Last week, we released a wide-ranging analysis estimating that more than 150,000 jobs could be needed in the United States to deploy “behind-the-meter” charging infrastructure for electric light-duty vehicles (LDVs) and medium- and heavy-duty vehicles (MHDVs) through 2032. The term “behind the meter” refers to the customer’s side of the electricity meter and the term “front of the meter” is used when talking about the utility’s side, where there’s infrastructure such as substations, transformers, and feeder lines (Figure 1).

For HDVs specifically, the new study estimated that the Environmental Protection Agency’s (EPA) proposed HDV Phase 3 greenhouse gas (GHG) standard could generate as many as 16,000 jobs by 2032, or about 10% of the national total. But that’s only part of the jobs story.

As we’ll explore here, when all the jobs to construct the infrastructure to channel megawatt-scale power to chargers at private depots and public charging plazas for battery electric trucks and buses are considered, the utility-side infrastructure in front of the meter is likely to require a workforce an order of magnitude larger than the workforce building out customer-side infrastructure.

Figure 1. Battery-electric MHDV charging infrastructure ecosystem.

Let’s look at a preliminary, top-down jobs estimate based on available national-level data. It’s sensitive to assumptions about how individual chargers are configured into charging stations, how expensive utility grid upgrades are at each charging station, and how utility investments translate into jobs in the economy.

Still, we make generally conservative assumptions and the eventual number of jobs created could be larger. First, while the total number of chargers is based on a projected level of zero-emission vehicle adoption supported by the EPA HDV GHG Phase 3 proposal, in previous analysis we found that market forces, aided by Inflation Reduction Act (IRA) incentives, can support a larger number of zero-emission MHDVs and may draw even greater investments in charging infrastructure. Second, we do not fully account for possible infrastructure investments upstream from the distribution substation to support the largest multi-megawatt installations with peak loads greater than 10 MW.

We arrived at the job estimates in Figure 2 by first aggregating the nameplate capacity of 100 kW, 350 kW, and 1 MW chargers into a total number of hypothetical charging stations. The cost of grid upgrades and connection costs for charging stations were taken from previous ICCT research and utility upgrade cost estimates by the National Renewable Energy Laboratory (NREL). Next, we converted dollars invested in distribution grid capacity into a total number of direct and indirect jobs in the United States required and supported by these investments; this is based on an economic impact analysis of a utility’s substation transformer upgrade costs and other high-level utility infrastructure economic impact studies (here and here). Direct jobs are those related to the core construction and electrical work, for example installing substations and laying feeder lines; indirect jobs are upstream manufacturing, administrative, and other jobs not immediately involved in utility upgrade activities.

Under the most optimistic level of electrification likely to occur with the proposed EPA HDV Phase 3 GHG rule, we project more than 493,000 overnight 100 kW chargers, nearly 17,000 fast 350 kW chargers, and around 12,800 ultra-fast 1 MW chargers by 2032. We estimate up to $21 billion would need to be invested in distribution grid capacity to support these chargers, also by 2032.

These calculations, combined with the behind-the-meter jobs our colleagues estimated, suggest approximately 262,000 direct and indirect full-time equivalent jobs would be necessary to support the most optimistic rates of electrification to meet the EPA proposal by 2032 (Figure 2). More than 94% of these jobs come from what would be needed for utility-side infrastructure deployment. These front-of-the-meter jobs are wide-ranging and include substation construction, laying conduit, wiring, installing transformers and meters, laying feeder lines and their foundations, and manufacturing electrical grid components and assembly of these assets.

Figure 2. Estimated direct and indirect jobs created from infrastructure investments in MHDV electrification under the most optimistic rates of electrification to meet the EPA Phase 3 GHG proposal by 2032.

Billions of dollars in public investments are already funding charging infrastructure deployment at the federal and local levels. Private sector investments from companies such as TerraWatt Infrastructure, WattEV, Forum Mobility, and GreenLane reflect this growing industry.

Our estimates suggest the vast majority of charging infrastructure job creation will occur not in the manufacturing and installation of chargers themselves, but in the distribution grid assets that power the chargers. Finalizing the EPA Phase 3 proposal would generate significant momentum toward this job creation and the potential is even greater when accounting for the additional market potential shaped by IRA incentives. It’s key that utilities and regulators not only recognize the potential in constructing infrastructure assets in front of the meter, but that they begin planning to deliver front-of-the-meter assets and prepare their workforce in a time frame consistent with the EPA Phase 3 proposal and beyond.

