Thursday, January 14, 2021

The New Economics of Electrifying Buildings - An Analysis of Seven Cities - All-Electric New Homes: A Win for the Climate and the Economy

As states and cities across the United States work to cut carbon emissions from every sector, they’re starting to tackle a crucial transition: eliminating fossil fuels in buildings. Burning fossil fuels, primarily gas, to heat space and water and cook food poses a risk to climate goals and public health. Thus, spurring the shift to modern, electric appliances like heat pumps becomes critical.
Buildings are quickly becoming a cornerstone of ambitious climate policy, as policymakers recognize they can’t achieve the necessary science-based emissions reductions without tackling this stubborn sector. This means states and cities across the country won’t meet their climate goals if new buildings in their jurisdiction include fossil fuel systems that lock in carbon emissions over the 50 to 100-year building lifetime.

The cost of such an ambitious transition is often the first consideration. Thus, to help inform these crucial decisions, Rocky Mountain Institute updated and expanded their 2018 analysis, The Economics of Electrifying Buildings. They examined the economics and carbon emissions impacts of electrifying residential space and water heating, now with seven new cities and additional methodology changes. Today, we are releasing the first set of our findings examining newly constructed single-family homes. In every city we analyzed, a new all-electric, single-family home is less expensive than a new mixed-fuel home that relies on gas for cooking, space heating, and water heating. Net present cost savings over the 15-year period of study are as high as $6,800 in New York City, where the all-electric home also results in 81 percent lower carbon emissions over the mixed-fuel home.
Key Findings
The new all-electric, single-family home has a lower net present cost than the new mixed-fuel home in every city we studied: Austin, TX; Boston, MA; Columbus, OH; Denver, CO; Minneapolis, MN; New York City, NY; and Seattle, WA.
  • In most cities, the mixed-fuel home (with gas furnace, water heater, air conditioning, and new gas connection costs) has a higher up-front cost than the all-electric home, which uses a heat pump system for both heating and cooling. This is true in Austin, Boston, Columbus, Denver, New York, and Seattle. The Minneapolis climate requires a higher capacity heat pump than other cities in the study. This comes at a higher cost, outweighing the equipment and labor cost savings seen with heat pump systems in milder climates.
  • There are significant energy savings with the heat pump space and water heater over corresponding gas appliances, resulting in a lower annual utility cost for the all-electric home in most cities—up to 9 percent lower in Minneapolis. The two modeled scenarios have nearly equivalent utility bills in Boston and Seattle.
  • The all-electric home results in substantial carbon emissions savings over the mixed-fuel home in all cities. The greatest savings are found in Seattle (93 percent) and New York City (81 percent). Minneapolis, Columbus, Boston, and Austin all save more than 50 percent over the lifetime of the equipment compared with the mixed-fuel home.
Context and Methodology
Cities in California, Washington, New York, and Massachusetts have all passed laws or adopted codes mandating or encouraging all-electric new building construction. Regional coalitions across the country are forming to extend lessons learned from these first movers to other states, including in New England and the Midwest.

Thus, we extended our Economics of Electrifying Buildings research to assess the economic case for electrification in a variety of climate zones. Several of these states are actively considering new policies or incentives to spur the transition to all-electric buildings.

