Hydrogen (H2) presents a vital opportunity for decarbonizing the road transportation sector in the United States. Since the United States has the world’s largest economy, its decarbonization is essential for attaining global greenhouse gas (GHG) emissions reduction of the magnitude needed to fight climate change. Such efforts need to be undertaken on the federal, state, and municipal levels.

Venera N. Anderson

Co-author: Raqib A. Chowdhury (M.S. Candidate in Energy Policy and Climate. The Johns Hopkins University)

Hydrogen (H2) presents a vital opportunity for decarbonizing the road transportation sector in the United States. Since the United States has the world’s largest economy, its decarbonization is essential for attaining global greenhouse gas (GHG) emissions reduction of the magnitude needed to fight climate change. Such efforts need to be undertaken on the federal, state, and municipal levels. Decarbonization is broadly defined as the decrease in the carbon intensity of an economy (Meyer, 2020). The Kaya Identity equation describes carbon intensity as carbon dioxide (CO2) emissions/energy. The Kaya Identity relates the global CO2 emissions to population, Gross Domestic Product (GDP) per capita, CO2 emissions/energy (carbon intensity), and energy/GDP (energy intensity) (Andrews & Jelley, 2007).

According to Economist (2021b), “only a holistic, multifaceted approach to decarbonization is likely to succeed” (p. 12). In other words, decarbonization efforts in all sectors of the economy can help address climate change. Due to the significant dependence on petroleum-based fuels, the transportation sector, in particular, faces substantial hurdles in lowering its carbon dioxide emissions. Gross (2020) states that the sector “is the least-diversified energy end-use sector, dominated by oil” (p. 4). For example, in 2019, petroleum-based fuels accounted for 92% of US transportation. The US transportation sector was responsible for the most significant source (28%) of US emissions versus the power sector, which contributed to a 25% share of US emissions (Saundry, 2021b). Andrews and Jelley (2007) assert that “to obtain deeper cuts in emissions will require lowering the carbon intensity of the fuels” (p. 442). Therefore, eliminating US emissions from the transportation sector will be crucial to meeting IPCC reduction mandates (IPCC, 2022) to avoid climate change.

As a valuable player in reducing carbon intensity, hydrogen may complement other low-carbon technologies and energy efficiency improvements in the US decarbonization efforts, especially in the road transportation sector. From a net-zero target perspective, the importance of hydrogen is manifold. "[While] not in itself the solution to abate all emissions across sectors, hydrogen uniquely complements and enables other decarbonization pathways such as direct electrification, energy efficiency measures, and biomass-based biofuels" (Hydrogen Council, 2021, p.13). Different factors, such as technological, infrastructural, economic, political, and standards (safety and fueling protocols) related to hydrogen deployment in the US road transportation sector, will be vital in achieving favorable decarbonization outcomes.

Hydrogen, the lightest element, is the most abundant element available in the universe. Hydrogen exists in gaseous form at normal pressure and temperature. However, it turns into liquid at minus 253°C (or minus 423°F). In the solar system, Sun consists of hydrogen and helium gases. On Earth, hydrogen exists only in compound form with other elements, such as gases, liquids, and solids (EIA, 2021). As the simplest element, hydrogen has many appealing physical properties. First, it has a high energy density by mass. One kilogram of hydrogen stores about three times (33.3 kWh or 120 MJ/kg) the energy content of one kilogram of gasoline (12.2 kWh or 44 MJ/kg). Tesla's new 4680 lithium batteries may achieve, at a maximum, 300Wh/kg. Some of the future solid-state batteries will only deliver less than 1kWh/kg, which is a tiny fraction of hydrogen's energy density by mass (DOE, 2020a: Neil, 2022). Second, hydrogen has significant environmental and health benefits. For example, hydrogen does not produce carbon monoxide or sulfates when burnt in the air except for a few nitrogen oxides. When hydrogen is used in a fuel cell (described more in Section 3), it emits nothing more than water (Economist, 2021).

Due to the lack of the elemental form of hydrogen on Earth, hydrogen has to be separated from the hydrogen-containing feedstock (fossil fuels, water, biomass, or waste materials) with an energy source (DOE, 2020a). Unfortunately, due to the laws of thermodynamics, it takes more energy to derive hydrogen than hydrogen provides when the element is converted into usable energy (Economist, 2021a, p.19). In other words, the current hydrogen production is a very energy-intensive and costly process. Depending on diverse resources and technological methods, hydrogen can be classified into black (made with coal); gray (made with natural gas), blue (same technologies with added carbon capture and sequestration (CCS)); green (electrolyzers with renewable energy); pink (electrolyzers with nuclear power); and turquoise (pyrolysis through heating methane) (Economist, 2021a). The most common "large-scale production technologies" are the following: natural gas steam methane reforming (SMR); nuclear high-temperature electrolysis (HTE); biomass gasification, and low-temperature electrolysis (LTE), which uses variable renewable energy, and gasification of coal. Other hydrogen production technologies are under development or available with different maturity levels or costs (Ruth et al., 2020; SGH2 Energy, 2022).

The current main uses of hydrogen are concentrated in the following applications: 1) as a catalyst and chemical feedstock, 2) as a chemical in ammonia (fertilizer) production, 3) in petrochemical and refinery processing, and 4) as a hydrogenating agent in drug and food production. Like electricity, hydrogen can be used as an energy carrier (fuel) to move, deliver, and store energy from other sources (DOE, 2020a). Presently, hydrogen is not widely used as a fuel but has enormous potential to emerge as a low-carbon fuel option for electricity generation, manufacturing, and transportation sectors (DOE, 2020a; EIA, 2022).

This study focuses explicitly on integrating hydrogen, as an energy carrier, into the US road transportation sector. It primarily focuses on medium-and-heavy-duty vehicles, which travel long distances (regional/intercity buses, trucks) and light-duty vehicles (light-duty trucks and high-utilization rate passenger cars, i.e., taxis). The analysis is structured into five main sections. After the introduction in Section 1, Section 2 describes the qualitative and quantitative methods employed in the paper. Section 3 explains the challenges and opportunities of hydrogen deployment in the road transportation sector. Section 4 outlines the strategy for using hydrogen in the road transportation sector as a part of the US decarbonization strategy. Section 5 concludes, addresses limitations, and offers further research suggestions. The following section describes hydrogen technology and its potentially important role in the US economy.

The analysis in this research paper builds upon different domestic and international case studies and quantitative indicators to present a strategy of using hydrogen in the road transportation sector as a part of the US comprehensive effort to decarbonize its economy. In addition, the paper’s methodology is informed by the US National Renewable Energy Laboratory’s (NREL) methods for estimation of hydrogen’s economic potential as an energy carrier, a transportation fuel for light-duty fuel-cell electric vehicles (FCEVs), and medium-and-heavy-duty FCEVs in the contiguous United States (Ruth et al., 2020). NREL uses resource analysis (Brown et al., 2016) to estimate the economic potential of hydrogen for the United States. In the analysis, economic potential represents a subsection of technical potential and serviceable consumption potential, which includes only the amount of the resource that can be sold at a profit. Technical potential, in turn, is a part of resource potential, which is constrained by the resource’s energy content and theoretical physical potential. Further, serviceable consumption potential is a subset of the total consumption potential, representing the maximum amount of hydrogen’s theoretical consumption (Ruth et al., 2020). The relationships are illustrated in Figure 1 and Figure 2.

NREL defines the economic potential of hydrogen as "the quantity of hydrogen expected to be available at prices lower than other options to meet each end-use requirement" (Ruth et al., 2020, p.12). Its researchers estimate the economic potential for hydrogen as the market equilibrium between demand and supply by utilizing microeconomic analytical methods (Brownlie and Lloyd Prichard 1963; Schwartz 2010). The researchers calculate the economic potential for every hydrogen application in the national market and find the threshold price at which point hydrogen may compete with other market options. NREL uses 2050 as the single target year for all hydrogen applications in the United States to make the analysis possible. This approach corresponds with the goals of the 

Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050

 (DOS, 2021b). In addition, the hydrogen market sizes are reported on a mass basis (in a million metric tons (MMT) of hydrogen).

NREL constructs demand and supply curves for hydrogen applications in the national market to calculate the economic potential. First, the researchers build demand curves for each hydrogen-consuming market, estimating the quantity of hydrogen every consumer might purchase over a range of prices. The light-duty FCEV’s hydrogen demand curve is obtained by utilizing the MA3T vehicle-choice model to ascertain the vehicle price, fuel price, and vehicle performance impact on consumer choices and further market penetration. NREL uses the economic equilibrium method for mature market estimations, but the MA3T model's estimate for 2050’s potential vehicle stock is not yet available for a mature market. Therefore, the researchers perform necessary changes in their approximations. Namely, NREL uses vehicle penetration when the market share for FCEVs reaches equilibrium in the MA3T vehicle-choice model (corresponding to the year 2075) (Oak Ridge National Library, 2019). The researchers then multiply the total vehicle stock in 2050 by the market share in 2075 to estimate the number of vehicles and corresponding hydrogen demand. So, the researchers calculate the equilibrium light-duty FCEV penetration if that market equilibrium could be reached by 2050 (Ruth et al., 2020).

To estimate annual FCEV demands in the demand curve estimates for medium-and-heavy duty vehicles, NREL uses the projected FCEV market shares modeled for light-duty vehicles, as described in Elgowainy et al. (2020). NREL assumes that FCEV penetrations in the medium-and heavy-duty vehicles’ markets might be similar to or exceed vehicle penetration in the light-duty vehicles’ markets due to the performance advantages of FCEVs over the battery-electric vehicles in duty cycles needed for medium-and-heavy duty vehicles (Ruth et al., 2020). NREL constructs supply curves to obtain the quantity of hydrogen each producer would supply at various prices. The supply curves are for hydrogen produced via the following production technologies, namely, natural gas steam methane reforming (SMR); nuclear high-temperature electrolysis (HTE); biomass gasification, and low-temperature electrolysis (LTE), which uses low-cost dispatch-constrained electricity from solar, wind, and nuclear generation. Such supply curves represent the summation of production and delivery costs, so, in the transportation sector, they may be considered as supply prices at the city-gate terminal for transportation demands (Ruth et al., 2020).

Finally, NREL develops five scenarios, which use different combinations of the demand and supply curves, to estimate the range of hydrogen’s economic potential in the contiguous United States, such as Reference; R&D advances plus Infrastructure; Low natural gas resource/High natural gas price; Aggressive Electrolysis R&D; and Lowest-cost Electrolysis. These scenarios depend on market conditions, fueling hydrogen infrastructure availability, hydrogen prices, hydrogen technology R&D, and prices that users will pay for hydrogen due to other competitor technologies without changes to the current state and federal policies. The scenarios do not include potential rebound effects when the price for competing technologies and resources change due to hydrogen's influence on their market shares (Ruth et al., 2020). Such scenarios are described in Table 1.

This study uses NREL's economic potential estimation for the road transportation sector (light-duty, medium, and heavy-duty vehicles) calculated in the most ambitious, Lowest-Cost Electrolysis scenario. NREL researchers state that "we identify the economic potentials for several scenarios but do not consider how to reach those potentials" (Ruth et al., 2020, p. 116). This analysis aims to demonstrate a specific strategy to reach the NRELs’ projected hydrogen economic potential for the road transportation sector in the Lowest-Cost Electrolysis scenario, where hydrogen is used as the preeminent tool for significant decarbonization in the United States.

