Connect with us

Published

on

Only two decades ago, some scientists were skeptical we could integrate more than about 20% renewable energy generation on the U.S. power grid. But we hit that milestone in 2020 — so, these days, experts’ sights are set on finding pathways toward a fully renewable national power system. And according to new research published in Joule, the nation could get a long way toward 100% cost-effectively; it is only the final few percent of renewable generation that cause a nonlinear spike in costs to build and operate the power system.

In “Quantifying the Challenge of Reaching a 100% Renewable Energy Power System for the United States,” analysts from the U.S. Department of Energy’s (DOE’s) National Renewable Energy Laboratory (NREL) and DOE’s Office of Energy Efficiency and Renewable Energy (EERE) evaluate possible pathways and quantify the system costs of transitioning to a 100% renewable power grid for the contiguous United States. The research was funded by EERE’s Strategic Analysis Team.

“Our goal was to robustly quantify the cost of a transition to a high-renewable power system in a way that provides electric-sector decision-makers with the information they need to assess the cost and value of pursuing such systems,” said Wesley Cole, NREL senior energy analyst and lead author of the paper.

Expanding on previous work to simulate the evolution of the U.S. power system at unprecedented scale, the authors quantify how various assumptions about how the power system might evolve can impact future system costs. They show how costs can increase nonlinearly for the last few percent toward 100%, which could drive interest in non-electric-sector investments that accomplish similar decarbonization objectives with a lower total tab.

“Our results highlight that getting all the way to 100% renewables is really challenging in terms of costs, but because the challenge is nonlinear, getting close to 100% is much easier,” Cole said. “We also show how innovations such as lower technology costs, or alternate definitions for 100% clean energy such as including nuclear or carbon capture, can lower the cost of reaching the target.”

Advanced Methods Expand Our Understanding of High-Renewable Grids

This work builds on another Joule article released last month exploring the key unresolved technical and economic challenges in achieving a 100% renewable U.S. electricity system. While some aspects of 100% renewable power grids are well established, there is much we do not know. And because 100% renewable grids do not exist at the scale of the entire United States, we rely on models to evaluate and understand possible future systems.

“With increasing reliance on energy storage technologies and variable wind and solar generation, modeling 100% renewable power systems is incredibly complex,” said Paul Denholm, NREL principal energy analyst and coauthor of the paper. “How storage was used yesterday impacts how it can be used today, and while the resolution of our renewable resource data has improved tremendously in recent years, we can’t precisely predict cloudy weather or calm winds.”

Integrated energy pathways modernizes our grid to support a broad selection of generation types, encourages consumer participation, and expands our options for transportation electrification.

Many prior studies have modeled high-renewable electricity systems for a variety of geographies, but not many examine the entire U.S. grid. And even fewer studies attempt to calculate the cost of transitioning to a 100% renewable U.S. grid — instead, they typically present snapshots of systems in a future year without considering the evolution needed to get there. This work expands on these prior studies with several important advances.

First, the team used detailed production cost modeling with unit commitment and economic dispatch to verify the results of the capacity expansion modeling performed with NREL’s publicly available Regional Energy Deployment System (ReEDS) model. The production cost model is Energy Exemplar’s PLEXOS, a commercial model widely used in the utility industry.

“Over the past couple of years we put a tremendous amount of effort into our modeling tools to give us confidence in their ability to capture the challenges inherent in 100% renewable energy power systems,” Cole said. “In addition, we also tried to consider a broad range of future conditions and definitions of the 100% requirement. The combination of these efforts enables us to quantify the cost of a transition to a 100% clean energy system far better than we could in the past.”

The analysis represents the power system with higher spatial and technology resolution than previous studies in order to better capture differences in technology types, renewable energy resource profiles, siting and land-use constraints, and transmission challenges. The analysis also uniquely captures the ability to retrofit existing fossil plants to serve needs under 100% renewable scenarios and assesses whether inertial response can be maintained in these futures.

What Drives System Costs? Transition Speed, Capital Costs, and How We Define 100%

The team simulated a total of 154 different scenarios for achieving up to 100% renewable electricity to determine how the resulting system cost changes under a wide range of future conditions, timeframes, and definitions for 100% — including with systems that allow nonrenewable low-carbon technologies to participate.