About this event

The ICCT in collaboration with NITI Aayog is organizing a one-day workshop on Low Emission Zones (LEZs) in Indian cities. LEZs, designated areas where certain vehicles, particularly those with high emissions, are restricted or prohibited, have proven effective in reducing air pollution worldwide. Additionally, LEZs play a crucial role in promoting the adoption of electric vehicles, aligning with NITI Aayog’s proactive advocacy in this area.

Our workshop, in association with the Raahgiri Foundation & SUM Network, is scheduled for February 19, 2024 in New Delhi, and aims to raise awareness about LEZ benefits, discuss best practices for LEZ implementation in Indian cities, and formulate a roadmap for future actions.

The workshop will include discussions on the following topics:

1. The benefits of LEZs for air quality and public health
2. Case studies of successful LEZs from around the world
3. Experiences in implementing LEZs in Indian cities
4. Legal pathways for developing LEZs in India
5. The role of technology in supporting LEZ implementation

The workshop will, we believe, significantly contribute to ongoing efforts to improve air quality and enhance EV adoption in Indian cities.

In July 2023, the International Maritime Organization (IMO) adopted a revised strategy that calls for reducing greenhouse gas (GHG) emissions from ships to net-zero by or around 2050. While the revised strategy is not legally binding, the measures used to implement it can be, and in many ways it’s the stringency of these measures that will ultimately determine shipping’s contribution to future global warming.  

Earlier this week, our colleague highlighted the need for measures that limit emissions from ships measured on a life-cycle basis, the well-to-wake (WTW) emissions. With this blog post, we show how one proposed measure, the GHG Fuel Standard (GFS), can be used to reduce emissions in line with the IMO’s revised 2023 strategy or with a pathway consistent with limiting warming to 1.5°C. 

The GFS being designed now will require ships to use fuels that emit fewer WTW GHG emissions until there is a complete transition to all zero-emission fuels. This GFS is meant to encourage the adoption of new fuels including renewable e-fuels (hydrogen, ammonia, and methanol) and sustainable biofuels; by setting limits on the GHG emissions intensity of fuels, it will drive investments in production capacity and infrastructure for new fuels. One effective design of the GFS would identify the date by which the WTW GHG intensity of marine fuels is to reach zero and include interim GHG intensity targets (at regular intervals) to keep the sector on a steady course toward its final goal. Here we use ICCT’s new Polaris model to estimate the WTW GHG intensity reductions that would be needed to achieve net-zero by 2050 in a pathway consistent with the 2023 IMO GHG strategy. Polaris is a global maritime emissions projection model that reports tank-to-wake (TTW) and WTW emissions as carbon dioxide equivalents (CO₂e) based on the 100-year or 20-year global warming potentials of CO₂, methane, nitrous oxide, and black carbon (we exclude black carbon in this particular analysis because it’s not accounted for in the guidelines on life-cycle GHG intensity of marine fuels). 

Figure 1 shows the straight-line GFS trajectory that satisfies the emissions reduction targets in the 2023 IMO GHG strategy and an S-curve trajectory that would stay below the cumulative emissions limit for 1.5°C estimated here. The GFS trajectories were determined based on the business as usual (BAU) predicted energy use from the Polaris model and target emissions in the 2023 IMO strategy and 1.5°C aligned pathways (using 100-year global warming potentials, GWP100). For 2030, the 2023 IMO strategy set a goal of at least a 20% reduction in absolute GHG emissions compared to 2008 levels, and “striving for” a 30% reduction; for 2040, the GHG reduction goals are at least 70% and striving for 80% below 2008 levels. Predicted energy use from Polaris goes from 10.7 EJ in 2023 to 14.5 EJ in 2050, and we estimated the baseline GHG intensity of marine fuels at 92.5 gCO₂e/MJ from shipping’s fuel mix in 2019 using ICCT’s Systematic Assessment of Vessel Emissions (SAVE) model and excluding black carbon emissions. 

Figure 1. Well-to-wake GHG intensities of marine fuels required to align the IMO GHG Fuel Standard (GFS) with IMO’s 2023 GHG strategy and a 1.5 °C-compatible emissions trajectory.