In partnership with Group 14, we have updated our methodology from the 2018 report to be more readily replicable in support of building decarbonization policy decisions across the United States, incorporating the following:
  • A thorough energy use calibration for each scenario to end-use breakdown, energy use intensity, and gas/electricity fuel split with the latest available Energy Information Administration Residential Energy 
  • Consumption Survey data by climate region
  • A 15-year greenhouse gas emissions comparison that incorporates data from both the US EPA and NREL’s Regional Energy Deployment System model to project changes in carbon intensity for electricity consumed in each state through 2036
  • RSMeans construction costing factors to account for location-specific variability in up-front cost
  • Building industry performance standards from ASHRAE for HVAC systems, EnergyStar for household appliances, and WaterSense for potable water fixtures
Policy Implications
Our analysis shows that all-electric new construction is more economical to build than a home with gas appliances, regardless of location. Given these findings, policymakers should embrace policies that incentivize or mandate all-electric residential new construction. In addition, they should prioritize complementary policies that address several obstacles that are impeding widespread adoption of all-electric homes. We suggest the following actions:
  • Educate contractors. Our research finds that there is low contractor comfort with heat pump systems for year-round heating in cities with severe winter climates, a notion that persists from an era of older technology. Today, there are cold-climate heat pumps designed to address concerns of low capacity and efficiency in cold temperatures, best practice design guidelines, and case studies proving the efficacy of cold-climate heat pumps.To promote contractor readiness as all-electric building codes come online, policymakers and regulatory agencies should establish contractor trainings on heat pump technologies (see for example, NYSERDA’s Clean Energy Workforce Development program and San Jose’s Educational Program). For high rates of participation, ensure attendees have a reason to attend. Some jurisdictions have considered paying participants for their time. Others have allowed trained participants to be added to a qualified contractors list.
  • Educate consumers and developers. Consumers and developers are increasingly knowledgeable about modern, efficient heating and cooking technology like heat pumps and induction stoves. But their comfort with the technologies must be fostered to realize the unprecedented market expansion that is needed in the next 10 years to align the buildings sector with our global climate goals.Policymakers and regulatory agencies should establish education campaigns for residents and building developers about the health, economic, and climate benefits of all-electric homes. Familiarizing consumers with induction cooking is a particularly important issue with a variety of novel solutions (see for example, San Jose’s Induction Cooktop Checkout Program).
  • Update gas line extension allowances. Typically, gas utilities offer an allowance to compensate a portion of the cost of a new customer gas service extension, with the remainder paid by the customer or developer of the new property. Our research finds that the allowance is highly variable: it could be as low as $1,000 or higher than $5,000, in some states covering the total cost to connect the gas pipeline to a new home. Gas utility customers bear the cost of this allowance over time, therefore socializing the cost of unnecessary, uneconomic infrastructure that is not aligned with air quality, health, or climate goals. Regulatory agencies should reassess these allowances as a part of their transition planning and management of stranded asset risk.
  • Address the split incentive challenge through creative financing. In Boston and Seattle, the all-electric home has a lower cost to build, but a slightly higher cost to operate. To ensure that all consumers benefit from the up-front cost savings for all-electric homes, home mortgages could be amortized in a manner to reduce the monthly payments to compensate for higher bills. Additionally, utility regulators and policymakers should work to make the cost of gas reflect the societal cost of greenhouse gas emissions or health impacts. This can be done through a greenhouse gas emissions tax, an air quality/health impacts adder, or an increase in permitting costs for extraction and transport of fossil fuel.
This is the first release of in the new Economics of Electrifying Buildings series. Later this year, we will release findings for single-family retrofits. In early 2021, we plan to provide a detailed technoeconomic analysis for multifamily buildings, examining the case for all-electric new construction and retrofits in all seven cities.

Austin: Single-Family Homes
RMI analyzed the costs of a new all-electric home versus a new mixed-fuel home that relies on gas for cooking, space heating, and water heating. In Austin, the all-electric home saves $4,400 in net present costs and 15 tons of CO2 emissions over a 15-year period.

Key Findings
The new all-electric home has a lower net present cost than the new mixed-fuel home, presenting savings on both up-front costs and utility bills.
• A mixed fuel home (with gas furnace, water heater, air conditioning, and new gas connection costs) has a higher up-front cost than the all-electric home, which uses the heat pump system for both heating and cooling.
The all-electric home has 7% lower annual utility costs. There are significant energy savings with a heat pump space and water heater over corresponding gas appliances, even though electricity is significantly more expensive than gas per unit energy in Austin.
Carbon emissions from heating, water heating, and cooking are 65% lower over the appliance lifetime in the all-electric home, due to more efficient appliances and increasingly low-carbon electricity.

Boston: Single Family Home
RMI analyzed the costs of a new all-electric home versus a new mixed-fuel home that relies on gas for cooking, space heating, and water heating. In Boston, the all-electric home saves nearly $1,600 in costs and 51 tons of CO2 emissions over a 15-year period.