Moreover, as a guide, the study uses the skeleton of the strategic framework laid out by the Fuel Cell & Hydrogen Energy Association (FCHEA) in the 

 report. In this report, the association describes the specific roadmap for all US economic sectors, organizing it into four important phases: 1) 2020-2022 (“immediate next steps”), 2) 2023-2025 (“early scale-up”), 3) 2026-2030 (“diversification”), and 4) 2031-beyond (“broad roll-out”). Each phase has specific quantitative and qualitative milestones for all hydrogen applications. Also, every phase designates the most important strategy enablers, namely "policy enablers" as well as "hydrogen supply and end-use equipment enablers" (FCHEA, 2020, p.13).

This analysis takes a similar approach to phases and facilitators in devising a specific decarbonization strategy, which uses hydrogen deployment in the US road transportation sector. The strategy in Section 4 consists of four phases: 1) 2022-2024 (immediate steps), 2) 2025-2027 (short-term scale-up); 3) 2028-2032 (mid-term steps), and 4) 2033-2050 (long-term roll-out). The strategy facilitators are 1) policy facilitators and 2) hydrogen fuel and supply chain facilitators. Due to the lack of access to special transportation-related modeling tools, the strategy in this study primarily focuses on qualitative recommendations and provides quantitative indicators whenever possible. The next section describes the state of the current US road transportation sector along with the challenges and opportunities of hydrogen integration into the sector.

Section 3: US Road Transportation and Hydrogen: Challenges and Opportunities

Hydrogen's deployment as an energy carrier is essential for US road transportation segments, especially for medium-and-heavy duty vehicles traveling long distances (intercity/regional buses, trucks, etc.) and light-duty vehicles (light-duty trucks and high-utilization rate passenger cars, i.e., taxis). US transportation consists of highway (road) transportation (81%) and non-highway transportation (19%). Within highway transportation (81% in total), passenger cars occupy 23%, light trucks – 33%, medium/heavy trucks – 24%, buses – 0.8%, and motorcycles – 0.2%. non-highway transportation usage (19% in total) consists of air (8.8%), water (4.2%), rail (2.1%), and pipelines (3.6%) (Saundry, 2021x). The US GHG emissions approximately correlate with energy usage within various segments of its transportation sector due to the prevalence of petroleum-based fuels. Light-duty vehicles account for 59%, medium/heavy-duty vehicles – 25%, aviation – 3%, and rail – 2% (Saundry, 2021b). Decomposition analysis, an environmental and energy analysis tool, has been useful in studying historical GHG emissions and energy use in various segments of the US transportation sector. This analysis uses the Kaya Identity variation for the transportation sector, which decomposes overall transportation CO2 emissions into four primary drivers: fuel carbon intensity, vehicle fuel consumption, population, and travel demand. (Scholl et al., 1996; Lakshmanan and Han, 1997; Mui et al., 2007; Yang et al., 2008; Yang et al., 2009; McCollum & Yang, 2009).

The valuable characteristics of petroleum-based transportation fuels, namely energy density, chemical conversion, and deployability, bring unique challenges in moving away from petroleum-based fuels (Gross, 2020). Since fossil fuels represent the primary energy source for most transportation segments, the sector is considered a difficult one to decarbonize (Meyer, 2020). The magnitude of complexity in decarbonizing road transportation also varies across its parts. Some transportation segments are maybe more complicated to decarbonize than others. For example, the expected fast growth of heavier forms of road transportation intensifies the challenge of displacing petroleum-based fuels in the sector. Per the International Energy Agency (IEA), the oil demand in heavy trucking will increase by 25% by 2040. In contrast, despite the growth of light-duty vehicles on the roads, IEA predicts the peak oil demand from these vehicles in the early 2020s. More efficiency in vehicles and transportation electrification reduce petroleum-based fuel consumption in the light-duty vehicle segment (Gross, 2020).

Electrification is considered the most attractive technology for a light-duty fleet (especially passenger cars) that carry lighter loads while traveling shorter distances. Papadis and Tsatsaronis (2020) advise that "electromobility can be applied to cars and trucks and is included as an option in most scenarios" (p. 7). Namely, the researchers believe that the electrification of transportation may serve as one of the best approaches for the transportation sector. However, the total decarbonization of the transportation sector through electrification may be problematic (IRENA, 2018). Saundry (2021c) also states that "the key variable for EVs is the level of emissions associated with generating the electricity used in the vehicle" (p.7). In other words, the electrification of transportation will only be successful if it is appropriately coordinated with the decarbonization of the power sector. Therefore, Gillispier and Krisher (2021) believe that, in the long-term, hydrogen may serve as an additional vital tool to reduce carbon emissions from the transportation sector, which represents "the single biggest US contributor to climate change" (para. 4). In other words, the hydrogen deployment in the road transportation sector may complement the electrification of vehicles in the broader context of the US energy transition.

Fuel cell electric vehicles (FCEVs) and battery electric vehicles (BEVs) represent the two main options for the zero-emissions US road transportation sector. FCEVs are electric vehicles with refueling times and driving ranges similar to internal combustion engine (ICE) vehicles (IRENA, 2008). Both types can be used for various transportation segments (light/medium/heavy-duty vehicles). BEVs store energy as electricity in batteries, whereas FCEVs store energy (15 kWh/kg) as hydrogen and then convert it to electricity through fuel cells (FCHEA, 2020). The fuel cell is "an electrochemical device that can be used to generate electricity or store energy in the form of hydrogen” (Andrews and Jelley, 2017, p. 405). The suitable materials and chemicals for the anode and cathode, electrolyte and catalyst represent the fundamental challenge in creating an efficient fuel cell (Saundry, 2021a). There are various fuel cells: polymer electrolyte membrane (PEM), solid oxide fuel, molten carbonate, phosphoric acid, alkaline fuel, and alkaline exchange membrane fuel cells. PEM fuel cells usually operate at about 80°C and respond rapidly to changing loads, making them appropriate for various transportation applications (DOE, 2020c).

FCEVs might compete with BEVs in some on-road transportation segments. However, IRENA (2018) asserts that "for each [road transportation segment], there is a clear competitive advantage for either FCEVs or BEVs" (p. 32). Although the FCEV deployment has been focused on the passenger light-duty vehicle segment, the real opportunity for hydrogen deployment exists for heavier vehicles traveling long distances. Goldman Sachs (2022) asserts that "clean hydrogen could be a key competing technology [for heavy vehicles], given its high energy content per unit mass (lighter) and faster refueling time" (p. 89). IRENA (2008) states that FCEVs have potential in the heavy vehicles segment (trucks and buses) in the short-medium term. In addition, FCEV long-term potential exits in the medium/sizeable light-duty passenger cars with high utilization rates (taxis or last-minute delivery vehicles). FCHEA (2020) believes that by deploying FCEVs through 2050, the US road transportation sector will be one of the biggest beneficiaries of hydrogen fuel (Figure 3).

The following section discusses the challenges of hydrogen deployment in the US road transportation sector.

The lack of adequate hydrogen fuel supply for the road transportation sector, absence of hydrogen infrastructure, economic issues, decarbonization policies' drawbacks, and the necessity to improve safety codes/standards and fueling protocols for medium/heavy-duty vehicles are the main potential challenges for successful hydrogen deployment in the road transportation sector.

Fuel Availability – Technological Barrier

The lack of sufficient liquid hydrogen supply for FCEVs represents the first challenge for scaling FCEVs in the US road transportation sector. Neil (2022) notes that "people assume hydrogen is abundant. It isn't – not in a readily usable form" (para. 4). For example, the United States, annually, produces only about 10 MMT of hydrogen (DOE, 2020a). As a chemical feedstock, the primary demand for hydrogen comes from ammonia production and petroleum refining. Small amounts of hydrogen are used in a few industrial applications, namely methanol production (DOE, 2020c). US hydrogen production primarily comes from fossil fuels (99%), natural gas through SMR (95%), and partial oxidation of natural gas through coal gasification (4%). Electrolysis is used only in 1% of US hydrogen. In contrast to the United States, 70MMT of hydrogen is produced globally. Global hydrogen production comes from natural gas through SMR (76%), coal gasification (22%, mainly in China), and electrolysis (2%) (DOE, 2020a).

Table 2 shows the current and future hydrogen economic potential breakdowns in the Lowest-Cost Electrolysis scenario. As seen from the table, in the most ambitious scenario, by 2050, the US needs to increase the supply of transportation FCEVs from a currently negligible amount to 17 MMT. Therefore, the US faces the daunting task of quickly ramping up the hydrogen supply for transportation and other sectors to decarbonize its economy.

The absence of a reliable public and private hydrogen infrastructure for the road transportation sector is the second challenge in achieving widespread FCEV adoption across the United States. This infrastructure consists of hydrogen transportation, storage, and distribution (dispensing and fueling) (DOE, 2020c). Incidentally, “[hydrogen] transportation, distribution, and storage are the primary challenges of integrating hydrogen into the overall energy economy system” (DOE, 2020a, p.11). Neil (2022) agrees that even if low-carbon hydrogen were plentiful, it would be challenging to develop hydrogen transportation and delivery for the road transportation sector.

Hydrogen transportation and storage are challenging since hydrogen has a low-volumetric density at room temperature (nearly 30% of methane at 15°C, 1 bar) and quality to pervade metal-based materials. There are four primary methods for hydrogen transportation at scale: tube trailers, pipelines, liquid tankers, and chemical hydrogen carriers. Gaseous hydrogen can be transported by pipelines or tube trailers, whereas liquid hydrogen may be moved by liquid tankers or marine vessels. The current portfolio of hydrogen storage options consists of physical-based (compressed gas, cold/cryo-compressed, liquid, and geological) and material-based (metal hydrides, absorbents, and chemical hydrogen carriers). Currently, there are no material-based storage options ready for widespread commercialization. Energy densities in cryo-compressed and liquid hydrogen storage systems may benefit medium/heavy-duty vehicles' infrastructure rollout. However, the need for boil-off, venting, and insulation, which occur from extended dormancy, adds costs and challenges to the system's performance (DOE, 2020c).

Hydrogen distribution (dispensing and fueling) is the last vital part of hydrogen infrastructure for the road transportation sector. Sinha and Brothy (2021) proclaim that "the hydrogen refueling network is the main barrier to FCV adoption because consumers will only purchase an FCV if the stations exist to refuel it" (p.7). In other words, US FCEV drivers require ample hydrogen fueling station (regional and/or nationwide) coverage to reassure them that fueling will not be a problem. There are 48 public hydrogen fueling stations in the US, 47 in California, and 1 in Hawaii (Neil, 2022). Overall, the US will need to invest in significant research and development (R&D) efforts to increase the throughput of hydrogen dispensing systems and other related systems at the fueling stations. Moreover, R&D efforts are required to improve the reliability of materials used in the compressors and develop new designs for cryogenic transfer pumps, compressors, and dispensers to ensure they have sufficient throughout the medium/heavy-duty vehicle fleet (DOE, 2020c). Overall, the demands placed on hydrogen transportation, storage, and hydrogen delivery present challenges for the initial introduction and the nationwide scale-up of hydrogen infrastructure for the road transportation sector.

Economics is the third hurdle to successful hydrogen deployment in the road transportation sector. The three-pronged economics issue is connected to the costs of hydrogen production, fueling infrastructure, and FCEVs. First, the current production cost of low-carbon hydrogen is a costly process. In the United States, gray hydrogen costs $2/kg, blue hydrogen costs between $5-$7/kg, and green hydrogen costs $10-$15/kg, depending on availability (SGH2 Energy, 2022). DOE Hydrogen Program describes that the US might produce hydrogen from polymer electrolyte membranes (PEM) at approximately $5-$7/kg. This calculation assumes grid electricity prices between 5-7 cents/kWh, existing technology, and low volume electrolyzer capital costs (CapEx) at $1,500/kW. Hellstern et al. (2021) stress that the significant hydrogen end-users would consider hydrogen economically viable if the fuel is made at $1/kg in the United States and $2/kg in the European Union. Second, the costs of building hydrogen infrastructure will be prohibitive. For example, Neil (2022) notes that the costs of presently available hydrogen fueling stations during the past decade are much higher than associated costs with traditional gas stations. Such costs usually include the costs of the natural gas reformer on-site to evade the necessity of high-capacity storage tanks and pipelines. Additional costs of hydrogen fueling stations are connected to the compliance costs associated with local, state, and federal safety regulations.