As Figure 1 illustrates, to achieve the minimum IMO targets, the GHG intensity of marine fuels will have to reduce by 18% to 76 gCO₂e/MJ by 2030 and by 72% to 26 gCO₂e/MJ in 2040 compared to the 2019 baseline. For the “striving” scenario, reductions in 2030 and 2040 will have to be 28% to 67 gCO₂e and 81% to 17 gCO₂e/MJ, respectively. A 1.5°C-aligned pathway requires 32% reductions in WTW GHG intensity in 2030 to 63 gCO₂e/MJ and 99% in 2040 to nearly zero GHG emissions. All pathways require 100% reductions by 2050. Following the GHG intensities in Figure 1 would result in the absolute emissions reduction pathways presented in Figure 2.

Figure 2. Absolute well-to-wake GHG emissions trajectories under each scenario.

Table 1 specifies the GHG intensity limits needed to follow the absolute emissions reduction pathways in Figure 2. This table can be used by policymakers as they develop the GFS.

Table 1. Well-to-wake GHG intensities (gCO₂e/MJ) and reductions in well-to-wake GHG intensities of marine fuels from the 2019 fossil fuel baseline needed to align the GFS with different emissions trajectories.

The cumulative WTW CO₂e emissions compared to “well-below” 2°C (interpreted by us as keeping warming to not more than 1.7°C) and 1.5°C limits are presented in Figure 3. Achieving the minimum or striving IMO targets is consistent with limiting warming to well-below 2°C and the S-curve is consistent with 1.5°C.

Figure 3. Cumulative well-to-wake GHG emissions from 2020-2050 implied by each scenario.

The 2023 GHG strategy also includes a target for the uptake of zero or near-zero GHG emission fuels and/or energy sources that should represent at least 5% (striving for 10%) of the energy used by international shipping by 2030. Achieving even the minimum 5% energy target in 2030 would require 0.6 EJ of zero/near-zero fuels. To put this target into perspective, 0.6 EJ represents around 14% of global biofuel demand in 2022 (~4.3 EJ), whereas shipping (~11 EJ/year) represents about 2.5% of global energy demand (~442 EJ/year). When considered in the context of the limited availability of sustainable advanced biofuels for use in shipping, this underlines the importance of scaling up e-fuels to achieve IMO’s target. 

The stronger the GFS targets, the greater the demand for zero/near-zero GHG emission fuels, the fewer GHGs emitted by the sector, and the greater the likelihood that shipping aligns with both IMO’s GHG strategy and the Paris Agreement. The next opportunity for IMO delegates to contribute to the design of the GFS is at the meeting of the 16th Intersessional Working Group on GHG emissions from ships in March 2024. 

LNG is primarily methane, a powerful GHG that leaks throughout the production and combustion processes—including unburned methane that escapes from marine engines, known as methane slip. As a result, a new ship that’s built to sail on LNG instead of conventional fuels can emit more GHGs on a life-cycle basis, depending on the engine technology and how the LNG is produced.

Figure 1 depicts methane emissions from international shipping in 2021 by ship type and engine type, estimated using ICCT’s Systematic Assessment of Vessel Emissions (SAVE) model (2021 is the most recent year for which we have such data). Liquefied gas tankers, mostly LNG carriers, were the source of 82% of the emissions and were followed by offshore vessels, RoPax ferries, cruise ships, and container ships. Accordingly, the map of methane emissions from LNG-fueled ships in Figure 2 shows they are highly concentrated along LNG trade routes.

Figure 2. Methane emissions from LNG-fueled ships in 2021, aggregated at 0.5 * 0.5 degrees. Sources: Spire (AIS data) and S&P Global (ship characteristics data). This map is without prejudice to the status of or sovereignty over any territory, to the delimitation of international frontiers and boundaries and to the name of any territory, city, or area.

Installations of high-methane-slip LPDF 4-stroke engines are on the rise (Figure 3). More than half of cruise ship capacity by gross tonnage to be built between 2023 and 2025 will run on LNG using these engines, according to IHS Markit (nka S&P Global) data as of July 2023 (the latest available). While a small share of all ships globally, cruise ships have disproportionately high per-ship average emissions because of their hotel and leisure facilities and leaky engines. About the only slightly bright spot here is that the relative share of LPDF 4-stroke engines among engine types in LNG-fueled ships is declining amid growing use of medium-methane-slip LPDF 2-stroke engines that are increasingly used in gas tankers and the low-methane-slip HPDF 2-stroke engines found in most new LNG-fueled container ships and vehicle carriers.