Key Findings
The new all-electric home has a lower net present cost than the new mixed-fuel home, with savings on up-front costs and nearly equivalent annual energy bills.
• A mixed-fuel home (with gas furnace, water heater, air conditioning, and new gas connection costs) has a higher up-front cost than the all-electric home, which uses the heat pump system for both heating and cooling.
The all-electric home has 3% higher annual utility costs. There are significant energy savings with heat pump space and water heater over corresponding gas appliances, which outweigh the high cost of electricity in Boston.
• Carbon emissions over the 15-year period from heating, water heating, and cooking are 69% lower in the allelectric home, due to more efficient appliances and increasingly low-carbon electricity.

Wednesday, January 13, 2021

New Report Finds Current Transmission Interconnection Process Unworkable and Inefficient, Raising Energy Costs for Customers and Stifling Job Creation

On January 12, 2021 a report was released that shows that the current system for interconnecting generators to the transmission grid is unworkable and inefficient, creating a backlog of unbuilt energy projects. These lengthy interconnection queues have resulted in increased electricity costs for consumers, delayed rural economic development and job creation, and an added difficulty for clean energy projects looking to be connected to the nation’s grid.

Sponsored by Americans for a Clean Energy Grid as part of the Macro Grid Initiative, Disconnected: The Need for a New Generator Interconnection Policy examines the current interconnection process and finds that current policies governing queues are excessively costly, slow, and unpredictable. At the end of 2019, 734 gigawatts of proposed generation — 90 percent of which are new wind, solar, and storage projects — were waiting in interconnection queues nationwide.

“Connecting to the transmission grid is like spending four years at the Department of Motor Vehicles, except the costs are much less predictable. FERC’s interconnection policy was created in a different era and it no longer works,” said Rob Gramlich, co-author and Executive Director of Americans for a Clean Energy Grid.

The report finds that the current interconnection backlog is:
  • Increasing electricity costs for American homes and businesses by delaying the construction of new energy projects, which are cheaper than existing electricity production.
  • Harming rural economic development and job creation as most new energy projects are located in remote, rural areas.
  • Delaying or preventing state, utility, and Fortune 500 companies from reaching their decarbonization commitments by backlogging the development of new renewable energy projects.
  • Continuing to expose Americans, especially those in marginalized communities, to the harmful impacts of smog, nitrogen oxide, sulfur oxide, fine particulate matter, and carbon dioxide pollution, which are usually associated with older forms of energy production.
“This report further demonstrates the urgency in which we need to upgrade and reform our transmission system,” says Jay Caspary, co-author and Vice President at Grid Strategies LLC. “We won’t be able to access the benefits of new, clean energy projects by relying on incremental, evolutionary reforms to generator interconnection processes.”

Currently, large transmission upgrades rely on participant funding and network planning, creating a situation in which project developers are charged with paying for transmission upgrades despite the fact that there are broad-based, regional benefits. To address this problem, the report argues that FERC and other planning authorities should discontinue the policy of participant funding for new generation and implement an up-front planning system that expands and improves regional and interregional transmission planning to be proactive, incorporate future generation additions and retirements, and spread costs to all beneficiaries.

“Backlogs in interconnection queues have emerged as a significant challenge to the growth of renewable energy, even as consumer demand increases for low-cost wind and solar projects,” said Gregory Wetstone, President and CEO of the American Council on Renewable Energy (ACORE). “This important new report highlights the shortcomings of current interconnection policies and proposes sensible solutions for substantive reform. The renewable energy growth enabled by these policy changes is essential to efforts to address the climate challenge.”

Executive Summary
America’s system for planning and paying for the nation’s transmission grid is causing a massive backlog and delay in the construction of new power projects. While locally produced electric power is gaining in popularity, most of the lowest cost new power production comes from projects which are located in rural areas and, thus, depend on new electricity lines to deliver power to the urban and suburban areas which use most of the nation’s power. Project developers must apply for interconnection to the transmission network, and until the network capacity is expanded to accommodate the resources, the projects must wait in an “interconnection queue.” At the end of 2019, 734 gigawatts of proposed generation were waiting in interconnection queues nationwide.

