Authors
Elena Krieger, PhD | PSE Healthy Energy
Bethany Kwoka, MAS | PSE Healthy Energy
Boris Lukanov, PhD | PSE Healthy Energy
Acknowledgements
We are grateful to Theo Caretto, Shana Lazerow, Arjun Makhijani, Drew Michanowicz, Seth
Shonkoff, and Adrienne Underwood for their insight and feedback during the development of
this report. Any errors or omissions remain our own.
About PSE Healthy Energy
PSE Healthy Energy is a nonprofit research institute dedicated to supplying evidence-based
scientific and technical information on the public health, environmental, and climate
dimensions of energy production and use. We are the only interdisciplinary collaboration
focused specifically on health and sustainability at the intersection of energy science and
policy. Visit us at psehealthyenergy.org and follow us on X @PhySciEng.
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510-330-5550
www.psehealthyenergy.org
info@psehealthyenergy.org
2 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Table of Contents
Executive Summary 4
1. Introduction 11
1.1 Goals of This Report 11
1.2 Outline of This Report 13
2. Overview of the Hydrogen Landscape in California 14
3. Background on Proposed Hydrogen Production and Use 19
3.1 Energy Efficiency of Proposed Hydrogen Production, Storage, and Transport Methods 20
3.2 Energy Efficiency of Hydrogen Use 39
4. CARB Scoping Plan: Hydrogen Energy Requirements and Compounding Interactions with DAC
and CCS 52
4.1 Summary of CARB Scoping Plan Hydrogen Energy Requirements 53
4.2 Hydrogen Production Under the Scoping Plan 55
4.3 Direct Air Capture Energy Inputs in the Scoping Plan 64
4.4 Carbon Capture and Storage Energy Inputs in the Scoping Plan 67
4.5 Cumulative Energy Requirements of Hydrogen, DAC, and CCS 68
5. Climate Considerations 72
5.1 Greenhouse Gas Implications of Hydrogen Use 72
5.2 Hydrogenʼs Indirect Climate Impacts 73
5.3 Comparing Hydrogen Adoption Pathways and Alternatives 77
6. Health and Safety Risks, Equity, and Unknowns 79
6.1 Hydrogen Combustion 79
6.2 Biofuel Feedstocks and Ammonia 85
7. Case Study: Repowering Scattergood with Hydrogen 87
8. Key Findings, Policy Considerations, and Recommendations 92
8.1 Key Findings 92
8.2 Key Policy Considerations and Guiding Questions to Address Unknowns 95
8.3 Recommendations 98
References 101
3 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Executive Summary
Local and state governments across California have set ambitious goals to mitigate greenhouse gas
emissions in the coming decades. In recent years, policymakers, utilities, and other planners statewide
have increasingly relied on green hydrogen as a component of their plans to meet climate targets, yet
our review of these plans has found that they rarely align. Statewide, decision-makers have set a wide
range of targets for green hydrogen deployment, with different primary end-uses, timelines, and
definitions of what makes hydrogen “green” or “clean.” In many cases, these plans also lack sufficient
detail to fully characterize the potential impacts—positive and negative—of proposed hydrogen
deployment strategies. The adoption of green hydrogen—and its role in the economy-wide energy
transition that California will undertake in the coming decades—holds implications for climate change,
public health, equity, safety, cost, the environment, and the overall feasibility and speed of achieving
the Stateʼs climate goals.
In this report, we review current plans for green hydrogen adoption to support Californiaʼs climate
goals, and also discuss potential adverse consequences associated with its proposed deployment.
Where there is insufficient information, we outline the key questions that must be addressed to better
understand the impacts of these proposals. The questions that guide our report largely fall into two
categories:
1) What are the direct impacts of hydrogen adoption across multiple applications (for example,
what are the potential public health hazards of using hydrogen compared to existing fossil fuel
use or other clean alternatives?);
2) What are the indirect and system-level impacts of proposed hydrogen strategies (for
example, how does proposed hydrogen adoption change the required rate of renewable
energy deployment in the next twenty years?).