Lastly, the broad adoption of FCEVs also relies on the relatively inexpensive cost to consumers. Compared to ICEVs and even BEVs, the high cost of FCEVs may preclude such widespread rollout of FCEVs in the road transportation sector. For example, the researchers analyzed the cost components for different vehicle types in Austria and Germany in 2016 (Table 3). The results show that, at present, FCEVs and BEVs are more expensive to operate than conventional vehicles. However, BEVs are less costly than FCEVs in investment, fuel, and operations costs. The fuel cell cost accounts for nearly half of the investment cost for FCEVs (Moriarty & Honnery, 2019). The main contributor to the cost of a fuel cell is the catalyst, which is based on the platinum group metals that are highly dependent on imports. Other components also need additional R&D improvements to meet low-cost targets for fuel cells, such as electrolytes or membranes, bipolar plates, etc. The cost reductions for fuel cells need to happen while maintaining efficiency and improving the durability of components (DOE, 2020c). To sum up, high costs of production, fueling infrastructure, and FCEVs may hinder the hydrogen deployment in the road transportation sector.

Drawbacks from decarbonization policies might become the fourth roadblock to successful hydrogen deployment in the road transportation sector. The United States, along with various nations worldwide, has implemented internal combustion engine phase-out policies. Biden's administration aims to "50 percent of all new passenger cars and light trucks sold in 2030 be zero-emissions vehicles, including battery-electric, plug-in hybrid electric, or fuel cell electric vehicles" (Saundry, 2021c). Andrews and Jelley (2017) affirm that policy changes may encourage the shift in the transportation modes and assist decarbonization efforts.

However, due to the urgency of the fight against climate change and ambitious decarbonization targets in some states, accurate technology winners might not be discovered quickly enough to justify large-scale hydrogen infrastructure buildout. Gross (2020) warns about the potential policy drawbacks in very ambitious jurisdictions: "Policy has the potential to drive vehicle uptake and infrastructure development, but at the risk of not allowing the technology competition to play out fully" (p. 11). In other words, the policies that encourage the shift to a low-carbon vehicle fleet might stifle the competition to establish an accurate technology winner for road transportation segments. Namely, the California Air Resources Board (CARB) passed a new rule in June 2020, which requires broad adoption of zero-emissions trucks, beginning in 2024, with all heavy-duty vehicle sales being zero-emissions by 2045. The CARB does not stipulate a specific technology in the ruling. Electric trucks are currently ahead of other technologies in research and development efforts.

Furthermore, through the West Coast Clean Transit Corridor Initiative, the US West Coast utilities are ready to offer the charging infrastructure for BEVs. Even though the CARB ruling is technology-neutral, such policy will significantly benefit California's electric medium/heavy-duty trucks. The District of Columbia and fifteen states in the US Northeast also signed a memorandum of understanding to follow California's initiative. Thus, policies may accelerate decarbonization in the road transportation sector by encouraging the electrification of medium/heavy-duty vehicles. However, such policies might leave the deployment of hydrogen infrastructure and FCEVs significantly behind. The policy drawbacks might also be amplified by the miscoordination of federal, state, and local efforts during the hydrogen deployment in the road transportation sector.

The implementation of safety standards is the fifth potential challenge in the US hydrogen deployment in its most carbon-intense sector, road transportation. Hydrogen has been safely used in different industrial sectors, such as refining and chemicals, for more than seventy years. Its chemical properties give hydrogen a better standing than fossil fuels inflammability, risk of secondary fires, and quick dissipation. Nevertheless, hydrogen is a flammable, odorless, invisible gas requiring stringent safety measures. The US needs to implement such actions in hydrogen production, use, and handling, namely leak detection systems, storage tanks, and safety valves (FCHEA, 2020). Thus, hydrogen standards need to be constantly revised, in concert with the R&D efforts in the US and abroad, as hydrogen continues to be deployed in the road transportation sector.

Fueling Standards for Medium/Heavy-Duty Vehicles

The rapid development of fueling standards for medium/heavy-duty vehicles might be the last challenge of hydrogen deployment in the road transportation sector. Once hydrogen is transported to the hydrogen fueling stations, it may need to undergo the additional process for conditioning, such as pressuring, cooling, and purification. Hydrogen is usually stored on-site in bulk. Hydrogen fueling stations for all vehicles (light, medium, heavy-duty) usually have high-pressure compressors, dispensers, and storage vessels – all these systems are required to permit hydrogen fueling per specific standard protocols. The fueling standards for light-duty vehicles are currently developed, with the technology commercially deployed in the current FCEV hydrogen fueling stations across the United States. For example, the fueling pressure for light-duty vehicles is typically 10,000 psi or 70 MPa (700 bar). However, the fueling standards for medium/heavy-duty vehicle fleets are yet to be established, and such measures need to inform the equipment requirements for the hydrogen high-throughput stations (DOE, 2020c). The US needs to coordinate its R&D efforts with similar efforts globally (FCHEA, 2022). Thus, the rapid development of reliable fueling standards for medium/heavy-duty vehicles is essential for successful hydrogen deployment in the US road transportation sector.

To summarize, the lack of hydrogen supply and infrastructure, economic issues, the drawbacks of decarbonization policies, the urgency to improve safety codes/standards, and fueling protocols for medium/heavy-duty vehicles are primary potential challenges for successful hydrogen deployment in the road transportation sector. The following section discusses the opportunities for hydrogen deployment in the road transportation sector.

The main prospects for hydrogen deployment in the road transportation sector are the availability of domestic natural resources, technologies, additional resources (storage and liquefication), supportive hydrogen-related policies, and the FCEV’s advantages over BEVs and ICEs.

Availability of Natural Resources, Technologies, and Additional Resources

The United States has various primary energy resources to produce low-cost, low-carbon, secure, sustainable, and large-scale hydrogen, including fossil, biomass, and waste-stream resources (DOE, 2020c). The US possesses sufficient low-carbon and renewable electricity sources for green hydrogen, such as solar, wind, nuclear, and hydropower (FCHEA, 2020). Currently, the country consumes and produces about 10 MMT/year, about one percent of US energy consumption (DOE, 2020c).

At the same time, the US is rapidly exploring and developing hydrogen production technologies, which can utilize these natural resources through natural gas and coal gasification with CCUS, biomass conversion, waste-to-energy technologies, and various water-splitting technologies (Figure 4). Such a wide array of natural resources and technologies spread across the country can help increase its hydrogen supply from "a few hundred to hundreds of thousands of kilograms per day” (DOE, 2020c, p. 15).

 Presently, natural gas and coal are the two primary fossil resources utilized for global hydrogen production (DOE, 2020c). Natural gas, produced in rock formations, contains the remains of tiny creatures fossilized under immense heat and pressure throughout millions of years (Andrews & Jelley, 2017). Coal is a "carbon-rich solid, which originated in vast swamps containing large trees and leafy plants" (Andrews & Jelley, 2017, p. 74). Based on the differences in carbon content, coal can be divided into lignite, bituminous, sub-bituminous, and anthracite (Saundry, 2021d). The US remains the largest natural gas consumer despite its decline in the share of global gas consumption (Saundry, 2021e). Due to the relatively recent fracking boom of "unconventional resources," the US currently is the largest global producer (with a 24% share) of natural gas (Saundry, 2021e). Approximately 95% of US hydrogen is produced through SMR methods based on prevailing natural gas infrastructure. FCHEA (2020) claims that the US has ample affordable natural gas and carbon storage capacity to produce blue hydrogen (natural gas with CCUS) on a massive scale. In the near term, CCUS can be utilized with auto thermal reforming (ATR - conversion of steam, natural gas, and oxygen to syngas), partial oxidation of natural gas, and gasification of coal or biomass/coal/plastic waste blends.

Other developing technologies include direct methane pyrolysis into hydrogen and solid carbon. There are currently promising hydrogen production systems that can produce hydrogen for less than $2/kg. One of the successful examples of an SMR/CCUS project is the integrated hydrogen production facility at the Valero Refinery, the Port Arthur (SMR/CCUS project) (Preston, 2018). In the long-term, the reductions in capital and operating costs and further R&D advances in technologies can lead to low-carbon production at less than $1/kg. In addition, steam cracking (cracking natural gas liquids) can also produce affordable hydrogen as a by-product of this process. The current hydrogen production capacity is 2 MMT/year, which will increase to 3.5 MMT/year from the deployment of additional steam cracking plants soon. The DOE estimates that, if properly implemented, this process can provide 35% of current hydrogen demand and provide opportunities to co-locate end-use applications in various US regions (DOE, 2020c).

 Primary biomass sources (poplar, willow, switchgrass) and biogas, derived from anaerobic digestion of organic residues from agricultural waste, municipal solid waste, and landfill sources, can be used for US hydrogen production. The feedstock potential for such resources is more than a billion dry tons annually (DOE, 2020c). Biomass is an attractive, sustainable low-carbon energy source due to the basic cycle for bioenergy, which recycles carbon dioxide out of the atmosphere and releases the same carbon dioxide during burning (Andrews and Jelley, 2017). Biomass can be gasified on its own or during the gasification processes for waste plastics and coal. The processing of primary biomass into bio-derived liquids for consequent reforming into hydrogen, together with CCUS, may produce carbon-negative hydrogen.

Furthermore, biogas can be reformed through an SMR-like process into hydrogen after additional clean-up procedures. Through microbial-assisted electrolysis, fermentation, or non-thermal/thermal plasma-based processes, producers can use waste-stream feedstocks for hydrogen production. Based on the availability and costs of biomass/waste-stream resources, producers can commercially deploy some types of technologies (SMR/gasification of biomass and waste streams) in the short term. In the long-term, R&D initiatives in conversion efficiency and the decrease in costs of transporting/pre-treating feedstocks will make this type of hydrogen production economically competitive (DOE, 2020c).

Water-Splitting Technologies for Hydrogen Production.

 Hydrogen producers can use various water-splitting technologies, which utilize electric, photonic, or thermal energy from US low-carbon and renewable energy resources (DOE, 2020c). Electrolysis is considered a "promising option for carbon-free hydrogen production from renewable and nuclear resources" (DOE, 2022a). Andrews and Jelley (2017) explain that electrolysis serves as vital technology in the energy storage and the synthesis of low-carbon fuels through hydrogen production. The US has abundant renewable and low-carbon electricity resources, crucial for hydrogen production. For example, solar photovoltaics and wind power enable hydrogen production on both distributed and centralized basis throughout almost all US regions. Concentrated solar power (in the south-western region) and solid biomass (in the central and eastern regions) are other potential renewable energy sources that the US may use for hydrogen production. Lastly, present nuclear plants can be co-located next to the large-scale hydrogen production facilities (DOE, 2020c).

Electrolyzers can be coupled with the US electric grid or be integrated with distributed generation assets for hydrogen production for various applications. An electrolyzer is defined as a “system that uses electricity to break water into hydrogen and oxygen” (Cummings, 2020, para. 1). IRENA predicts in its 

that the cost of hydrogen electrolyzers will fall at similar rates to onshore wind and solar PV's decrease in the past decade (Collins, 2022). Low-temperature electrolyzers (membrane-based and liquid-alkaline) provide short-term commercial profitability, with units ready for industrial-scale production. The hydrogen cost for low-temperature electrolysis is connected to the US electricity cost. Currently, for electricity priced between $0.05-$0.07/kWh, hydrogen’s cost ranges between $5-$6/kg (DOE, 2020b). Hydrogen becomes cost-competitive, at less than $2/kg, if the electricity cost lowers to $0.02 - $0.03/kWh (due to the increase in solar/wind generation) along with R&D advancements in the durability and efficiency of electrolyzers (DOE, 2020c).

