spur advanced nuclear deployment, Texas Gov. Greg Abbott announced the formation of the Advanced Nuclear Reactor Working Group in 2023. The group is charged with assessing the feasibility of making the state a leader in nuclear power. With a team comprised of academics, business leaders and nuclear engineering experts, the working group seeks to understand how advancements such as modular reactors can be leveraged to improve affordability, reliability and safety in Texas’ energy sector. Results from their evaluation will be announced in December 2024.
Texas may also prove fertile ground for modular reactor deployment for industrial uses. The modular reactors may be particularly suited to serve on-site at the large and growing footprint of heavy manufacturing, petrochemical facilities and data centers. The first units—already ordered—are likely to appear toward the end of the decade.
Balancing costs and reliability
While developments in advanced nuclear technology hold promise for an energy grid to achieve a desired balance of low emissions and reliability, affordability may remain elusive. Additionally, widespread deployment of advanced nuclear is at least a decade away. Balancing electricity supply and demand with solar, wind, batteries and natural gas resources—and the associated price volatility for consumers—will remain a significant challenge in the interim.
ERCOT’s electricity load set records in summer 2023, primarily because of consistently excessive heat. In the winter, the grid continues to face challenges, especially during sustained temperature drops, which spike demand across the state and impact the natural gas supply chain.
Even though wholesale electricity prices rise sharply during periods of tight supply and demand, most households don’t experience surging power bills because they have fixed-rate power contracts. However, volatile prices and rising load forecasts have increased forward electricity prices, which pushes retail prices higher over time. While the residential cost per kilowatt-hour in Texas ranged between 14 and 17 cents from 2015 to 2019 in real (inflation-adjusted) terms, it jumped to more than 30 cents in 2022 and has remained volatile since (Chart 4).
For low-income households struggling to get by, rising utility bills represent a significant share of living expenses. For example, in 2023, 57 percent of Texas households with annual income under $50,000 reported forgoing meals or medication to pay energy bills.
In times of severe weather, such households may also be at particular risk of power loss. During the February 2021 statewide freeze, communities with higher shares of racial minorities were more than four times more likely than predominately white areas to experience blackouts, driving some to unsafe heating methods that led to carbon monoxide poisoning.
Charting a path forward
Nuclear energy offers several advantages over other types of power: It is cleaner than fossil fuels, it is more predictable and reliable than renewables, and its generation capacity is far greater than all alternatives. Nuclear reactors in Texas, either at the utility level or as co-generation assets for heavy manufacturing facilities, offer the prospect of solving many fundamental challenges for the grid.
However, significant upfront capital costs mean the returns for any plant developer are uncertain— particularly in ERCOT’s energy-only market, which pays power providers only for the electricity they deliver. In other regions, capacity markets, in which power providers are compensated for holding capacity in reserve, could help ensure cost recovery for nuclear plants and likely accelerate their development.
For the past two decades, Texas consumers have largely benefitted from cheaper electricity with the increased presence of cheaper renewables. However, consumers are no longer seeing benefits to the same extent as concerns about reliability quickly escalate. Amid volatile wholesale pricing, market signals and incentives to deploy more baseload resources within ERCOT are inadequate. An adjustment to the market or incentive structure could bring more nuclear capacity into the grid, but it’s likely to push electricity bills higher.
Ultimately, Texas and the U.S. will need a diverse set of fuel sources while grappling to balance sustainability, cost and reliability. Nuclear, already part of the mix, may end up playing a larger role in the future through new technology. Commercial small modular reactors and advanced reactor designs are relatively new concepts. It remains to be seen if new reactor technology can deliver on the promise of a scalable option.
About the authors
Garrett Golding is a senior business economist in the Research Department of the Federal Reserve Bank of Dallas.
Emily Ryder Perlmeter is a senior advisor in Community Development at the Federal Reserve Bank of Dallas.
Prithvi Kalkunte is an economic programmer in the Research Department at the Federal Reserve Bank of Dallas.