The proposed adoption pathways for green hydrogen vary significantly by plan. For instance:
● The California Air Resources Boardʼs (CARB) 2022 Scoping Plan for Achieving Carbon
Neutrality allocates the majority of hydrogen to transportation, proposes blending hydrogen
into existing natural gas pipelines, and only uses hydrogen in power plants for emergency
backup.
● In contrast, the Los Angeles Department of Water and Powerʼs (LADWP) Strategic Long
Term Resource Plan aims to repower all of its natural gas plants by 2035 to burn hydrogen to
meet regular power demand.
● Meanwhile, the federally-funded Alliance for Renewable Clean Hydrogen Energy Systems
(ARCHES) hydrogen hub supports hydrogen use in power plants and for transportation but
does not propose blending it into existing natural gas distribution pipelines.
4 | Green Hydrogen Proposals Across California | PSE Healthy Energy
This misalignment exists across all aspects of the proposed green hydrogen system, including where
and how it is produced, how it is transported, how it is used, and how soon its adoption will take place.
The enactment of conflicting plans by local and state planners raises the risk of energy security and
reliability challenges. These challenges emerge when there are numerous local and state planners
relying on different end uses for a limited hydrogen supply or who have varying expectations for the
renewable energy that might be used to produce it. This lack of coordination may also undermine the
ability of local and state planners to meet their climate goals. It could also result in inefficient
infrastructure investments and potential stranded assets.
While many of the proposed hydrogen adoption pathways lack the detail to fully evaluate their
outcomes, the direct and system-level impacts of each plan can be organized into key categories.
These categories, with relevant examples, include:
Climate Change. The climate impacts of hydrogen adoption depend largely upon:
● How “Green” or “Clean” Hydrogen Is Defined. Defining hydrogen as “renewable,” “green,”
or “clean” depends largely on the greenhouse gas footprint of the energy source (e.g., biogas,
wind energy, grid electricity) used to produce that hydrogen. However, there is no clear
consensus for defining what counts as “renewable” in this context, nor for calculating the
greenhouse gas footprint of hydrogen production. ARCHES, for example, has supported the
use of existing renewable energy resources to produce hydrogen. Using existing resources risks
increasing greenhouse gas emissions by redirecting energy that might have previously
displaced the need for natural gas power generation, causing natural gas use to increase.
● Indirect Atmospheric Climate Impacts. Hydrogen is not a greenhouse gas, but it can
indirectly contribute to climate change when leaked into the atmosphere by affecting the
concentration of other greenhouse gases. This effect means that the global warming potential
of hydrogen is roughly 37 times higher than that of carbon dioxide over a 20-year period and
about 8–12 times higher over a 100-year period, although these estimates are an active area of
study. Unfortunately, hydrogen leakage rates are poorly characterized system-wide and are
rarely accounted for when evaluating the climate benefits of hydrogen adoption across
California.
● Deployment Pathways and Alternatives. The climate impacts of hydrogen adoption depend
on which energy source it is displacing, which alternatives might exist for that end-use, and
how the energy needed to produce hydrogen might otherwise be used. Examples include:
○ Burning hydrogen at a power plant, as proposed by LADWP, uses roughly two to four
times as much energy compared to solar+battery storage (when this alternative is
feasible). Producing hydrogen with renewable electricity, transporting it to a power
plant, and then burning it is likely less than 35 percent efficient overall, and possibly
much lower (although very few 100 percent hydrogen turbines are commercially
5 | Green Hydrogen Proposals Across California | PSE Healthy Energy
available, so these values are somewhat speculative). Therefore, using renewable
energy and battery storage directly would enable three times as much fossil fuel to be
displaced—and displace three times the amount of greenhouse gas emissions.