Additional Resources (Hydrogen Storage and Liquefaction).

 The US possesses more than 1,600 miles of hydrogen pipelines and three caverns, which can be used to store hydrogen on a massive scale. In addition, there are eight hydrogen liquefaction plants (cumulative capacity of 200 metric tonnes/day), with three more additional plants to be built in the near term (DOE, 2020c). These other resources provide tangible opportunities for hydrogen storage and transportation of liquified hydrogen to the end-users, especially in the road transportation sector.

Although the US has not yet announced an official national hydrogen strategy, the country has always supported hydrogen technology. In 1969, the US Apollo 11 mission, which put the first man on the moon, utilized a hydrogen fuel cell system for electricity/ water needs and liquid hydrogen as rocket fuel. Since this historic mission, the US has retained its leadership position in developing and commercializing hydrogen and fuel cell technology. Over the last decade, the US DOE provided funding for fuel cells and hydrogen ($100-$280 million/year) and $150 million/year since 2017 (FCHEA, 2020). More than ten years ago, the DOE's early investment in the forklift and material handling industry represented the US early market success for using hydrogen in transportation. As of 2020, more than 35,000 systems are commercialized by the US private sector without additional DOE funding. Hydrogen is also used in over 8800 commercial and passenger vehicles, with a growing hydrogen fueling infrastructure (DOE, 2020c).

Other developed countries have provided more significant financial support for developing their hydrogen economies. For instance, China declared $17 billion in funding for hydrogen transportation needs through 2023. In 2019, Japan announced hydrogen funding of approximately $560 million. Germany offers $110 million/year towards R&D efforts for hydrogen technologies for various industrial-scale end-uses. Therefore, FCHEA proclaims, "Directing capital to hydrogen is key to enabling its growth in the US" (FCHEA, 2020, p.6). In other words, large-scale government funding is crucial to lay down the foundation for all sectors of the US hydrogen economy, mainly in the road transportation sector.

Recently, the US has undertaken serious steps towards creating the solid groundwork for nationwide hydrogen solutions. For example, in 2020, the US DOE published 

, which describes the strategic framework for nationwide hydrogen deployment, H2@Scale. "H2@Scale is a DOE initiative that provides an overarching vision for how hydrogen can enable energy pathways across applications and sectors in an increasingly interconnected energy system" (DOE, 2020c, p. 8). Furthermore, launched on June 7th, 2021, the DOE Hydrogen Shot initiative seeks to reduce clean hydrogen's cost by 80% to $1/kg by 2031 (DOE, 2022b). In February 2022, the US "[entered] the hydrogen policy wave" by announcing $9.5 billion in clean hydrogen funding as a part of the US Infrastructure Investments and Jobs Act (Goldman Sachs, 2022, p. 17). Here are the excerpts from Sections 40313, 40314, and 40315 of this Infrastructure Bill, which are relevant to the road transportation sector (Goldman Sachs, 2022):

 focuses on forming a clean hydrogen R&D plan to 1) further R&D and commercialization of the use of clean hydrogen in transportation and 2) show a standard of clean hydrogen production in the transportation sector by 2040.

 describes additional clean hydrogen programs with vital provisions to the Energy Policy Act, such as:

 over four years (2022-2026) for the creation of Regional Hydrogen hubs for clean hydrogen production

2) Requirement for development of National Energy Strategy for Hydrogen

 over four years (2022-2026) towards R&D and demonstration projects for novel clean hydrogen production/processing/delivery/storage/use of equipment manufacturing technologies

 for the Clean Energy Electrolysis Program for funding R&D, demonstration, commercialization, and hydrogen deployment efforts. The federal government will provide grants to entities that can reach the following program goals: a) reduction in the cost of hydrogen production using electrolyzers to less than $2/kg by 2026 and b) any other goals that the Secretary of Energy deems appropriate.

5) establishment of the mechanism for coordination of National Laboratories, namely the Idaho National Laboratory, the National Energy Technology Laboratory, The National Renewable Energy Laboratories, and other research institutes and universities

 defines clean hydrogen as hydrogen manufactured "with a carbon intensity equal to or less than 2 kilograms of carbon dioxide equivalent per kilogram" (Goldman Sachs, 2022, p. 18). The DOE and EPA will readjust this definition no later than 2027 after further consultation between the DOE and EPA.

Furthermore, in March 2022, US Senators Chris Coons (D-Delaware) and John Cornyn (R-Texas) introduced the Hydrogen for Trucks Act to assist with deploying heavy-duty FCEVs and hydrogen fueling stations. This act will 1) provide incentives for FCEV adoption by covering the cost difference between FCEVs and ICEs; 2) encourage parallel deployment of fueling stations and FCEVs, and 3) offer data and benchmarks for various kinds of fleet operations, which is supposed to accelerate deployment and incentivize private investment (Coons, 2022). To sum up, the trajectory of US pro-hydrogen policy and, mainly, the current political environment provides a vital boost for hydrogen deployment in the US road transportation sector.

According to FCHEA (2020), FCEVs have many advantages compared to BEVs and ICEs. Such benefits are based on 1) range/weight/powertrain volume, 2) fueling time, 3) diversification or reduction of raw material dependencies, and 4) performance consistency at various temperatures. Based on such prospects, FCEVs can be instrumental in various US transportation segments, complementing electrification, biofuels, and other powertrain strategies (FCHEA, 2020):

FCEVs’ hydrogen storage requires less weight and space than a BEV’s battery. Therefore, FCEVs can have a higher payload and drive further than BEVs. This advantage translates into a longer-range advantage, which is crucial for freight transport and light/mid/heavy-duty vehicles (FCHEA, 2020). Moriarty and Honnery (2019) also indicate that such factors will significantly influence purchasing decisions for vehicle customers.

FCEV's fueling time matches ICE's (2-3 minutes for 400 miles) faster than the BEV rate (between 30 minutes and 8 hours). This advantage might not be transparent when vehicles are charged overnight in depots. However, FCEV's fueling time is advantageous in the market segments, where customer convenience and high utilization rates are vital, namely for taxis, medium/heavy-duty transport, and autonomous vehicles. Faster refueling time reduces the infrastructure footprint for FCEVs due to the decrease in the number of fuel pumps in warehouses, mines, ports, and public areas (FCHEA, 2020).

Reduction and diversification of raw material dependencies: 

The FCEV deployment will have limited supply chain risks on raw materials for manufacturing hydrogen storage tanks and fuel cells for the road transportation sector. Namely, the hydrogen industry in 2005 already limited the usage of platinum content by 80 percent to less than 0.2g/kW (Jacob et al., 2020). Cerium and cobalt are also limited quantities in fuel cell production (FCHEA, 2020).

Performance consistency at various temperatures: 

FCEVs provide the same performance standard across all the geographies and varying climates. This temperature-resistant operation advantage is crucial for the successful deployment in various regions throughout the US road transportation sector.

In essence, the hydrogen deployment in the US road transportation sector might benefit from domestic natural resources, technologies, additional resources (storage and liquefication), supportive domestic policies, and the FCEV's advantages over BEVs and ICEs. The following section discusses the hydrogen deployment strategy in the road transportation sector through 2050.

Part 2 of this article and a full list of references will be available here when published. 

illuminem Voices is a democratic space presenting the thoughts and opinions of leading Sustainability & Energy writers, their opinions do not necessarily represent those of illuminem.

Hydrogen deployment in the road transportation sector: US decarbonization strategy (Part 1)

This article provides a summary of selected revisions (from version 18.0. to version 14.0.), to a small-scale Clean Development Mechanism (CDM) methodology “AMS-I.A.: “Electricity generation by the user” (hereinafter referred to as "AMS-I.A."). It also describes the rationale for such proposed revisions, including those approved, rejected and yet to be decided by the CDM Executive Board. 

This article provides a summary of selected revisions (from version 18.0. to version 14.0.), to a small-scale Clean Development Mechanism (CDM) methodology “AMS-I.A.: “Electricity generation by the user” (hereinafter referred to as "AMS-I.A."). It also describes the rationale for such proposed revisions, including those approved, rejected and yet to be decided by the CDM Executive Board. The CDM "requires the application of a baseline and monitoring methodology to determine the amount of Certified Emissions Reductions (CERs) generated by a mitigation CDM project activity in a host country" (UNFCCC, 2021, p. 4). CDM methodologies consist of five categories for its project activities: large-scale; small-scale; large-scale afforestation and reforestation (A/R); small-scale A/R; and carbon capture and storage (CCS) project activities (UNFCCC, 2021). As of March 16, 2022, there were one hundred approved small-scale methodologies (UNFCCC, 2022). In general, the methodology offers provisions for the main elements of a Project Design Document (PDD) in the CDM project cycle, such as a) the evidence of additionality, b) the formation of the baseline scenario and the approximation of emission reductions or net removals, and, finally, c) the monitoring plan (UNFCCC, 2021). The methodologies are vital for ensuring the environmental integrity of the carbon credits issued (Michelowa, 2020).

The analysis is divided into five main sections. After the introduction in Section 1, Section 2 outlines the anatomy of the “AMS-I.A.” methodology. The analysis in Section 3 describes six clarifications/revisions, traced from version 18.0 to version 14.0. Section 4 provides a case study of the “AMS-I.A.” project, Cabo Negro Wind Farm Project (Phase 1), to review the application of methodology. Section 5 concludes and offers suggestions for the future of the methodology. The following section briefly describes the current “AMS-I.A.” methodology (version 18.0, valid from March 11, 2022).

“AMS-I.A.” small-scale CDM methodology has been revised repeatedly, up to eighteen times. The scope of this methodology covers renewable electricity generation units, namely wind, solar photovoltaic, hydro and renewable biomass, which provide electricity either to individual households/users or groups of households/users. The "AMS-I.A" methodology applies to CDM project activities, which are implemented by the users of new installations (greenfield) or users who replace present onsite fossil-fuel-fired generation (UNFCCC, 2022b). The applicability of this methodology is limited to users and individual households in off-(national/regional) grid locations or unique situations, such as weak grids. Furthermore, essential conditions apply for reservoir-based hydro plants. And lastly, all users must be included in the project boundary, which incorporates the physical (geographical) site of the renewable energy generating unit(s) as well as the equipment which utilizes the produced electricity (UNFCCC, 2022b).

The methodology refers to the following approved methodologies and tools, namely a) “AMS-I.D.: Grid-connected renewable energy generation” (hereinafter referred as “AMS-I.D.”); b) “AMS-I.L.: Electrification of rural communities using renewable energy” (hereinafter referred as “AMS-I.L.”); c) “AMS-I.F.: Renewable electricity generation for captive use and mini-grid” (hereinafter referred as “AMS-I.F.”); d) “ACM0002: Consolidated baseline methodology for grid-connected electricity generation from renewable sources”(hereinafter referred as “ACM0002”); e) “Standard: Sampling and surveys for CDM project activities and programme of activities” (hereinafter referred as “Standard”); f) “TOOL5: Baseline, project, and/or leakage emissions from electricity consumption and monitoring of electricity generation” (hereinafter referred as “TOOL5”); and g) “TOOL16: Project and leakage emissions from biomass” (hereinafter referred as “TOOL16”). The methodology also instructs the project participants to follow the General guidelines for SSC CDM methodologies and “TOOL21: Demonstration of additionality of small-scale project activities” (UNFCCC, 2022b).