“Here we use total cumulative system cost as the primary metric for assessing the challenge of increased renewable deployment for the contiguous U.S. power system,” said Trieu Mai, NREL senior energy analyst and coauthor of the paper. “This system cost is the sum of the cost of building and operating the bulk power system assets out to the year 2050, after accounting for the time value of money.”

To establish a reference case for comparison, the team modeled the system cost at increasing renewable energy deployment for base conditions, which use midrange projections for factors such as capital costs, fuel prices, and electricity demand growth. Under these conditions, the least-cost buildout grows renewable energy from 20% of generation today to 57% in 2050, with average levelized costs of $30 per megawatt-hour (MWh). Imposing a requirement to achieve 100% renewable generation by 2050 under these same conditions raises these costs by 29%, or less than $10 per MWh. System costs increase nonlinearly for the last few percent approaching 100%

Associated with the high renewable energy targets are substantial reductions in direct carbon dioxide (CO2) emissions. From the 57% least-cost scenario, the team translated the changes in system cost and CO2 emissions between scenarios into an average and incremental levelized CO2 abatement cost. The average value is the abatement cost relative to the 57% scenario, while the incremental value is the abatement cost between adjacent scenarios, e.g., between 80% and 90% renewables. In other words, the average value considers all the changes, while the incremental value considers only the change over the most recent increment.

Total bulk power system cost at a 5% discount rate (left) for the seven base scenarios and levelized average and incremental CO2 abatement cost (right) for those scenarios. The 2050 renewable (RE) generation level for each scenario is listed on the x-axis. The system costs in the left figure are subdivided into the four cost categories listed in the figure legend (O&M = operations and maintenance). The purple diamond on the y-axis in the left plot indicates the system cost for maintaining the current generation mix, which can be used to compare costs and indicates a system cost comparable to the 90% case.

Total bulk power system cost at a 5% discount rate (left) for the seven base scenarios and levelized average and incremental CO2 abatement cost (right) for those scenarios. The 2050 renewable (RE) generation level for each scenario is listed on the x-axis. The system costs in the left figure are subdivided into the four cost categories listed in the figure legend (O&M = operations and maintenance). The purple diamond on the y-axis in the left plot indicates the system cost for maintaining the current generation mix, which can be used to compare costs and indicates a system cost comparable to the 90% case. NREL

Notably, incremental abatement costs from 99% to 100% reach $930/ton, driven primarily by the need for firm renewable capacity — resources that can provide energy during periods of lower wind and solar generation, extremely high demand, and unplanned events like transmission line outages. In many scenarios, this firm capacity was supplied by renewable-energy-fueled combustion turbines, which could run on biodiesel, synthetic methane, hydrogen, or some other renewable energy resource to support reliable power system operation. The DOE Energy Earthshots Initiative recently announced by Secretary of Energy Jennifer M. Granholm includes the Hydrogen Shot, which seeks to reduce the cost of clean hydrogen by 80% to $1 per kilogram in one decade — an ambitious effort that could help reduce the cost of providing renewable firm capacity.

“When achieving a 100% renewable system, the costs are significantly lower if there is a cost-effective source of firm capacity that can qualify for the 100% definition,” Denholm said. “The last few percent cannot cost-effectively be satisfied using only wind, solar, and diurnal storage or load flexibility — so other resources that can bridge this gap become particularly important.”

Capital costs are the largest contributor to system costs at 100% renewable energy. Future changes in the capital costs of renewable technologies and storage can thus greatly impact the total system cost of 100% renewable grids. The speed of transition is also an important consideration for both cost and emission impacts. The scenarios with more rapid transitions to 100% renewable power were more costly but had greater cumulative emissions reductions.

“Looking at the low incremental system costs in scenarios that increase renewable generation levels somewhat beyond the reference solutions to 80%–90%, we see considerable low-cost abatement opportunities within the power sector,” Mai said. “The trade-off between power-sector emissions reductions and the associated costs of reducing those emissions should be considered in the context of non-power-sector opportunities to reduce emissions, which might have lower abatement costs — especially at the higher renewable generation levels.”

“The way the requirement is defined is an important aspect of understanding the costs of the requirement and associated emissions reduction,” Cole said. “For instance, if the 100% requirement is defined as a fraction of electricity sales, as it is with current state renewable polices, the cost and emissions of meeting that requirement are similar to those of the scenarios that have requirements of less than 100%.”