This massive backlog has multiple negative impacts on the nation. First, it needlessly increases electricity costs for America’s homes and businesses in two ways: (1) it slows or prevents the adoption of new power sources which are cheaper than existing power generation; and (2) it also significantly increases the costs of each new power source. Americans for a Clean Energy Grid’s (ACEG) recent study demonstrates that a comprehensive approach to building transmission to connect remote power resources to electricity load centers in the Eastern half of the U.S. can cut consumers electric bills by $100 billion and decrease the average electric bill rate by more than one-third, from over cents/kWh  today to around 6 cents/kWh by 2050, saving a typical household more than $300 per year.

Second, because the lowest cost proposed power projects are often located in rural areas, this backlog is blocking rural economic development and job creation. In addition, rural power projects expand the tax base of local communities and typically generate lease payments or other revenue for farmers and other landowners. New transmission in the Eastern half of the U.S. alone will unleash up to $7.8 trillion in investment in rural America and create more than 6 million net new domestic jobs.

Third, almost 90 percent of the backlog is for wind and solar projects, thus blocking the resources which dominate new electricity production, reflecting the changing resource mix in the power sector and America’s abundance of high-quality renewable resource areas where the sun shines bright and the wind blows strong. The U.S. Energy Information Administration (EIA) projects wind and solar will account for 75 percent of new electricity generation in 2020.5 Many states, utilities, Fortune 500 companies and other institutions have adopted large commitments or requirements to scale up their renewable energy use or reduce their carbon pollution and this backlog may delay or impede achievement of these commitments or requirements. In addition, delays in developing these projects unnecessarily exposes Americans, especially those in environmental justice communities, to the harmful impacts of smog, and nitrogen oxide, sulfur dioxide, fine particulate and carbon dioxide pollution.

IV. Evidence of a Broken Interconnection Policy
a) Upgrade costs assigned to customers are high
Analysis by Lawrence Berkeley National Laboratory, shown in tables 1 and 2 below, indicates that the costs to integrate new resources, not just renewable projects, have reached levels that are unreasonably high for a developer to proceed in MISO and PJM. As expected, the costs for integrating new resources in MISO are rising substantially relative to previous years, indicating that the large-scale network has reached its capacity and needs to expand to connect more generation. In other words, much more than “driveway” type facilities are needed; larger roads and highways are required to alleviate the traffic. Table 137 below shows that historically, interconnecting wind projects have incurred interconnection costs of $0.85 per megawatt hour (MWh) or $66 per kilowatt (kW). However, newly proposed wind projects now face interconnection costs that are nearly five times higher, at $4.05/MWh or $317/kW. For reference, this is about 23 percent of the capital cost of building a wind project.

New solar projects in MISO South have much higher upgrade costs. The most recent 2019 system impact study for solar projects in MISO South estimated upgrade costs to total $307/kW, with upgrade costs for individual interconnection requests as high as $677/kW.

The rapidly increasing cost of interconnection in recent years shows that the breaking point has been reached. MISO, for example, has reported that “...interconnection studies for new generation resources in MISO’s West sub-region have indicated the need for network upgrades exceeding $3 billion to accommodate the initial queue volume, and a similar trend is expected to occur in other areas with high wind and solar potential, including MISO’s Central and South sub-regions.” Figure 2 below illustrates the large increase in assigned network upgrade costs to generators in MISO West, from approximately $300/kW in 2016 to nearly $1,000/kW in 2017. The costs to build proposed wind projects will likely result in developers abandoning those resources as project integration costs exceed $100/kW.

Tuesday, January 12, 2021

The Benefits and Costs of Decarbonizing Costa Rica's Economy

Costa Rica's National Decarbonization Plan (NDP) sets the ambitious goal for the country to become carbon-neutral by 2050 and lays out a wide range of policy and institutional reforms to achieve this goal. The authors of this report developed an integrated model that estimates the benefits and costs of implementing the NDP in all major sectors, informed by consultations with numerous government agencies, industries, and nongovernmental organizations, and used it to evaluate whether the NDP makes economic sense for Costa Rica — that is, whether the benefits of the NDP exceed its costs.