Keep in mind, also, that the real-world methane emissions from ships may be higher than is currently understood. Existing emission inventories, including ours, rely on methane emission factors derived from limited on-board or laboratory measurements of engines. ICCT is leading a project called Fugitive and Unburned Methane Emissions from Ships (FUMES) to estimate real-world methane emissions from LNG-fueled ships using drones, helicopters, and in-stack sensors. Studies like this will more accurately measure methane slip and, if reflected in policies, will help account for and control the climate impacts of LNG-fueled ships. Watch out for that study later this month.

Given that ships can remain in service for decades—the average ship is now more than 22 years old—many of the ships built today will probably still be in the fleet in 2050, when the IMO aims to achieve net-zero emissions. This makes regulations on them crucial, and starting in 2026, the European Union (EU)’s Emissions Trading System (ETS) will cover methane emissions from ships entering or departing EU ports. A separate regulation, FuelEU maritime, will require ships to reduce the life-cycle GHG intensity of on-board energy use starting in 2025. With the FuelEU maritime regulation in effect, ships could only use LPDF 4-stroke engines with 100% fossil LNG if they also use credits from overperforming ships in their fleet or buy credits from other ships; absent that, they will have to use a mix of fossil LNG and qualifying bio- or synthetic fuels. This is because the European Union included methane slip and upstream well-to-tank emissions in the regulations.

The IMO and other multilateral and national authorities could not only follow the EU example but consider more ambitious targets than the European Union has set thus far. IMO delegates are currently developing a GHG Fuel Standard (GFS) to regulate the life-cycle GHG intensity of marine fuels that’s similar to the FuelEU maritime regulation. The earliest the GFS could enter into force is 2027, and if it is to spur emissions reductions that would achieve IMO’s 2050 goal, the GFS will have to break from historical patterns of lagging behind the European Union and be more stringent from the start. After all, the EU regulation aims for 80% reduction in the GHG intensity, not 100%, by 2050. In the meantime, regions or countries could set more ambitious regulations that target methane pollution in their waters. For the more than 150 countries that have signed on to the Global Methane Pledge, reducing methane emissions from ships that call on their ports or sail in their waters would help to achieve the goal of reducing global methane emissions by 30% between 2020 and 2030.

And to be clear, alternatives to LNG are out there. Methanol avoids the methane slip problem and is liquid at room temperature. Other options expected to be available in the longer term include hydrogen fuel cells or batteries. For LNG carriers that continue to use LNG as their fuel, low-methane-slip HPDF engines are a better choice for the environment than the LPDF engines that have long dominated the class. Regulations like a strict GFS that could support the adoption of fuels with lower life-cycle GHG emissions.

In a blog post we’ll publish in a couple of days, my colleagues use our new Polaris model to estimate the life-cycle GHG intensity reductions that would be needed until 2050 to align with IMO goals or with the Paris Agreement. And at the same time, multilateral and national regulators can be ambitious in their own efforts to limit GHG emissions, including methane, from marine fuel.

Last week brought long-awaited tax-credit guidance about sustainable aviation fuels (SAFs) from the U.S. Treasury Department. It found that, as configured, the Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) model does not “satisfy the requirements to calculate the emissions reduction percentage” to determine which fuels qualify for the lucrative credit for SAFs in the Inflation Reduction Act (IRA). In the brief guidance, Treasury also tasked multiple agencies with collaborating on an update of GREET that would fit the requirements. While this interagency working group might seem like a nod to the agricultural industry and corn ethanol producers who have been pushing for use of this model, there’s still little clarity about how life-cycle greenhouse gas (GHG) emissions will ultimately be calculated for different SAFs.

GREET can be a useful analytical tool for evaluating the life-cycle emissions of a variety of different fuels on a consistent basis, but it’s always dependent on the quality of the assumptions and inputs. In past work, the ICCT explained how using GREET can allow users to incorporate a variety of optimistic external assumptions and inputs that have not undergone regulatory scrutiny. The model has many possible configurations and data sources, and its impact on the SAF tax credit will heavily depend on the three key data inputs and assumptions discussed below. All of these will be determined by the interagency working group that will finalize the version of GREET used for the tax credit:

1. The indirect land-use change emission factor used for crop-derived biofuels. Demand for biofuels can lead to cropland expansion, but the magnitude of the expansion and the associated emissions remain the subject of vigorous academic debate. Depending on how GREET is configured, the estimated indirect land-use change (ILUC) emissions for SAF’s can range from one-quarter to one-third of the values assessed by the U.S. Environmental Protection Agency (EPA) for the Renewable Fuel Standard, by California for its Low-Carbon Fuel Standard, and by the International Civil Aviation Organization (ICAO) for its Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA).

