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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


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Tesla lowers price of ‘Full Self-Driving’ to $8,000, down from $12,000

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Tesla lowers price of 'Full Self-Driving' to ,000, down from ,000

Tesla has once again lowered the price of its Full Self-Driving software by $4,000, now costing $8,000, down from a previous price of $12,000 in the US.

Prices were also lowered in Canada, where the system used to cost $16,000CAD, and now costs $11,000CAD.

In addition to the price drop, Tesla has eliminated “Enhanced Autopilot” as an option, which previously cost $6,000. For owners who already have enhanced autopilot, the cost to upgrade to FSD is now $2,000, down from $6,000.

Tesla has been doing a lot of price cuts lately, including dropping the price of most of its vehicles by $2,000 just a day ago.

It also cut the price of its FSD subscription service in half, to $99/mo, just a couple weeks ago.

That new subscription price suddenly made FSD’s $12k price seem quite steep, as someone would need to subscribe to FSD for ten whole years before paying $12k in total cost – and that’s not including the time value of money.

So it seemed inevitable that people would lean towards subscriptions, rather than upfront purchases, after that price drop.

Now, to make the prices a little closer, Tesla dropped the price of FSD to $8,000 – or 6 2/3 years worth of subscriptions at $99/mo. A little more reasonable, though still longer than many people own a car (and, again, one should account for the time value of money).

All of these prices are down significantly from the highest price FSD has ever sold for, which was $15k from late 2022 until late 2023 when it dropped the price back to $12k.

Tesla CEO Elon Musk has repeatedly said that as FSD becomes more capable, it should also go up in price to reflect its greater value. Previously, FSD price increases were largely associated with software updates that added new capability to the system.

Musk even went as far as to say that this means Tesla cars with FSD are “appreciating assets,” potentially worth $100-200k due to their value as robotaxis. Though Tesla only uses those values when it’s convenient, considering FSD much less valuable when offering trade-in estimates to owners.

But on a more practical business level, this move to lower FSD prices probably has less to do with the system’s capabilities and more to do with boosting revenue during a difficult time for the company, having just posted bad quarterly delivery numbers and laying off 10% of its workforce. A lower price could incentivize owners to pony up for software which had previously mostly gone up in price, giving Tesla a free cash infusion.

The system’s capabilities have been changing, too. Tesla has been pushing FSD more lately, ever since the release of the “mind-blowing” FSD v12. The new version changes the system significantly on the back-end, finally using machine learning neural nets to analyze Tesla’s vast amounts of driving data to teach cars how to drive themselves.

With Tesla’s confidence in the new system, the company rolled out a free one-month trial of FSD to all Teslas in the US, basically encompassing the month of April.

It has also started calling the system “Supervised Full Self-Driving,” a somewhat self-contradictory name that nevertheless is more accurate given that FSD is still a “Level 2” system that does not ever actually take full responsibility for the dynamic driving task (that only happens with level 3+ systems, like Mercedes’ DRIVE PILOT or Waymo).

Today’s price drop hasn’t been echoed in all other territories. It’s still listed at £6,800 in the UK and 59,600kr in Norway, same as it was before today’s price drop. FSD has generally been somewhat cheaper in Europe than the US after taking into account exchange rates, because it also has more capabilities in the US than in other countries, but after today’s price cuts, it’s actually more expensive in some EU countries (like the UK, where exchange rate puts it at ~$8.4k USD equivalent) than in the US, despite lower capabilities.

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First ever electric semi truck rides into Mexico with SDG&E

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First ever electric semi truck rides into Mexico with SDG&E

San Diego Gas & Electric (SDG&E) says the maiden voyage of their Class 8 heavy-duty electric semi marks the first time an electric semi has crossed the border hauling a standard load, marking an important milestone as the two nations move toward a net zero future.

The electric semi truck – one of 11 Peterbilt 579EV Class 8 trucks bought by San Diego-based Bali Express last year – made its first trip to Mexico carrying an unspecified load of goods through the Port of Entry at Otay Mesa, which connects Southern California to the city of Tijuana, Mexico.

Bali Express’ electric trucks will utilize SDG&E’s recently activated HD charging infrastructure to provide “reliable and affordable” electric freight options for medium and heavy-duty EVs crossing the US/Mexico border.