The authors' analysis suggests that under the vast majority of plausible assumptions about the future, the NDP would achieve or nearly achieve its greenhouse gas emissions reduction goals and do so at a net economic benefit. Conversely, without a concerted focus and investment in decarbonization, Costa Rica's greenhouse gas emissions will increase substantially.

The findings from this study can play an important role in ensuring that the implementation of the NDP is robust — meaning that it will achieve its goals in the uncertain future. This analysis confirms which lines of action are most critical to the success of the NDP — transport and land use — and identifies some key conditions necessary to achieve close to zero net emissions at a large net economic benefit. This study also offers ideas and models that are valuable for other countries interested in decarbonization, and that can inspire development partners globally.

Key Findings
  • Under baseline assumptions, decarbonization would yield $41 billion in net benefits to Costa Rica between 2020 and 2050, using a 5 percent discount rate.
  • Under all but 22 of the more than 3,000 plausible futures considered, implementation of the decarbonization plan would lead to economic benefits that exceed the costs.
  • Currently, electricity is almost completely renewable, and with modest investments it would provide nearly emissions-free energy to support the electrification of much of Costa Rica's economy.
  • In the transport sector, significant emissions reductions are possible through electrification of transport and shifting to public transportation. The economic benefits from energy savings, fewer accidents, time saved from reduced congestion, and the reduced negative impacts of air pollution on health more than compensate for the initially higher up-front costs of switching to electric vehicles and building infrastructure for zero-emissions public transport.
  • Reducing emissions in agriculture and livestock could lead to increased productivity, and increasing carbon sequestration by forests would increase valuable ecosystem services, such as renewable forestry products, water and soil benefits, and support for tourism and cultural heritage.
  • Emissions reductions from buildings, industry, and the waste sector are also important to reach zero net emissions and together provide modest net benefits through energy cost savings, increased productivity, and the value of treating and recycling and reusing liquid and solid waste.

  • Costa Rica should continue implementing its NDP to both meet its international obligations to decarbonize and facilitate an economic transition that would very likely lead to large net benefits and contribute to a sustainable COVID-19 pandemic recovery.
  • As Costa Rica recovers from the COVID-19 pandemic, it should focus on decarbonization investments that would reactivate the economy and provide support to the most critically affected sectors of the economy.
  • Costa Rica should monitor the costs of alternative-fuel vehicles, as well as the adoption of improved public transportation options, and make adjustments to the transport decarbonization strategies as needed to ensure net economic benefits and sufficient emissions reductions.
  • As Costa Rica continues to manage its forests for long-term sustainability, it should measure and monitor ecosystem service benefits in order to best target the NDP interventions.
  • Costa Rica should continue to develop more-detailed proposals for implementing the plan and reevaluate benefits and costs periodically to ensure the greatest net benefits, including by aligning its Nationally Determined Contribution to the NDP.
Our analysis suggests that, under baseline assumptions, implementing the NDP would lead to net-zero GHG emissions by 2050 and provide about $41 billion of net benefits across the economy from 2020 to 2050, discounted back to 2015 at a rate of 5 percent per year.3 It would save or otherwise provide $78 billion in benefits, and it would cost about $37 billion. There is significant uncertainty around these estimates, but the analysis shows that under the vast majority of plausible assumptions about the future, the NDP would achieve or nearly achieve its emissions reduction goals and do so at a net economic benefit.

Under baseline assumptions, fully implementing all lines of action in the NDP would lead to about $41 billion in net benefits (Figure S.2). The greatest benefits are due to actions affecting transport,  agriculture, livestock, and forestry net emissions. In the agriculture, livestock, and forestry sectors, ecosystem services provided by forests, such as renewable forestry products, water and soil benefits, support for tourism and cultural heritage, and improved yields are worth much more than the investments required to decarbonize and the forgone value of land dedicated to forests—providing discounted net benefits of about $22 billion. The public and private transport sectors together with the freight sector would provide $19 billion in net benefits under baseline assumptions, since the economic benefits from energy savings, fewer accidents, time saved from reduced congestion, and the reduced negative impacts of air pollution on health more than compensate for the initially higher up-front costs of switching to electric vehicles and building infrastructure for public transport (Godínez-Zamora et al., 2020). Efficiency gains in industry, and the economic value of recycled materials and treated wastewater, result in a small net benefit for the industry and waste sectors: $1.3 billion together. Figure S.2 shows modest net costs for the electricity and buildings lines of actions. However, the benefits of cheaper electricity are accounted for under the transport, industry, and buildings sectors.