Additional Research Can Help the Power Sector Understand the Path Forward

While this work relies on state-of-the-art modeling capabilities, additional research is needed to help fill gaps in our understanding of the technical solutions that could be implemented to achieve higher levels of renewable generation, and their impact on system cost. Future work could focus on key considerations such as the scaling up supply chains, social or environmental factors that could impact real-world deployment, the future role of distributed energy resources, or how increased levels of demand flexibility could reduce costs, to name a few.

“While there is much left to explore, given the energy community’s frequent focus on using the electricity sector as the foundation for economy-wide decarbonization, we believe this work extends our collective understanding of what it might take to get to 100%,” Cole said.

Learn more about NREL’s energy analysis and grid modernization research.

Article courtesy of the NREL, the U.S. Department of Energy


Appreciate CleanTechnica’s originality? Consider becoming a CleanTechnica Member, Supporter, Technician, or Ambassador — or a patron on Patreon.


 



 


Have a tip for CleanTechnica, want to advertise, or want to suggest a guest for our CleanTech Talk podcast? Contact us here.

Continue Reading

Environment

Customers could end up paying for data centers’ energy costs in the absence of reform: Experts

Published

on

By

Customers could end up paying for data centers' energy costs in the absence of reform: Experts

A visitor observes a computer bay at the PA10 data center, operated by Equinix Inc., in Paris, France, on Thursday, Feb. 6, 2025.

Bloomberg | Bloomberg | Getty Images

In some advanced economies, electricity infrastructure and cost of utilities are undergoing structural changes because of artificial intelligence-driven demand for data centers.

In the process, U.S consumers could be paying higher utility bills because of the sector shifting costs to consumers, warned a latest paper by the Harvard Electricity Law Initiative.

Meanwhile in the U.K, residents may experience higher wholesale prices in light of a proposed reform to the electricity market that would favor data centers which harness renewable energy.

As pricing concerns emerge, regulation and energy grid reform will take center stage in managing energy prices and meeting changing energy needs.

‘Complex’ special contracts

Special contracts between utilities and data center companies are one of the ways higher costs associated with data centers may transfer onto everyday consumers, identified a report by the Harvard Electricity Law Initiative in March.

Such contracts “allow an individual consumer to take service under conditions and terms not otherwise available to anyone else.” In other words, they can be used to shift costs from data centers to consumers because of the subjectivity and complexity in those contracts’ accounting practices, the report stated.

Moreover, special contracts are approved by the Public Utilities Commission but tend to undergo “opaque regulatory processes” that make it difficult to assess if costs have been shifted from data centers onto the consumer.

To remedy this, the report recommended regulators tighten oversight over special contracts or completely do away with them and opt for existing tariff practices.

“Unlike a one-off special contract that provides each data center with unique terms and conditions, a tariff ensures that all data centers pay under the same terms and that the impact of new customers is addressed by considering the full picture of the utility’s costs and revenue,” according to the report.

Jonathan Koomey, a researcher in energy and information technology, concurs with the need for data centers to pay according to their usage of the energy grid.

“The key point, in my view, is that highly profitable companies who impose costs on the grid with big new loads should pay the costs created by those new loads,” Koomey told CNBC.

Beyond utility companies and regulators, “intervenors in the utility regulatory process also play a critical role,” Koomey said.

Intervenors can include a specific group of constituents or a large commercial or industrial customer who partake in proceedings. They may raise issues pertaining to customer service and affordability and ultimately allow for commissions to hear from a broad group of stakeholders.

“They often can dig deeper than the overburdened regulators into the projections and technical details and reveal key issues that haven’t yet surfaced in regulatory proceedings,” Koomey added.

Overbuilt infrastructure?

Another factor affecting utility prices is the excessive development of energy infrastructure.

Utilities and pipeline companies in the states of Virginia, North Carolina, South Carolina and Georgia are planning a “major buildout of natural gas infrastructure over the next 15 years,” potentially based on an overestimation of data center load forecasts, highlighted a report by the Institute for Energy Economics and Financial Analysis in January.

Proactive decisions on the part of utilities and regulators are needed to prevent ratepayers from being “on the hook” for overbuilt infrastructure, said the IEEFA report.

Policymakers across states have adopted a slew of measures to incentivize, curb and regulate the influx of data center development, from tax breaks to legislative bills, with a focus on ensuring non-data centers consumers do not bear undue costs, according to a report by the Gibson Dunn Data Centers and Digital Infrastructure Practice Group.