○ The CARB Scoping Plan proposes to blend hydrogen into natural gas pipelines at a
level of 20 percent by volume. However, this blend only displaces a maximum of 6–7
percent of greenhouse gas emissions because hydrogen is less dense than natural gas
(a 20 percent hydrogen by volume blend is only 6–7 percent hydrogen on an energy
basis), and even less if any hydrogen leaks. If the goal from pipeline blending is to
decarbonize home heating, air source heat pumps are a more effective option, as they
require roughly one-fih the renewable electricity as burning hydrogen to heat a
home.
Energy System. To reach the stateʼs 2045 climate neutrality targets—which is the goal of the CARB
Scoping Plan—California will have to rapidly deploy renewable energy resources such as wind and
solar. CARB does not include the energy used to produce hydrogen in their energy resource build
estimates, so we incorporate that demand as well. CARB also excludes the energy required for two
other key components of their climate mitigation portfolio: direct air capture of carbon dioxide and
carbon capture and storage (CCS). Deployed simultaneously, these carbon-mitigation technologies
risk competing for a potentially limited supply of renewable resources. We therefore estimate the
deployment rates needed to meet the combined demand for all climate mitigation strategies in 2045
to better understand their compounding impact on renewable energy requirements.
● Scoping Plan Base Case. CARB estimates that it will need a total of 128 gigawatts (GW) of new
renewable energy capacity in 2045. We estimate that this deployment will require doubling the
historic average annual construction rate of wind and solar and maintaining this build rate
every year until 2045—which is also an average construction rate equivalent to the maximum
renewable energy ever deployed in California in a single year.
● Scoping Plan Base Case Plus Hydrogen. However, the Scoping Planʼs base deployment rate is
likely an underestimate; the Scoping Plan does not include the energy required to produce
hydrogen or to meet other demands such as the direct air capture of carbon dioxide. Instead,
the Scoping Plan states that this demand will be met with “off-grid” solar and, for 36 percent of
the hydrogen used in 2045, with biofuels. We estimate that 26–29 GW of off-grid solar would be
needed to meet the hydrogen demand under the Scoping Plan. This estimate grows to 41–45
GW if biofuels cannot be scaled up to produce hydrogen, leading to a total of 20–35 percent
more renewable capacity that must be built by 2045.
● Scoping Plan Base Case Plus Hydrogen, Direct Air Capture of Carbon Dioxide, and CCS.
Moreover, the energy required for direct air capture in the Scoping Plan would require an
additional 73 GW of solar; the energy required for CCS would add another 10 GW. Altogether,
these combine to approximately 250 GW of new renewables by 2045, which would require
nearly quadrupling Californiaʼs historic average annual renewable energy deployment rate.
6 | Green Hydrogen Proposals Across California | PSE Healthy Energy
● Scoping Plan Base Case Plus Hydrogen, Direct Air Capture, and Hydrogen in Place of CCS.
The California Energy Commission has explored an additional contingency in which the
remaining natural gas plants in CARBʼs Scoping Plan all burn hydrogen in 2045. This
contingency, combined with the above requirements, could require up to 4.3 times the historic
average annual growth of renewables. This level of renewable energy deployment is ambitious
for all scenarios, and highlights the competing demands for renewable energy resources to
simultaneously meet numerous proposed demands in 2045, including renewable energy
targets in the power sector, hydrogen production, and direct air capture.
Public Health and Equity. The public health hazards of hydrogen vary by application, and have
significant equity implications. Currently, fossil energy production, transmission, and use are the
largest sources of criteria air pollutants, toxic air contaminants, and other health damaging air
pollutants of any sector in California. Low-income communities and communities of color are
disproportionately exposed to these emissions. As such, the deployment of hydrogen to displace fossil
energy holds multiple potential equity implications, both positive and negative. These impacts
depend, in part, on the hydrogen technology used:
● Fuel Cells. Hydrogen applications that displace fossil fuel combustion, such as running
heavy-duty trucks on hydrogen fuel cells rather than diesel fuel, have the potential to reduce
criteria air pollutant and toxic air contaminant emissions and thus provide public health
benefits, particularly in environmentally overburdened communities such as those next to
freeways.