by David G. Groves, James Syme, Edmundo Molina-Perez, Carlos Calvo Hernandez, Luis F. Víctor-Gallardo, Guido Godinez-Zamora, Jairo Quirós-Tortós, Felipe De León, Andrea Meza Murillo, Valentina Saavedra Gómez, Adrien Vogt-Schilb

Friday, January 8, 2021

Local Sectoral Specialization in a Warming World

This paper quantitatively assesses the world's changing economic geography and sectoral specialization due to global warming. It proposes a two-sector dynamic spatial growth model that incorporates the relation between economic activity, carbon emissions, and temperature. The model is taken to the data at the 1° by 1° resolution for the entire world. Over a 200-year horizon, rising temperatures consistent with emissions under Representative Concentration Pathway 8.5 push people and economic activity northwards to Siberia, Canada, and Scandinavia. Compared to a world without climate change, clusters of agricultural specialization shift from Central Africa, Brazil, and India's Ganges Valley, to Central Asia, parts of China and northern Canada. Equatorial latitudes that lose agriculture specialize more in non-agriculture but, due to their persistently low productivity, lose population. By the year 2200, predicted losses in real GDP and utility are 6% and 15%, respectively. Higher trade costs make adaptation through changes in sectoral specialization more costly, leading to less geographic concentration in agriculture and larger climate-induced migration.

The Value of Time in the United States: Estimates from Nationwide Natural Field Experiments

The value of time determines relative prices of goods and services, investments, productivity, economic growth, and measurements of income inequality. Economists in the 1960s began to focus on the value of non-work time, pioneering a deep literature exploring the optimal allocation and value of time. By leveraging key features of these classic time allocation theories, we use a novel approach to estimate the value of time (VOT) via two large-scale natural field experiments with the ridesharing company Lyft. We use random variation in both wait times and prices to estimate a consumer's VOT with a data set of more than 14 million observations across consumers in U.S. cities. We find that the VOT is roughly $19 per hour (or 75% (100%) of the after-tax mean (median) wage rate) and varies predictably with choice circumstances correlated with the opportunity cost of wait time. Our VOT estimate is larger than what is currently used by the U.S. Government, suggesting that society is under-valuing time improvements and subsequently under-investing public resources in time-saving infrastructure projects and technologies

Having gotten this far in our study you have surely invested a fair amount of time. We hope that such time was indeed an investment, and not ill-spent. This is because time is the ultimate scarce resource, and its value has deep implications for a range of economic phenomena and investment decisions. Our starting point is a literature from the 1960s that had deep implications for our understanding of the family, the household, and time allocation more generally. We leverage insights from these classic time allocation theories to provide a theoretically-consistent but updated approach to estimate the VOT. The theory carefully directs two large-scale natural field experiments on the Lyft platform to estimate the causal effects of wait time and price on ride-share demand.

We report several interesting insights. First, we estimate a VOT that is roughly $19 per hour (2015 prices). This estimate is 75-80% of the mean wage rate for the various regions in our experiment, which is quantitatively different from the findings of previous empirical studies on the VOT (Small et al., 2007) and is greater than the existing US policy guidelines on the VOT (USDOT, 2015). Second, we document that, consistent with standard microeconomic models (Becker, 1965; DeSerpa, 1971), the VOT is related to the opportunity cost of time, the available substitute set, and other key features of the trip that impact marginal benefits and marginal costs. Third, taken in aggregate, our research has key implications for policy. Specifically, we recommend that policymakers: (i) account for the great deal of VOT heterogeneity with respect to cities, locations within cities, day of week, and time of day; and (ii) adjust the rule-of-thumb VOT estimates up to 75% of the after-tax mean wage rate otherwise.