Besides applicability, every methodology document has other sections, such as baseline methodology and monitoring methodology. Generally, the integrity of the methodology depends on the integrity of these underlying sections. The basic formula for emission reductions (CERs) under a methodology is baseline emissions minus project emissions minus leakage emissions (Hart, 2022a). The “AMS-I.A.” baseline emissions are estimated “based on the fuel consumption of the technology in use, or that would have been used to generate the equivalent quantity of energy in the absence of the project activity. The baseline emissions are calculated using one of the three options: a) Option 1: based on the electricity consumption of the household/user, b) Option 2: based on the annual electricity generation by the project activity, and c) Option 3: based on a trend-adjusted projection of historic fuel consumption, in the case of replacement of existing fossil fuel-based technologies. Furthermore, baseline emissions of project activities, which involve capacity addition at an existing facility or replacement/retrofit of an existing facility, must be calculated using “AMS-I.D.” with the emissions factor (EFCO2) calculated under the “AMS-I.A.” parameters. Baseline emissions for project activities, which offer renewable energy to communities, can be calculated using the "AMS-I.L.” methodology (UNFCCC, 2012b).

The “AMS-I.A.” project emissions for most renewable energy project activities are zero. However, the project developers need to apply the "ACM0002” methodology for emissions connected to water reservoirs of hydropower plants or emissions related to the operation of geothermal plants. The project activities related to cultivated biomass need to be calculated per "TOOL16" with simplifications for small/micro-scale project activities. In terms of leakage emissions, leakage is considered when the energy-generating equipment is transferred from other project activity or when the CDM project utilizes biomass per "TOOL16" (UNFCCC, 2022b). Lastly, the “AMS-I.A.” monitoring methodology stipulates an annual check of all systems or a sample of the systems to ensure the operation or metering of generated electricity. If applicable, consumption of all energy sources and the availability of connected grids must be monitored (UNFCCC, 2021). The methodology also stipulates the “AMS-I.L.” monitoring procedures for all project activities, which determine baseline emissions based on Option 3 (UNFCCC, 2022b). The following section focuses on the revisions to the methodology.

This section discusses clarifications/revisions of the "AMS-I.A.” methodology from the most recent version, 18.0. to version 14.0. (UNFCCC, 2022b; 2022c, 2019a, 2019b; 2012j; 2012k; 2012h; 2012i; 2010a; 2010b). Out of six selected clarifications/ revisions, two requests focus on applicability while the rest clarify the calculation of baseline emissions in the methodology. Usually, the integrity of applicability is crucial for consistency of outcomes across host countries, avoidance of gaming, and clarity of methodology scope. The right design for baseline scenarios has an appropriate baseline setting approach, limits uncertainties, and ensures conservativeness (Michaelowa, 2020). The strong baselines are credible, transparent, and practical. Such baselines do not lead to under/over allocation of credits and help additionality (Hart, 2022a).

The section describes each of the clarifications/revisions by providing details about queries, answers by the small-scale working group (SSC WG) to authors of queries, recommendations to the CDM EB, and analysis of each revision to the methodology.

 of solar water pumps for irrigation purpose under AMS-I.A.” (SSC_823)

[Date and number of Panel / WG meeting: 7-11 February 2022 / MP 87] 

The Indian project participant seeks clarification about theapplicability of standalone or decentralized solar photovoltaic water pumps for irrigation, which replaces the usage of diesel-operated pumps under the “AMS-I.A.” (version. 17.0) (UNFCCC 2019a; 2019b). The high cost of solar water pumps and inadequate market ecosystem represent the main challenges for implementing this technology. The agricultural field where solar water pumps are/will be used by the small users is not connected to the national grid. The stakeholder also seeks to clarify if Option 3 of “AMS-I.A.” can be utilized in this project activity. If yes, the stakeholder asks about the necessity of a survey to be performed to a) to access the “capacity wise annual hours of operation for diesel pumps and the value/factor to be fixed ex-ante” or b) to access “the capacity wise annual operational hours of solar water pumps and the value to be used for assessing the baseline fuel consumption and estimation of baseline emission in the ex-post scenario [on an annualized basis].” Also, the stakeholder seeks to clarify if the project participant needs to perform a sample survey to measure the continued operation of the project units, per paragraph 33 of “AMS-I.A.” (version 17.0) (UNFCCC, 2019a; 2022a).

Answers to Authors of Query / Recommendations

The Methodology Panel (Meth Panel) clarifies that, in principle, “AMS-I.A.” is applicable in the project. However, suppose a stakeholder seeks to use Option 3. In that case, the project participant has to submit a request for revision, which explains a conservative and accurate method to estimate "Projected fuel consumption of fuel type j in year y (mass or volume unit) (FC,y), since “AMS-I.A.” (version 17.0) does not explain the intricacies of such a calculation. The Meth Panel recommends a baseline survey to estimate baseline pump type, its emission factor, and capacity. This emission factor can remain fixed during the crediting period. After that, ex-post surveys need to be performed to calculate solar water pumps' capacity-wise annual operational hours (UNFCCC, 2022a).

The baseline and ex-post estimation surveys need to be carried out under the provisions of "Standard." The project participant can also consult "AMS-II.P.: Energy-efficient pump-set for agriculture use similar approaches" to calculate baseline emissions and monitor annual operational hours. The Meth Panel also recommends sampling for determining the retention rates and the operation hours of the project's solar water pumps. And lastly, Meth Panel advises stakeholders to apply a Type-II Methodology (for example, "AMS.II.F.: Energy efficiency and fuel switching measures for agricultural facilities and activities") in concert with "AMS-I.A.," particularly in the circumstances where the project participants want to implement the standalone solar water pumps and an efficient irrigation method during project scenarios (UNFCCC, 2022a).

The clarification regarding the applicability of solar-water pumps for irrigation purposes under the "AMS-I.A." methodology has the following positive and negative implications. As mentioned earlier, the integrity of applicability conditions is crucial for consistency of outcomes across host countries, avoidance of gaming, and clarity of methodology scope.

 aspects of the proposed changes. First, the clarification provides consistency of projects outcomes since outcomes will not differ between host countries in similar conditions and with similar ambitions. Second, 

, the proposed scenarios for sampling, surveying, and monitoring act as safeguards against gaming by project participants and, thus, promote the environmental integrity of the emissions credits. Third, the clarification provides clarity of the methodological scope by affirming, 

, the applicability of the project activities implementing standalone solar pumps to replace the use of diesel pumps used for irrigation. Fourth, the clarification of the “AMS-I.A.” methodology (and the allowance to apply a Type-II methodology) for such cases is valuable in light of goals of the CDM, which strives for "real, measurable, and long-term benefits related to the mitigation of the climate change" (Hart, 2022a).

 aspects of the proposed changes. First, 

, project developers might still be delayed with the implementation of the project since they might need to submit a follow-up request for revision about their thoughts on FCj,y estimation. Second, suppose they follow the Meth Panel's advice on one of the options of estimating FCj,y. In that case, project developers might incur additional costs for implementing specific baseline and ex-post surveys. Third, although the clarification stimulates the promotion of standalone solar water pumps to replace diesel pumps, the projects might benefit beyond credits and not be additional in all cases. Fourth, the data from sampling during the crediting period might be tampered with by project participants and thus, will not provide an accurate and conservative approach to calculate FCj,y. Fifth, third-party monitors will know less about the true intentions of project participants, so the third-party monitoring data might also become unreliable. The main lessons to inform best practices in offset designs in such cases are robust monitoring and review processes to ensure the accuracy/reliability of sampling/surveying information and improve the tests for additionality.

 calculation in the case of a greenfield project and provision of leakage in the case of a PoA for AMS-I.F.” 

(submitted by Jiwan Acharya, Asian Development Bank – ADB; SSC_547)

[Date of SSC WG meeting: 22-25 August 2011 / SSC WG 33]

ADB’s Technical Support Facility (Carbon Market Program) presents two requests for clarifications. One of them, which discusses baseline emissions calculation for greenfield projects, is related to the “AMS-I.A.” methodology. This query follows the SSC_537, in which SSG WG is permitted to use “AMS-I.D.” and “AMS-I.F.” methodologies in the Programme of Activity (PoA). The group points out “AMS-I.F.” (version 2.0). does not contain an allowance for calculating baseline emissions if there is no electricity use before the project activity. Instead, “AMS-I.F.” is designed for cases of captive power generation or renewable electricity generation for isolated grids. In such cases, the baseline emissions calculation is likely based on carbon-intensive or fossil fuel-based electricity generation. Therefore, the group asks SSC WG / EB about the possibility to utilize “AMS-I.D.” and “AMS-I.F.” along with the “AMS-I.A.” for a renewable electricity supply PoA (UNFCCC, 2011b)

The SSG WG notifies that the "AMS-I.A." and not “AMS-I.F." methodology should calculate the baseline emissions for greenfield projects. The group clarifies that “the baseline will be determined as the fuel consumption of the technology that would have been used in the absence of the project activity to generate the equivalent quantity of electricity” (UNFCCC, 2011b, p. 3). SSG WG also recommends to the CDM Executive Board to approve the combination of “AMS-I.A.” with “AMS-I.F.” and/or “AMS-I.D.” in a PofA (UNFCCC, 2011b)

In the meeting report (paragraph 23 of SSC WG 33), SSC WG states its agreement to clarify the provisions under "AMS-I.A.," not "AMS-I.F." should be used in cases where is no electricity usage before project activities. Also, the SSC WG makes the recommendation to CDM Executive Board to approve the combination of “AMS-I.A.” with “AMS-I.F.” and /or “AMS-I.D.” in a PoA (UNFCCC, 2011a). 

The clarification/revision regarding baseline calculation in the case of a greenfield project has positive and negative implications. 

 aspects of the proposed changes. First, it provides clarity and consistency to project developers regarding the calculation of baseline emissions and the permission for the usage of a combination of "AMS-I.A." with “AMS-I.F.” and/or “AMS-I.D.” in a PoA. Second, it is appropriate, conservative, and limits uncertainties (all CDM greenfield projects will follow the same guidelines). Third, the clarification/revision may, 

, help ensure environmental integrity. For example, under “AMS.-I.F.," the baseline emissions are based on carbon-intensive electricity generation, whereas “AMS-I.A." allows the absence of fossil-fuel-based power in baseline (UNFCCC, 2011b). Such a revision can prevent the issue of “perverse incentives," which usually leads to an artificial maximization of credits for a CDM project (Mukerjee, 2009). As discussed earlier, correct baseline design is critical for determining additionality since the “same project can earn different CERs depending on a grid” (Hart, 2022a). Fourth, the clarification/revision helps the implementation of the renewable energy projects in light of the goal of the CDM, which seeks “[stimulation of] low-emitting projects that wouldn’t have otherwise occurred” (Hart, 2022b).

, the clarification/revision might still provide an incentive for gaming by project participants. For instance, the baseline calculations under “AMS-I.A.” are based on the “fuel consumption of the technology that would have been used in the absence of the project activity to generate the equivalent quantity of electricity” (UNFCCC, 2011b). The Developing Member Countries (DMCs)'s project participants may still propose a fossil-fuel-based technology as a "technology that would have been used in the absence of the project activity"(UNFCCC, 2011b). As mentioned above, the revision, 

, eliminates the issue of perverse incentives. However, 

, due to the gaming by the project participants, there might be potential problems with the environmental integrity of the credits. Second, even though the revision stimulates the promotion of renewable energy projects, the projects might benefit beyond credits and not be additional in all cases. Third, the “AMS-I.A.” baseline calculations rely on counterfactual and uncertain information that might impede the measurability and accuracy of the projects’ credits. The main lessons to inform best practices in offset designs are the robust monitoring and review processes to improve the tests for additionality and reduce perverse incentives.

 identification for renewable energy lighting applications using AMS-I.A.” 