● Combustion of Hydrogen. However, burning hydrogen (rather than using a fuel cell) produces
nitrogen oxides (NO
x
), similar to burning natural gas. Exposure to nitrogen dioxide (NO
2
), is
associated with respiratory health impacts and contributes to the atmospheric formation of
secondary air pollutants, most notably tropospheric ozone and particulate matter. Burning
hydrogen in residential gas appliances and at natural gas power plants risks perpetuating
these emissions, including in Californiaʼs designated disadvantaged communities, because
natural gas plants are disproportionately located near these communities.
Safety. The production, transport, and use of hydrogen, like any combustible fuel, entail safety risks
for those working with hydrogen infrastructure or living nearby. These risks may be elevated for
certain applications. For example, blending hydrogen into natural gas pipelines oen requires
operating pipelines at higher pressures, and hydrogen-natural gas blends at these higher pressures
have been shown to leak from pipelines at higher rates than natural gas alone. Hydrogen also risks
embrittling pipelines, leading to an increased risk of failure in the long term. Mitigating such risks
would require dedicated monitoring and maintenance, including tailored interventions to protect
potentially vulnerable populations such as multilingual emergency communication plans reflecting
local community needs, all of which would likely require ongoing sources of funding.
7 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Costs. We did not analyze the full costs of hydrogen deployment in California, but we identified a
number of considerations as to how cost and risk should be incorporated into planning. These include:
● Stranded Assets. There is a risk of creating stranded assets if hydrogen infrastructure is built
but not used. This has already occurred for light-duty vehicle hydrogen fuel stations, which
outpaced demand and some of which have been taken offline.
● Uncertain Hydrogen Supply and Transport. Many plans do not have a well-defined supply of
hydrogen, leading to energy insecurity risks if production, transport, and storage infrastructure
are not built in line with demand. For example, LADWP aims to begin repowering gas plants
with hydrogen beginning with the Scattergood Generating Station in 2029, but the proposed
Angeles Link hydrogen pipeline to provide hydrogen to Los Angeles does not have an identified
production source, route, or permitting; there is also minimal if any existing hydrogen trucking
and storage infrastructure. These unknowns may lead to significant delivery and price
volatility risks, as well as a wide range of uncertainty about how infrastructure costs could
affect hydrogen supply costs and how these costs could be passed on to ratepayers.
● Opportunity Costs. Investment in hydrogen infrastructure, or in renewable energy supply to
produce hydrogen, should be compared to alternative decarbonization pathways. Many
proposed plans do not include a full quantification of hydrogen production, transport, and
delivery costs, so the relative costs of hydrogen pathways compared to other pathways to
meet decarbonization goals have not been fully explored.
Environment. A comprehensive accounting of the environmental impacts of hydrogen use would
require a full lifecycle analysis, including the potential impacts of the energy sources used to produce
hydrogen. A full lifecycle analysis of proposed hydrogen pathways is beyond the scope of this report;
however, we do highlight particularly salient considerations. For example, hydrogen produced from
dairy biogas may have associated environmental impacts due to dairy waste management, which can
affect air, water, and soil quality. Using biomass to produce hydrogen has a wide range of potential
impacts, from the benefits of using woody debris that might otherwise burn in wildfires to the public
health consequences associated with trucking biomass potentially long distances across the state to
hydrogen production sites. The siting of solar and wind to produce hydrogen also holds implications
for land use and biological diversity. Additionally, electrolytic hydrogen production requires splitting
water, which may face supply constraints in certain areas of California, particularly in more arid or
overdrawn regions. For example, the Angeles Link pipeline is considering siting hydrogen production
facilities in the Central Valley, the Mojave Desert, and near Blythe. The first has significant competing
water demands while the latter two are in the desert with limited water resources.