Zonal pricing

In the U.K, data centers and consumers face a different pricing challenge amid government plans to transform the country’s electricity market into a decarbonized, cost-effective and secure electricity system.

The zonal pricing scheme that is being explored under the government’s Review of Electricity Markets Arrangements would mark a shift away from uniform pricing to a split electricity market. Under the new framework, consumers in different geographical zones would be subject to different wholesale electricity prices based on the marginal cost of meeting demand at that location.

Modeling from consulting firm Lane Clark and Peacock suggests that Northern Scotland would experience lower wholesale prices owing to their high renewable penetration and relatively low demand.

The rest of the U.K, accounting for 97% of national electricity demand, is poised to see a rise in wholesale prices from the current national pricing model.

The impact on retail prices remains murky as yet.

“It is not clear how this may impact retail prices as wholesale prices are only one part of the overall electricity bill for consumers, and DESNZ still needs to make various decisions,” according to joint comments from Sam Hollister, Head of Energy Economics, Policy, and Investment and Dina Darshini, Head of Commercial and Industrial at Lane Clark Peacock’s energy transition division, LCP Delta.

The DESNZ is the U.K.’s Department for Energy Security and Net Zero.

Will data centers benefit?

While tech firms appear onboard with the lower costs that zonal pricing stands to offer, based on think tank research supported by Amazon, OpenAI and Anthropic, whether data centers do in fact stand to benefit from zonal pricing would depend on their type of operations, according to Hollister and Darshini.

Those potentially well-suited for zonal pricing include data center facilities that handle workloads that can be shifted in time or location, they said.

AI training for deep learning models is one such example. Such workloads can be scheduled during off-peak hours when electricity prices may be lower and synchronized with periods of surplus wind or solar power, which would reduce costs and alleviate grid congestion.

Similarly, data centers that do not need to be close to major urban centers or end users — such as those supporting hyperscale AI training, cloud and large-scale data storage facilities or scientific computing hubs — could also benefit from cheaper electricity when located in regions with high renewable generation and low local demand, Hollister and Darshini said.

However, “not all AI workloads are flexible — real-time inference tasks, such as those used in chatbots, fraud detection, or autonomous vehicles, require immediate processing and would not benefit from time-shifting,” they added.

Latency-sensitive applications such as financial trading and real-time streaming that require close proximity to users would also find zonal pricing “less viable.”

Boosting grid infrastructure

Proponents of zonal pricing point to the benefits of reducing the need to move energy over long distances.

But with the National Energy System Operator’s plans to increase network capability and connect more offshore wind, focusing on grid infrastructure is important, “and zonal pricing won’t eliminate those requirements,” according to Hollister and Darshini.

“It’s not just data centers that are going to need this additional capacity on the grid, they’re probably the most high profile ones, but EV charging is going to change the grid. National Grid as an organization have been talking about the change in the demand profile from EVs for a very long time,” David Mytton, a researcher in sustainable computing, told CNBC.

The demands on the energy grid posed by the electrification of vehicles is a challenge shared across the U.S. and U.K.

In the U.S., electric vehicles will constitute over half of all new cars sold by 2030 and is set to place a considerable strain on an aging energy grid system.

While the electricity consumption of U.S. data centers is growing at an increasing pace, a report by the Lawrence Berkeley National Laboratory published in December noted that this is playing out against a “much larger electricity demand that is expected to occur over the next few decades from a combination of electric vehicle adoption, onshoring of manufacturing, hydrogen utilization, and the electrification of industry and buildings.”

Given this, the infrastructural and regulatory reforms that emerge out of data center management would be helpful for an imminent era of changing electricity demand, said Mytton and fellow researchers.

Continue Reading

Environment

Tesla’s Cybercab and Semi sourcing disrupted by Trump’s tariffs, report says

Published

on

By

Tesla's Cybercab and Semi sourcing disrupted by Trump's tariffs, report says

A new report claims that President Trump’s tariffs have disrupted Tesla’s plan to source parts for the upcoming Cybercab and Tesla Semi production in China.

The trade war started by President Trump and his constantly changing tariffs has thrown a wrench in the plans of most supply chain managers worldwide.

Tesla is no exception.

For most of its manufacturing programs in the US, the American automaker imports a significant number of parts from China, Mexico, Canada, and Europe.