(submitted by Adriaan Tas, Carbon Africa Limited; SSC_581)

[Date of SSC WG meeting: January 30 - February 2, 2012, / SSC WG 35]

The query describes the project activity, which involves replacing the usage of kerosene lamps with the distribution of LED lighting technology. The project used the "AMS-I.A." methodology since the new methodology "AMS-III A.R.: Substituting fossil fuel-based lighting with LED lighting system” was not approved at the validation. Mr. Tas seeks to clarify the calculation of the project’s baseline emissions. The requestor quotes the definition of energy baseline (para. 8 of “AMS I.A.” version 14.0) and footnote 4 (Annex 1 of EB 08), which states that “Renewable energy lighting applications shall consider the equivalent level of lighting services instead of energy” (UNFCCC, 2012a; 2010b). 

Mr. Tas asks whether the energy baseline should be based on a) “the fuel consumption of kerosene lamps to generate the 

” or b) “the fuel consumption of kerosene lamps to generate the 

.” The requestor also assumes, due to the commonly used approach, as per paragraph the 

Guidelines on the consideration of suppressed demand in CDM methodologies

 (paragraph 12 b, version 1.0), “in the baseline the same service would be provided as under the project activity but with a different technology” (UNFCCC, 2012a). Also, the requestor describes the approach by “AMS III A.R.” (para 12f) to assume that one project lamp replaces one fuel-based lamp. Therefore, the requestor proposes to use the approaches used in AMS-III A.R" and the previous guidance due to the absence of clear guidance from "AMS-I.A." regarding the service level used (UNFCCC, 2012a).

The SSC WG notifies that since Option 3 of “AMS-I.A.” mentions lighting, the energy baseline should be a trend-adjusted projection of historic fuel consumption. The SSC WG reiterates the energy baseline definition and clarifies that footnote 4 refers to the "equivalent level of lighting services the project activity provides." However, it warns that renewable energy lighting application refers to the "equivalent level of lighting services as provided by the project activity," not surpassing the baseline, which is estimated “based on a trend-adjusted projection of historic fuel consumption used for lighting” (UNFCCC, 2012a, p.2).

The SSC WG clarifies that in the case of this project activity, baseline emissions should be based on the fuel consumption of kerosene lamps to produce the 

 offered by LED lighting technology. However, they should be capped at the baseline value, calculated from the trend-adjusted projection of historic fuel consumption used for lighting. The SSC WG explains that this cap is necessary since the amount of energy required by baseline traditional kerosene technologies to deliver equivalent services on the project lighting level will be substantial and, thus, provide the unrealistic basis of emission reductions. The SSC WG advises using the 

Guidelines to consider suppressed demand in CDM methodologies

 (version 1.0.) to estimate the cap by referring to the concept of minimum service level. The SSC WG notifies that “AMS-I.A.” (version 14.0) also has these built-in caveats/cap in options (a) to (c) of paragraph 8. It advises the project proponent to either use “AMS-I.A.” with the aforementioned interpretation or “AMS-III.A.R.” Lastly, the SSG WG advises that “AMS-I.A.” might probably be revised to account for the situations of suppressed demand so that the project participant might wait for such a revision as an alternate option (UNFCCC, 2012a)

In the meeting report (paragraph 37 of SSC WG 35), SSC WG agrees to clarify that the equivalent level of lighting services denotes "the equivalent level of lighting services provided by the project activity.” However, if Option 3 is applied, SSC WG warns about the following caveat: the equivalent level of lighting services cannot exceed the trend-adjusted projection of historic fuel consumption used for lighting. SSC WG also notifies that “AMS-I.A.” most likely will be revised, following the work program about suppressed demand, mentioned in EB 63, annex 30 (UNFCCC, 2012a; 2011c).

The clarification/revision regarding baseline identification for renewable energy lighting applications has positive and negative implications.

 aspects of the proposed changes. First, it provides clarity and consistency about baseline identification for renewable energy lighting applications to project developers, who used “AMS-I.A.” at validation when "AMS-III.A.R." was unavailable. Second, the change is appropriate, conservative, and limits uncertainties. For example, SSC WG gives an option to either use "AMS-I.A." with the above interpretation of "AMS-III.A.R." Third, such a clarification/guidance ensures the environmental integrity of the credits since SSC WG advises how to use Option 3 correctly in calculating the energy baseline for the project. It warns about the cap at the baseline value derived from the trend-adjusted projection of historic fuel consumption used for lighting. SSC EG explains that, otherwise, “the amount of energy required by baseline traditional kerosene technologies, to deliver equivalent service levels provided by project facilities (project lighting level) is unrealistically very large that it cannot be used as a realistic basis of emission reduction” (UNFCCC, 2012a, p. 2). Fourth, the clarification/revision also addresses the issue of suppressed demand in its explanation to the project participant by pointing to the built caveats/cap in the "AMS-I.A." methodology. According to Gavaldao et al. (2013), suppressed demand is defined as an “unmet latent demand for basic services” (p. 3). Fifth, the careful clarification of the “AMS-I.A." methodology for renewable energy lighting applications is helpful in light of the goals of the CDM, which strives for "real, measurable, and long-term benefits related to the mitigation of the climate change" (Hart, 2022a).

 aspects of the proposed changes. First, although the clarification/revision stimulates the promotion of renewable energy projects in lighting applications, the projects might benefit beyond credits and not be additional in all cases. Second, the “AMS-I.A." baseline calculations rely on counterfactual and uncertain information that might impede the measurability and accuracy of the projects' credits. Third, third-party monitors will know less about the true intentions of project participants. The main lessons to inform best practices in offset designs are robust monitoring and review processes to ensure the accuracy of baseline value cap calculations in capturing the issue of suppressed demand and improving the tests for additionality.

 emission calculation for off-grid CFL-LED lighting projects” 

(submitted by Vikas Menghwani, Emergent Ventures India Pvt, Ltd.; SSC_598)

The stakeholder requests clarification about the calculation of baseline emissions for off-grid CFL-LED lighting projects in India. The project entails the installation of a power generation facility in off-grid Indian villages (30kW micro-scale biomass-based) and developing power distribution infrastructure. The delivered electricity is being utilized by the users of CFL lamps, which the project participant provides. Such CFLs (AC-based non-rechargeable) are lit as long as the power is given during the day. Households pay a monthly fixed rental fee to pay for the electricity used by these lamps. The project participant may supply users with pre-paid meters and smart monitoring. Each household uses a fuse to stop the illicit usage, other than lighting the CFLs. The baseline emissions represent kerosene-based lamps utilized by the community households in the absence of the CFL lamps. Due to the small capacity of each generation unit, the stakeholder plans to develop such a project as a PoA, which will cover all Indian states (UNFCCC, 2012b).

Mr. Menghwani asks if “AMS-III.A.R. – Substituting fossil-based lighting with LED/CFL lighting systems” methodology (has an extended scope to cover the installation of battery-charged CFLs to replace kerosene lamps) applies to this project. He believes that the "AMS-III.A.R.” methodology’s default factors and other assumptions simplify the calculation of baseline emissions. If the project is not applicable under “AMS-III.A.R.,” then the stakeholder proposes the following revisions to the SSG EB: a) make the “AMS-III.A.R.” applicable for non-rechargeable CFLs or b) make the “AMS-III.A.R.” baseline calculations applicable for “AMS-I.A.” projects (UNFCCC, 2012b).

The SSG WG believes that the following project should be covered under the "AMS-I.A." methodology if the proper measures are adopted to guarantee that the supplied electricity is only used for lighting purposes. The group also does not want to expand "AMS-III. A.R." to cover non-chargeable lighting systems, complicating the methodology. However, SSG WG believes that the provisions under “AMS-I.A.” will probably be revised to account for the suppressed demand. The SSG also advises the stakeholder to consult the response given by the SSG to SSC_581 (mentioned above) or follow the progress on the revision of “AMS-I.A.”

In the meeting report (paragraph 25 of SSC WG 35), SSC WG does not accept the suggested revision to the methodology to simplify baseline emission calculation for off-grid CFL lighting projects. SSC WG recommends checking the response that is provided to SSC_581 (mentioned above) and notifying that “AMS-I.A.” is considered as one of the candidate methodologies under work program on suppressed demand (EB 63, annex 30) (UNFCCC 2011c; 2012c).

The clarification/revision regarding the simplification of baseline emission calculation for off-grid CFL/LED lighting projects has positive and negative implications.

 aspects of denial of the revision request. First, the SSC WG’s denial of the revision request provides clarity and consistency to project developers who strive to replace kerosene lighting with LED lighting. Second, such a decision is appropriate, conservative and limits uncertainties about whether "AMS-III.A.R." with an extended scope covering battery-charged CFLs can be used for non-chargeable CFLs. Third, such a clarification/guidance ensures the environmental integrity of the credits generated by the project activity of PoA. For example, SSC WG reiterates the necessity of proper measures (installation of fuses) to ensure that the electricity will only be utilized for lighting purposes. Fourth, the clarification/revision also addresses the issue of suppressed demand in its explanation to the project participant and alerts them to follow the progress on the "AMS-I.A." revision (as mentioned in SSC WG's response to SSC_581). Fifth, the clarification of the "AMS-I.A.” methodology and denial for the expansion of scope “AMS-III.A.R." for renewable energy lighting applications is helpful in light of goals of the CDM, which strives for "real, measurable, and long-term benefits related to the mitigation of the climate change" (Hart, 2022a).

 aspects of the denial of the revision request. First, project developers (especially, in this case), perhaps, will incur higher costs to increase further monitoring efforts (third-party /project participant’s human monitoring of each household with a fuse) besides the planned smart monitoring and pre-paid meters to qualify under the “AMS-I.A.” methodology. This biomass-based project is already complicated with the necessity to utilize “TOOL16” and representative sampling, in the specific case of lighting devices, under the "Standard" methodology (UNFCCC, 2012b). Expanding costly and complicated procedures might dissuade the project participant from developing the PoA. Second, even if the project participants still consider promoting renewable energy projects in lighting applications, the projects might benefit beyond credits and not be additional in all cases. Third, the "AMF-I.A." baseline calculations rely on counterfactual and uncertain information that might impede the measurability and accuracy of the projects' credits. Fourth, even though SSC WG confirms the installation of fuses, 

, there is still a possibility for gaming for project participants and households in the project boundary. Fifth, third-party monitors will know less about the true intentions of project participants. The main lessons to inform best practices in offset designs are the robust monitoring and review processes to ensure the accuracy of baseline value calculations in capturing the issue of suppressed demand and improving the tests for additionality.

V. “Revisions of AMS-I.A. to cover project activity involving partial displacement of fossil fuel consumption”

(submitted by Andrea Rudnick Garcia, Ministry of Environment of Chile – Climate Change Office; 

[Date of SSC WG meeting: 20-23 March 2012 / SSC WG 36]

The query's author wants to resubmit a new request for registration of the project “Cabo Negro Wind Farm Project. Reg. 4103” since it was previously rejected by the EB, which decided that Option 3 for baseline emissions could not be applied to the project activity. The project is applicable under the "AMS-I.A." methodology. Ms. Garcia wants to resubmit the PPD by proposing a revision to calculate baseline emissions for wind farm projects, Option 4. This option considers that the fossil-based technology (the existing power generation system) may operate even after implementing a wind farm (proposed project activity). The option can be used only if the project participant can prove that the fossil-fuel generation is displaced by the wind farm energy generation (UNFCCC, 2012d).