Sources of Cost Overrun in Nuclear Power Plant Construction Call for a New Approach to Engineering Design

• US nuclear plant cost estimation does not align with observed experience
• “Indirect” expenses, largely soft costs, contributed a majority of the cost rise
• Safety-related factors were important but not the only driver of cost increases
• Mechanistic models inform innovation by relating engineering design to cost change

Nuclear plant costs in the US have repeatedly exceeded projections. Here, we use data covering 5 decades and bottom-up cost modeling to identify the mechanisms behind this divergence. We observe that nth-of-a-kind plants have been more, not less, expensive than first-of-a-kind plants. “Soft” factors external to standardized reactor hardware, such as labor supervision, contributed over half of the cost rise from 1976 to 1987. Relatedly, containment building costs more than doubled from 1976 to 2017, due only in part to safety regulations. Labor productivity in recent plants is up to 13 times lower than industry expectations. Our results point to a gap between expected and realized costs stemming from low resilience to time- and site-dependent construction conditions. Prospective models suggest reducing commodity usage and automating construction to increase resilience. More generally, rethinking engineering design to relate design variables to cost change mechanisms could help deliver real-world cost reductions for technologies with demanding construction requirements.
The history of nuclear energy in the US is one of mixed results. Rapid capacity growth in the 1960s was accompanied by significant unit upscaling, followed by operational improvements and rising capacity factors. But in the 1970s, rising project durations and costs, alongside studies on thermal pollution and low-level radiation, became a source of public controversy. Following the 1979 Three Mile Island accident, a long hiatus of nuclear construction began. Rising construction costs and project delays have continued to affect efforts to expand nuclear capacity in the US since the 1970s. A survey of plants begun after 1970 shows an average overnight cost overrun of 241%. Since the 1990s, two nuclear projects have begun construction, both two-reactor expansions of existing generating stations. The VC Summer project in South Carolina was abandoned in 2017 with sunk costs of $9B, and the Vogtle project in Georgia is severely delayed. Current estimates place the total price of the Vogtle expansion at $25B ($11,000/kW), almost twice as high as the initial estimate of $14B, and costs are anticipated to rise further.

Challenges in nuclear construction are not unique to the US. Recent projects in Finland (Olkiluoto 3) and France (Flamanville 3) have also experienced cost escalation, cost overrun, and schedule delays. Cost estimates for a plant under construction in the United Kingdom (Hinkley Point C) have been revised upward. In contrast to the experience in Western Europe and the US, however, China, Japan, and South Korea have achieved construction durations shorter than the global median since 1990. Cost and construction duration tend to correlate (e.g., Lovering et al.), but it should be noted that cost data from these countries are largely missing or are not independently verified. (Cost data should be provided and audited by entities not actively involved in plant procurement and construction, including data from international organizations or government agencies as opposed to data from utilities and reactor equipment providers.)
[The researchers concluded that between 1976 and 1987, indirect costs—those external to hardware—caused 72% of the cost increase. “Most aren’t hardware-related but rather are what we call soft costs,” says Trancik. “Examples include rising expenditures on engineering services, on-site job supervision, and temporary construction facilities.”]

Percentage contribution of variables to increases in containment building costs These panels summarize types of variables that caused costs to increase between 1976 and 2017. In the first time period (left panel), the major contributor was a drop in the rate at which materials were deployed during construction. In the second period (middle panel), the containment building was redesigned for improved safety during possible emergencies, and the required increase in wall thickness pushed up costs. Overall, from 1976 to 2017 (right panel), the cost of a containment building more than doubled.

As the left and center panels above show, the importance of those mechanisms changed over time. Between 1976 and 1987, the cost increase was caused primarily by declining deployment rates; in other words, productivity dropped. Between 1987 and 2017, the containment building was redesigned for passive cooling, reducing the need for operator intervention during emergencies. The new design required that the steel shell be approximately five times thicker in 2017 than it had been in 1987—a change that caused 80% of the cost increase over the 1976–2017 period.