Advertisement – scroll for more content

This includes its upcoming vehicles: Cybercab and Tesla Semi.

Tesla aims to start production of the vehicles at Gigafactory Texas and a new factory in Nevada later this year and ramp up to volume production in 2026.

Reuters reports that Tesla has suspended plans to source certain parts for the upcoming Cybercab and Tesla Semi from China:

Tesla’s plans to ship components from China for Cybercab and Semi electric trucks in the United States were suspended after President Donald Trump raised tariffs on Chinese goods amid a trade war, said a person with direct knowledge.

According to the report, Tesla was ready to move ahead with the plan when Trump first increased the tariffs on China to 34%, but the automaker is suspending the specific sourcing plans after the most recent increases:

Tesla was ready to absorb the additional costs when Trump imposed the 34% tariff on Chinese goods but could not do so when the tariff went beyond that, leaving shipping plans suspended, said the person, who declined to be named as the matter is private.

Trump raised the tariffs on China to 145% last week, with some expectations announced on Friday — even though Trump later claimed there were no exceptions.

In response to the tariffs the US is imposing on China, the Chinese government reciprocated with its own tariffs on US goods, which resulted in Tesla stopping taking new orders for Model S and Model X vehicles in the country.

Electrek’s Take

I would take the report with a grain of salt since it is based on a single source, but it certainly makes sense.

The phrase “Trump’s tariffs have disrupted” could be followed by the name of virtually every major manufacturing company globally, and Tesla is no exception.

Due to Tesla’s vertical integration, Tesla shareholders have been claiming that the tariffs would be positive for Tesla, or at least not as bad as they would be for other automakers.

Tesla indeed has impressive vertical integration for the auto industry, but that’s in relative terms. Effectively, Tesla still uses a significant number of parts from other countries, especially Mexico, but also from China.

Mexico would be the most problematic for Tesla, as roughly 25% of the parts of all its vehicle programs built in the US originate from there.

The tariffs on auto parts from Canada and Mexico are currently paused for everything in the USMCA agreement, but Trump signaled that this is only temporary.

As for the tariffs on China, they primarily affect Tesla’s energy business, which relies on cheap Chinese battery cells, but Tesla also imports some Chinese parts for its cars and 145% tariffs will change that.

Tesla, like many other companies, has to start looking for alternatives.

Many of the problems come not only from the excessively high tariffs Trump is imposing on countries, but also from the fact that he keeps changing his mind and making exceptions, making it hard for companies to plan.

In this case, Tesla might have suspended plans with Chinese suppliers only to wait and see if Trump will back off the Chinese tariffs, if Musk can lobby for an exception with the President, whom he helped elect with $250 million in political donations, to shop for suppliers from other countries, or maybe, just maybe, do what Trumps claims his tariffs will do and manufacture those parts in the US.

For some reason, I have doubts about it being the last one, but you never know.

FTC: We use income earning auto affiliate links. More.

Continue Reading

Environment

Groundbreaking heavy equipment EVs (ha!) steals the show at bauma

Published

on

By

Groundbreaking heavy equipment EVs (ha!) steals the show at bauma

It only happens every three years, but it’s spectacular! I’m speaking of course, about bauma – one of the largest trade shows of any kind where heavy equipment manufacturers serving construction, forestry, mining, and more bring out their latest and greatest new job site innovations, and we’ve got a whole bunch of them here, on this special bauma edition of Quick Charge!

With more than two million square feet indoors and twice that outdoors, bauma hosts more than 600,000 guests from 200 countries to see 3,600 exhibitors’ hardware (and, increasingly, software). We’re only going to cover a sliver, but it’s a really cool sliver, you guys – enjoy!

Prefer listening to your podcasts? Audio-only versions of Quick Charge are now available on Apple PodcastsSpotifyTuneIn, and our RSS feed for Overcast and other podcast players.

New episodes of Quick Charge are recorded, usually, Monday through Thursday (and sometimes Sunday). We’ll be posting bonus audio content from time to time as well, so be sure to follow and subscribe so you don’t miss a minute of Electrek’s high-voltage daily news.

Advertisement – scroll for more content

Got news? Let us know!
Drop us a line at tips@electrek.co. You can also rate us on Apple Podcasts and Spotify, or recommend us in Overcast to help more people discover the show.

FTC: We use income earning auto affiliate links. More.

Continue Reading

Trending