Ms. Garcia states that, in the case of wind farm projects, the complete replacement of the existing technology, which provides backup energy for wind generation, is not possible. Consequently, Option 3 cannot be used to calculate baseline emissions calculations. In Option 4, the baseline emissions can also be calculated as a trend-adjusted projection of historic fuel consumption. However, "the replaced fossil fuel consumption will correspond to the division of wind electricity generation with the fossil fuel consumption efficiency calculated considering the energy generation and the fossil fuel consumption of the existing fossil fuel units" (UNFCCC, 2012d, p. 1). Ms. Garcia also points out the project participant, in the calculation of ex-post emissions reductions, must realize that if "ex-post calculated value for fuel consumption efficiency is higher than the ex-ante figure, it shall be used for the calculation of baseline emissions” (UNFCCC, 2012d, p. 2).

The SSC WG recommends the revision of “AMS-I.A.," as described in the SSG WG 36 meeting report (annex 3) (UNFCCC, 2012f).

In the meeting report (paragraph 37 of SSC WG 35), SSC WG agrees to clarify if the project activity displaces existing fossil fuel captive electricity generation, the emission factor of such a generation needs to be estimated using Scenario B of the "Tool to calculate baseline, project and/or leakage emissions from electricity consumption.” This provision was included in the revised version of the methodology (version 15.0.) (UNFCCC, 2012c; 2012h).

The clarification/revision regarding energy baseline calculation in case of project activity concerning partial displacement of fossil fuel consumption by wind generation has the following positive and negative implications.

 aspects of the proposed changes. First, the new option provides clarity and consistency about energy baseline calculation in case of partial displacement of fossil fuel power generation by wind farm power generation. Second, the change is appropriate, conservative, and limits uncertainties. For example, the project proponent describes the conservative nature of the rationale in the submission. She reiterates that the calculation of fixed ex-ante fuel consumption efficiency for the whole crediting period is not conservative in such projects. Instead, the monitoring and calculation of ex-post fuel consumption efficiency and the usage of such efficiency, if it is higher than the ex-ante number, will guarantee the most conservative estimation of energy baseline. Thus, revision and provisions ensure the environmental integrity of the credits in the cases of wind power generation partially displacing fossil fuel consumption. Third, the careful clarification of the “AMS-I.A." methodology for such cases is valuable in light of the goals of the CDM, which strives for "real, measurable, and long-term benefits related to the mitigation of the climate change" (Hart, 2022a).

 aspects of the proposed changes. First, although the clarification/revision stimulates the promotion of renewable energy projects in wind farm projects, the projects might benefit beyond credits and not be additional in all cases. Second, the "AMF-I.A." baseline calculations rely on counterfactual and uncertain information that might impede the measurability and accuracy of the projects' credits. Third, third-party monitors will know less about the true intentions of project participants. The main lessons to inform best practices in offset designs are robust monitoring and review processes to ensure the accuracy of fuel consumption efficiency (ex-post versus ex-ante) and improve the tests for additionality. Section 4 describes applying "AMS-I.A" methodology to the registered project, Cabo Negro Wind Farm Project, (Phase 1).

of AMS-I.A. for off-grid project activity involving end-users connected to a grid with frequent blackouts/brownouts”

(submitted by Vladislav Arnaoudov, Mitsubishi UFJ Morgan Stanley Securities; 

The query discusses the interaction between the stakeholder and the SSC EG. Mr. Arnaoudov seeks clarification about a possible project (new hydropower plants not exceeding 1.5MW) in Tajikistan, where the power grid supply is unreliable and does not deliver good services. This situation is observable in other CIS countries. In this case, the baseline emissions will not be grid electricity but instead, potentially, represent the baseline as described by the "AMS-I.A."(version 14.0) (UNFCCC, 2010a; 2010b). In this case, the baseline emissions will come from diesel generation. Some households would have zero access to electricity due to the absence of a grid electricity supply. Mr. Arnaoudov proposes to install simple devices (costing approximately 100 Euros), which can record the time when electricity supply started and stopped. This device can only be accessed by authorized personnel with a built-in memory or memory card. The stakeholder proposed considering the "grid is not available" condition for a particular day when there is no electricity supply from the power grid for more than 12 hours out of 24 hours. The mini-grid and the power grid will not be interconnected during the crediting period. The stakeholder agrees to the strict “AMS-I.A.” applicability condition and monitoring procedures, so the project does not claim emissions reductions during the mini-grid/power grid connection (UNFCCC, 2012e).

SSC WG clarifies that "AMS-I.A." applies only to users/households connected to the grid before the start of the project activity. Still, the electricity is not available for users/households for less than 36 hours per calendar month during the crediting period. Also, in such conditions, the applicability of the project activity will be ascertained with continuous power monitoring during any given calendar month. The CERs calculation under “AMS-I.A.” will be possible for users/households who receive power from the grid for less than 36 hours for any given calendar month. The CERs calculation is not allowed for any hours when power is available from the grid for users/households. “AMS-I.A.” will not be applicable if the project activity gets connected to the grid during the crediting period (UNFCCC, 2012e).

In the meeting report (paragraph 28 of SSC WG 36), SSC WG agreed to clarify the “AMS-I.A.” applicability, based on actual monitoring, if users/households involved in project activity receive grid power for less than 36 hours (or about 5% of the time) in any given calendar month. The CER calculations can include the months during which users/households sustain such conditions. A special provision for this approach was included in the revised version 15.0. of this methodology (Annex 3 of SSC WG 36) (UNFCC, 2012f, 2012g).

The clarification/revision regarding the applicability of "AMS-I.A." for off-grid projects, which involves end-users connected to a grid with recurrent blackouts/brownouts, has positive and negative implications. As mentioned earlier, the integrity of applicability conditions is crucial for consistency of outcomes across host countries, avoidance of gaming, and clarity of methodology scope.

 aspects of the proposed changes. First, the proposed revision provides consistent outcomes since outcomes will not differ between host countries (especially CIS countries) in similar conditions and with similar ambitions. Second, 

, the provision outlines strict and continuous monitoring procedures during any calendar month as safeguards against gaming by the project participants and, thus, promoting the environmental integrity of the emissions credits. Third, the revision clearly defines project types and specific applicability conditions (end-users connected to a grid with frequent blackouts/brownouts) that fall under the “AMS.-I.A.” methodology scope. Fourth, the careful clarification of the “AMS-I.A." methodology for such cases is helpful in light of the goals of the CDM, which strives for "real, measurable, and long-term benefits related to the mitigation of the climate change" (Hart, 2022a).

 aspects of the proposed changes. First, although the clarification/revision stimulates the promotion of renewable energy projects (in this case, mini-hydro plants projects), the projects might benefit beyond credits and not be additional in all cases. Second, the data (from the simple devices with built-in memory/memory card) for the continuous power monitoring required to verify the applicability of the project under the "AMS-I.A." might become unreliable due to data tampering by corrupt authorized personnel. Hart (2022c) also describes common problems with the equipment since it can be not installed correctly, is not performing, or is not appropriately calibrated. Third, third-party monitors will know less about the true intentions of project participants so that the third-party monitoring data might also become unreliable. The main lessons to inform best practices in offset designs are strong monitoring and review processes to ensure the accuracy/reliability of continuous power monitoring information and improve the tests for additionality. The following section briefly describes a case study, focusing on applying the “AMS- I.A” methodology to the actual CDM small-scale project.

: Cabo Negro Wind Farm Project, Phase I (version 3.0.)

Completion date of the Project Design Document (PDD):

Sectoral scope(s) and selected methodology(ies):

The estimated amount of annual average GHG emissions reductions:

The project involves wind farm generation, replacing electricity generated onsite by natural gas (fossil-fuel-based generation) in Methanex Chile S.A.'s facilities. Methanex is the largest global supplier of methanol to various international markets. The Cabo Negro wind farm project is a pioneer wind generation project both in the region and for Methanex. It is located in the south of Chile, in the Cabo Negro industrial complex in the Magallanes Province in the 12thRegion of Chile. The Methanex industrial complex does not have a grid connection. All electricity needed for the methanol production is produced onsite. The project considers the operation of three wind turbine generators, each with a capacity of 850 kW. The GHG reductions (estimated at 10,436 tCO2) depend on the variable performance of the wind power generation (UNFCC, 2012l). The project satisfies the following conditions under “AMS-I.A.” methodology (version 15.0) (UNFCCC, 2012h):

a) the project activity supplies energy to users that do not have grid connection; b) the project is not a cogeneration system or a hydropower plant with reservoirs; c) the project only considers the addition of a renewable component to the system; and d) the project’s installed capacity is estimated to be 2.55MW, which should not exceed the limit for CDM small-scale projects.

a) Baseline – natural gas (fossil-fuel) power units in Methanex facilities with inclusion of CO2 and exclusion of CH4 and N20.

b) Project Activity: wind power electricity generation through three generators and associated equipment in the Methanex facilities.

Transformation of small-scale methodology (AMS-I.A.): Electricity generation by the user

Cryptocurrency technology can play a significant role in revolutionizing voluntary carbon markets. The voluntary carbon markets (VCM), where companies and individuals trade carbon credits voluntarily, propel investment in carbon neutralization (removal) and compensation (avoidance and reduction) projects (McKinsey, 2021). The current VCM is complicated due to fragmented carbon standards, liquidity, and choices for corporate demand and retail. The existence of countless trading exchanges and an absence of clarity about the carbon offset quality also complicate the VCM’s expansion for climate-benefiting efforts (KlimaDAO, 2022).

Cryptocurrencies are “digital tokens used to transfer money between individuals’ computers with minimal fees” (Vigna, 2021). The crypto market consists of the original cryptocurrency, Bitcoin, and alternative coins, such as Ethereum, Dogecoin, XRP, Litecoin, and Monero (Nakamoto, 2008, Terrapass, 2021). Cryptocurrency is based on blockchain technology. The blockchain is an open-access ledger that runs on the global distributed network of computers to verify and record digital assets and their transactions (Terrapass, 2021). The blockchain underlies the concept of Web3, which is a “decentralized online ecosystem” based on this technology (Edelman, 2021). The data structure differentiates a blockchain from a typical database. Whereas a database collects information into tables, a blockchain structures the data into groups or blocks (Phiel, 2022). When a block of data or record is inputted into the ledger, the block’s information is connected to the previously filled blocks, forming a chain of data known as a blockchain. Each block is signed with a unique signature per the sequence of data in that specific block (Acharya et al., 2020).

This article explores how cryptocurrency technology can enhance the VCM’s development. The analysis builds upon various case studies and quantitative indicators, wherever possible, to review the technology's valuable features, including transparency, value transfer, and cost reduction. The analysis also considers challenges when incorporating cryptocurrency into the VCM. The following section describes cryptocurrency technology opportunities for the VCM in the joint fight against climate change.

Opportunities of Cryptocurrency Technology

First, transparency represents one of the valuable aspects of cryptocurrencies. Transparency through information disclosure is paramount for global environmental governance to ensure legitimate, accountable, and effective governance. Cryptocurrencies and the technology that powers them offer an immutable data source as well as a verifiable and traceable record of transactions and their participants (Acharya et al., 2020). Moreover, since the blockchain is resistant to fraud and meddling, it is helpful in regions with vulnerable institutions and a high level of corruption (McKenz, 2021). Recently, technology has grown into a powerful tool for climate finance, requiring traceable and transparent data to monitor and measure climate impact (Sandor, 2022). The cryptocurrency technology also serves as the decisive driver for transparency and innovation within the VCM. For instance, an industry group, the Taskforce on Scaling Voluntary Carbon Markets (TSVCM), claims that the efforts to ease the traceability and trading of carbon credits, through the public recording of transactions, will lead to the growth in the number of companies, which can utilize offsets for their climate objectives (Holger, 2022). 