To qualify as a SAF under the IRA, a fuel’s life-cycle emissions must be below approximately 45 grams CO2e per MJ of fuel. The difference between assuming an ILUC emission factor of ~7 gCO2e/MJ and ~30 gCO2e/MJ for a feedstock like soy can make a big difference in the total emissions, all without the producer having demonstrated any improvements in their fuel-conversion process. (To view a range of possible values, see Figure 2 here.) A key outcome of the interagency working group process will be the determination of which emission factor will be used for feedstocks like corn and soy. Will it be a low estimate selected from the literature, an estimate consistent with the other regulatory assessments, or something in between?

2. The guidance around soil carbon modeling and climate-smart agricultural practices. Though carbon offsets and offset programs have recently taken somewhat of a beating in the public imagination, they’ve nevertheless attracted substantial interest from the Biden Administration, which has described activities like planting cover crops and reduced tillage of crops that have been shown to improve soils as “climate-smart” practices. However, the exact change in soil carbon that results from such practices is uncertain and difficult to credit, and a recent article in Science highlighted warnings from soil carbon modelers about the uncertainties and research gaps in their current work.

This is important because one module in the GREET model allows biofuel producers to use modeled soil carbon change estimates to credit individual biofuel projects. The size of these credits can be substantial and can allow producers to claim large emissions reductions. Rather than a conventional supply chain LCA, this module looks into the future to determine shifts in soil carbon content based on an assumed 30 years of consistent practices. Crediting these reductions would thus necessitate a new dimension to Treasury’s guidance, as Treasury would have to verify the shifts in soil carbon, ensure their permanence, and develop a system for clawing back tax credits if producers fail to keep up the promised practices for the full 30 years. Given that many existing carbon-offset schemes have recently been criticized for the lack of rigor of their soil carbon offsets, Treasury may opt to steer clear.

3. The guidelines for book-and-claim accounting for natural gas and electricity. There’s been a lot of recent focus on the “three pillars” of demonstrating renewable electricity use as it pertains to producing green hydrogen for the IRA’s 45V tax credit. Such focus is also relevant for aviation. What constitutes a “renewable” electron? Under “book-and-claim” accounting, a fuel producer can purchase the rights to renewable energy somewhere else in the economy and attribute it to their specific process. The three pillars help to create guardrails to ensure that those renewable attributes are (1) truly additional to the status quo; (2) not being double counted; and (3) are closely correlated with the energy demand for the fuel pathway. If Treasury determines that hydrogen producers must demonstrate the three pillars for the renewable electricity used to generate hydrogen, will it hold renewable inputs to SAF production to the same standard?

Depending on how flexible the guidelines are for SAF’s, producers may opt to meet their GHG reduction threshold outside of their immediate supply chain by purchasing the rights to renewable electricity or natural gas generated somewhere else. It’s even conceivable that with a particularly loose interpretation of book-and-claim without additionality safeguards, a SAF producer could purchase the rights to highly GHG negative “moo hydrogen” made from dairy manure as an input to their SAF pathway. Even if the additionality of that moo hydrogen was dubious (say, for example, the dairy biogas facility long predates the IRA), the carbon offsets for the avoided methane could be used to adjust the carbon intensity of SAF pathways looking to cross the 50% GHG reduction threshold.

As the above helps to illustrate, suggesting that GREET is a kind of definitive “method” of conducting an LCA is not much different from suggesting that Microsoft Excel is the most accurate method for conducting an LCA or that Microsoft Word is the best tool for writing a screenplay. Treasury’s recent guidance provides no answers about how the United States will ultimately handle these thorny-but-important questions. Answering them is not just a matter of collecting data and updating GREET, but also establishing the government’s tolerance for risk in assessing what constitutes a GHG reduction and what behavior justifies a tax credit. Until those questions are answered in March, we’re left with the status quo.