The SDG&E-powered chargers were partially funded through a $200,000 grant from the California Energy Commission’s Clean Transportation Program. That program has put more than $1 billion to alternative fuel and vehicle technology projects designed to improve public health while bringing both environmental and economic benefits to communities throughout the state.

Those sentiments were echoed by San Diego Mayor Todd Gloria. “The historic crossing of this electric freight truck symbolizes San Diego’s commitment to innovation, cross-border cooperation and our binational community,” said Gloria, in a statement. “We’re not just reducing emissions, we’re building a cleaner future for people living near our border, and leading the way in international trade and environmental responsibility.”

Meanwhile, Executive Director of SDG&E Caroline Winn called the new charging corridor, “an example of how collaboration can create new and innovative ways to rethink how to move transportation systems toward electrification.”

The Peterbilt 579EV trucks have an 82,000 lb. GCWR and is powered by the same 670 hp Meritor 14Xe “epowertrain” used in the PACCAR Kenworth t680e that debuted back in 2022. That system integrates electric motors and drive axles into a single unit, making it easy for manufacturers to electrify their fleets by maintaining existing (re: ICE) axle mounting hardware.

The big Petes have approx. 150 miles of range and are capable of fully charging their massive, 400 kWh batteries in about 3 hours.

Electrek’s Take

San Diego Gas & Electric (SDG&E) and Bali Express have announced the maiden voyage to Mexico of a U.S. Class 8 heavy-duty electric truckload; image by Bali Express, via Mexico Now.

The California Air Resources Board (CARB) has approved a landmark plan to end the sale of gas-powered vehicles by 2035. And, while California is just one state, it’s important to remember that, as California’s fleets go, so too go the fleets of Mexico, Arizona, Colorado, Washington State, and others.

If we’re lucky, the whole country will be electric-only well before then.

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Liebherr electric excavator reaches million ton milestone, scores more orders

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Liebherr electric excavator reaches million ton milestone, scores more orders

This massive Liebherr electric excavator reached a major operational milestone earlier this month when it moved its one millionth tonne of dirt. And now, its buyers want more!

That’s right, gang – since we first covered the converted mining excavator back in January it’s been hard at work. And now, after its initial 90 day “break-in” period operating at partial capacity while the site team familiarized themselves with the new tech, it’s operating at full speed at Fortescue’s Christmas Creek mine in Western Australia.

The Liebherr is working so well, in fact, that Fortescue is planning on order two more examples of the mighty electric earth-mover.

“This is such an exciting milestone for Fortescue and our decarbonisation journey. Importantly, we’ve been able to achieve this while maintaining our high safety standards,” says Fortescue Metals CEO, Dino Otranto. “We will have two additional electric excavators commissioned by the end of April. Once we decarbonize our entire fleet, around 95 million liters of diesel will be removed from our operations every year, or more than a quarter of a million tonnes of carbon dioxide equivalent.”

Big work needs big power

Liebherr and Fortescue repower R 9400 excavator to electric configuration
The repowered Liebherr R 9400 E excavator at Fortescue’s Christmas Creek mine; via Liebherr.

Moving more than a million tons of earth and rock takes a lot of energy. To keep its batteries topped off, the re-powered Liebherr R 9400 E electric excavator operates off blend of renewable solar power and a 6.6 kV substation pumping electrons through more than two kilometers of high voltage trailing cable.

Eventually, though, Fortescue plans to power its equipment completely from sustainable sources. “In line with our commitment to eliminate emissions across our mining operations,” reads the company’s statement. “The intention is that all electrified mining equipment will eventually be 100 per cent powered by renewable electricity.”

Electrek’s Take

Because Liebherr takes a modular approach to building its larger mining equipment, repowering a diesel-drive excavator like the R 9400 can be completed in a matter of weeks; courtesy Liebherr.

Covering an electric pilot program is always fun, but all too often the results of these initial experiments aren’t publicized – or else, don’t directly lead to sales. To their credit, Liebherr is lucky to have a customer in Fortescue that’s willing to put their cards on the table here, trumpeting the re-powered excavator’s success and even announcing its plans to order two more electric machines publicly.

They won’t have to wait long, either. Because Liebherr takes a modular approach to building its larger mining equipment, a diesel-drive excavator like the R 9400 can be completely re-powered to electric in a matter of weeks.

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