Moreover, “new players in Web3 have driven a renaissance in the voluntary carbon market” (Purdom and Zou, 2022, para.30). Namely, KlimaDAO, a Regenerative Finance (ReFi) project, states that its efforts improve transparency in the VCM. This organization utilizes the infrastructure developed by Toucan Protocol and Moss.Earth, the decentralized finance (DeFi) projects. The infrastructure allows high-integrity carbon credits, issued through carbon standards’ stringent processes, namely Gold Standard and Verra, to be bridged onto the blockchain. As soon as carbon credits get transferred, they can integrate with other DeFi applications and obtain the transparency needed in the VCM (KlimaDAO, 2022). Another ReFi project, Regen Network, focuses on constructing an on-chain registry ecosystem for carbon claims and incorporating data into the VCM with Regen Registry to monitor the carbon data and methodologies (Regen Network, 2022). Therefore, the transparency enabled by the cryptocurrency technology can help alleviate the VCM’s opacity and repair the fragmentation of its carbon standards. Transparency is closely connected with value transfer, the next important feature of cryptocurrency technology.

Second, cryptocurrency technology facilitates efficient value transfers without a centralized authority. Like cross-border payments, value exchanges usually include multiple steps and participants in their processes. Various entities also participate in carbon credit trading. For instance, the Kyoto Protocol’s Clean Development Mechanism (CDM) involved multiple national and global registries and took years to verify projects and validate the credits’ transfers (Acharya et al., 2020). The cryptocurrency use cases in the VCM demonstrate that blockchain’s decentralized ledger enables efficient value transfers without a centralized party. For example, the Toucan Bridge created by Toucan Protocol allows a value transfer by allowing the owners of carbon credits to link them to Web3 assets. The credits are permanently retired on the traditional registry to prevent double-spending. The blockchain beneficiary (an Ethereum wallet address) is included in the public retirement message. After bridging, users can receive project-specific TCO2 (Toucan CO2) tokens, which retain metadata from the original carbon credits. These tokens can be retired, transferred, held, or deposited into a Carbon Pool. In turn, the depositor of TCO2 tokens obtains Pool reference to tokens, such as BCT (Base Carbon Tonne), on a 1:1 basis (DiAngelis, 2022). BCTs can then be traded on cryptocurrency exchanges (Holger, 2022).

BCT has one of the highest trading volumes on the Polygon network, generating more than $100 million in weekly volume. In contrast, the traditional VCM amassed only $1 billion for the entire year of 2021 (DiAngelis, 2022). Furthermore, BCT can be used as a building block for other Web3 players, such as KlimaDAO, which allows trading BCT tokens for KLIMA tokens. KlimaDAO keeps the BCT tokens in its treasury, eliminating them from circulation to prevent their usage for carbon offsets. At the same time, KLIMA tokens can be traded as carbon-backed cryptocurrencies (Holger, 2022). In 2022, it was estimated that over 200 million TCO2 (annualized) would be traded through KLIMA pools on Decentralized Exchanges (DEXs). In contrast, in 2019, only nearly half of this volume of carbon offsets was traded in the legacy VCM (KlimaDAO, 2022). Also, on February 17, 2022, KlimaDAO launched Klima Infinity program that gives "protocols and corporates the opportunity to manage their carbon offset program via Klima and further accelerates the on-chain carbon market" (KlimaDAO, 2022). Thus, such examples show that cryptocurrency technology can help value transfer and provide choices for corporate demand and retail, enhancing the liquidity and growth of the VCM. The innovative on-chain value exchange between VCM’s participants relates to cost reduction, the following helpful feature of cryptocurrency technology.

Lastly, the use of cryptocurrency technology can lead to significant cost reduction. Blockchain-based applications can advance operational efficiencies since global data processing takes ample time. In the short term, the strategic value of peer-to-peer transactions is primarily focused on cost reduction (Carson et al., 2018). The technology’s self-auditability reduces the cost of multi-layered reporting. So, eliminating the administrative archiving process and intermediaries can significantly reduce administrative and transactional costs (Acharya, 2020). Namely, the United Nations World Food Program (WFP) successfully used Ethereum Blockchain in its pilot program, Building Blocks, to deliver humanitarian cash to recipients in Pakistan and Jordan. The program allowed cash transfers through pre-paid debit cards and vouchers, permitting people to buy food on their own in these countries. The program results showed the reduction of payment costs connected to cash transfers and reached a 98% cost reduction due to the peer-to-peer structure of blockchain-enabled transactions (Acharya et al., 2020).

Participants in the VCM can also realize similar cost savings resulting from cryptocurrency technology. DeFi’s interoperable applications can reduce VCM’s global data processing time. For instance, the Toucan Protocol's BCT pools permit any tokenized carbon project from 2008+ vintage to be deposited in its pool. This process enables the carbon credit suppliers to deposit their credits into the Automated Market Makers (AMMs) on DEXs and instantly locate an off-taker for their BCTs. At the same time, the buyers do not need to engage with numerous suppliers for price discovery and demand fulfillment. Instead, the buyers can instantaneously access BCTs on a DEX. This innovation overcomes the “key failure at the interface between supply and demand” (KlimaDAO, 2022).

Another cost reduction is related to the public and accessible data disclosure on the blockchain. To understand market trends, participants often have to pay for retrospective data from centralized registry databases about VCM players to perform market and transaction analyses. In contrast, the technology provides unparalleled data availability and transparency, which never existed in the legacy carbon markets. Namely, VCM participants can use a block explorer, such as Polygonscan, to search for the blockchain blocks with the associated metadata about carbon offsets. Specifically, they can freely view particular carbon pools' price history, spot prices, and transaction volumes. VCM participants can also search for the composition/ number of offsets bridged from various entities and see the on-chain usage of tokenized carbon offsets (KlimaDAO, 2022). Thus, cryptocurrency technology may reduce transaction and administrative costs for VCM's market participants. However, blockchain users can achieve vast operational cost reductions in limited settings since the technology remains a “very resource-intensive and computationally inefficient data structure" (Acharya, 2020). In other words, these hurdles need to be considered when scaling up the VCM. The following section describes some of the challenges of cryptocurrency technology.

First, high energy consumption is a crucial technical challenge for cryptocurrency technology. Terrapass (2021) warns that "even as the popularity and acceptability of cryptocurrencies surge, there is a greater and greater recognition of the crypto economy's strain on the environment” (para 12). In other words, the enormous level of power intensity required for blockchain networks might hinder the fight against climate change. For example, Bitcoin and other proof-of-work (PoW) cryptocurrencies need abundant energy (Acharya et al., 2020). During the PoW process, the crypto coins are “mined” (the method to create new coins) through an ultra-competitive process during which miners compete to solve numerous complicated mathematical puzzles. The crypto coins are granted to the first miner who successfully solves the puzzle. Bitcoin generates the highest amount of competition, requires significant computing power, and, thus, requires the highest power usage, about 91 terawatt-hours of electricity annually (Terrapass, 2021). Due to significant energy consumption, one can find large-scale crypto mining operations in locales with highly subsidized and low electricity prices (Acharya, 2020).

The adoption of renewable energy sources can serve as one of the possible solutions for the power density required for mining operations. Alternative consensus systems, such as Proof-of-Authority (PoA) and Proof-of-Stake (PoS), also consume less energy (Acharya, 2020). For instance, Ethereum has started shifting towards the PoS method, eliminating the competitive race and requiring less processing power. This method is supposed to lessen the environmental impact of this cryptocurrency by 99%. Lastly, in 2021, Crypto Climate Accord, a private sector partnership, emerged to decarbonize cryptocurrency technology. The United Nations Framework Convention on Climate Change (UNFCCC)’s Climate Champions supported this initiative (Terrapass, 2022). Therefore, despite the concern about the high energy consumption of cryptocurrency technology, new solutions can reduce its current carbon footprint, especially during the VCM's transformation. This technical challenge is related to the non-technical challenge, the lack of understanding of the cryptocurrency technology.

The lack of comprehension about cryptocurrency technology and its applications represents a widely-recognized non-technical challenge. For example, the following issues bring confusion to consumers and investors, such as 1) costs and benefits of blockchain in contrast to conventional financial services, 2) access to digital technologies, 3) security of the cryptocurrencies, and 4) privacy issues on transactions (The World Bank, 2018; FSB, 2022). Carson et al. (2018) also discuss common blockchain myths, which lead to misconceptions and hesitation about the wider technology adoption. In addition, high price volatility and low price explainability perpetuate the lack of understanding and hesitation about cryptocurrencies. Namely, KLIMA’s market performance has been choppy, for example, with prices dropping from its highest historical close price of $3,683.57 (as of October 25, 2021) to $1.67 (as of January 18, 2023). Trading volume dropped from $72,946,871 (as of October 29, 2021) to $20,340 (as of January 18, 2023) (Coinmarketcap, 2023).

However, despite such volatility, the emerging players in the VCM markets still try educating the public about the technology and its applications. For example, the frequent newsletters and updates from the emerging crypto players in the VCM markets, such as KlimaDAO, Regen Network, and the Toucan Protocol, aid in educating people about the collaboration of the crypto and carbon markets. Thus, increasing crypto awareness and education remains essential to better understanding and the continued adoption of cryptocurrency technology in the VCM. The following section illustrates the last, but not least, challenge for the collaborative efforts between the VCM and the crypto world.

The current uncertainty about regulatory issues may hinder the further expansion of cryptocurrency technology in various sectors. The overall commercial scalability of the technology is difficult without the resolution of problems related to information reporting, money and value transmission, privacy, and anti-money laundering. For example, the European Union’s General Data Protection and Regulation (GDPR) delineates stringent limitations on the saving and storage of personal data. GDPR’s “right to be forgotten” goes against the premise of blockchain’s immutable data storage (Acharya et al., 2020). In the United States, lawmakers strive to regulate cryptocurrencies since they believe that the hype about Web3 assets adversely hurts investors (Kierman, 2022). At the same time, the Crypto Council for Innovation, a crypto lobby group, strives to reshape the narrative around these assets while pushing back against the significant regulatory headwinds (Versprille, 2022).

Fortunately, the VCM has a lower exposure to regulatory risks than compliance carbon markets (CCM). CCM is a market in which the trading of carbon allowances is regulated by mandatory international, national, or regional regimes (McKinsey, 2021). However, the regulatory uncertainties may negatively affect the collaboration of the VCM and cryptocurrency technology. Therefore, regulatory clarity around cryptocurrencies is necessary for broader adoption of the technology’s applications at the intersection of carbon and climate.

This article describes the opportunities and challenges of cryptocurrency technology for voluntary carbon markets. The technology equipped with transparency, value transfer, and cost reduction can be a powerful tool while aiding VCM’s growth and transformation. TSVCM warns that the VCM volume needs to reach a 15-fold scale-up by 2030 to deliver the 1.5 °C- pathway to avoid the worst effects of climate change (KlimaDAO, 2022). High energy consumption, the lack of a better understanding of cryptocurrency technology, and regulatory issues represent only a few challenges to successful cooperation and collaboration of the crypto and the traditional VCM. Preparing for additional hurdles, ReFi pioneers realize the necessity of establishing “mutual trust and mechanisms to ensure quality carbon and integrated working relationships between industries” (Regen Network, 2022).

Since climate change is the most critical issue for our generation, new tools are urgently required to attain climate goals faster. While cryptocurrency technology is not the only available instrument in the fight against climate change, it can become a valuable partner for new climate solutions under Article 6 of the Paris Agreement.This topic requires more in-depth consideration in future studies.

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Venera N. Anderson

Venera N. Anderson

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