Feasibility. Many of the above considerations affect not only the societal costs and benefits, but also
the overall feasibility of using “green” hydrogen to meet decarbonization goals. For example, the
required rapid deployment of renewable energy resources and hydrogen infrastructure buildout to
meet the goals and targets in various plans for hydrogen in California may run into several barriers.
8 | Green Hydrogen Proposals Across California | PSE Healthy Energy
These include access to capital and finance, workforce training, supply chain scaling, and permitting.
Moreover, multiple competing demands for hydrogen might undermine the ability of any individual
organization or agency to achieve its hydrogen goals and associated climate targets. Additionally, a
lack of coordinated prioritization around the many needs for renewable electricity—including direct
use, hydrogen production, carbon capture and storage, and direct air capture—may lead to an
inefficient build-out of energy resources.
Before rapidly expanding hydrogen infrastructure, we recommend that planners and
decision-makers better characterize the impacts, both positive and negative, of hydrogen
deployment scenarios and alternatives. This assessment will require a more comprehensive
analysis of hydrogen production, transport, and use for proposed applications, including resolving the
many outstanding unknowns and uncertainties, and may require the development of contingency
plans should proposed deployments prove infeasible. We also make the following recommendations:
1. Develop stringent, consistent definitions for “green” or “clean” hydrogen to ensure that
hydrogen adoption provides verifiable additional climate benefits with minimal environmental
impacts.
2. Improve interagency coordination on hydrogen planning to ensure competing goals and
demands do not lead to system inefficiencies or undermine the Stateʼs ability to meet
decarbonization targets.
3. Better characterize hydrogen leakage rates and pipeline safety risks before committing to
hydrogen infrastructure expansion; ensure sufficient safety measures are built into hydrogen
deployment, including ongoing funding for monitoring and maintenance.
4. Address equity concerns throughout hydrogen planning processes, including ongoing
meaningful community engagement and incorporation of equity considerations when
addressing public health and safety concerns.
5. Consider the system-level and lifecycle impacts of hydrogen production and use—including
potential cost, public health, equity, environmental, and climate implications—within policy
planning.
6. Evaluate alternative technologies and deployment scenarios and each scenarioʼs sensitivity to
techno-economic assumptions.
7. Avoid hydrogen pipeline blending due to minimal potential climate benefit and possible safety
risks.
8. Fill outstanding research gaps to address unknowns. A primary example includes the need to
comprehensively model energy demand to better understand and optimize combined
renewable energy requirements in the power sector, for hydrogen production, and to power
the direct air capture of carbon dioxide.
9 | Green Hydrogen Proposals Across California | PSE Healthy Energy
While decision-makers are keen to push forward with hydrogen, setting strict standards for what
constitutes “clean,” addressing critical unknowns, and ensuring alignment across decarbonization
solutions and pathways will be critical to successfully achieving Californiaʼs climate goals.
10 | Green Hydrogen Proposals Across California | PSE Healthy Energy
1. Introduction
1.1 Goals of This Report
Local and state governments across California have set ambitious goals to mitigate greenhouse gas
emissions in the coming decades. These efforts range from city-level climate action plans to the Stateʼs
overarching 2045 target of reducing total greenhouse gas emissions by 85 percent from 1990 levels,
and offsetting the rest through carbon removal strategies to achieve statewide carbon neutrality.
1
With
targets set, officials are now determining how to achieve rapid emissions reductions. In different
planning arenas, one fuel has gained significant new traction in recent proposals: hydrogen.
The goal of this report is to investigate the opportunities, challenges, and risks associated with existing
proposals to scale hydrogen in California. To do this, we examine the role of hydrogen within several
proposed energy transition plans in California, including those from the California Air Resources Board
(CARB), from the Los Angeles Department of Water and Power (LADWP), and from the Alliance for
Renewable Clean Hydrogen Energy Systems (ARCHES) hydrogen hub. We then analyze the
implications of using hydrogen across a broad range of proposed applications, with a particular
emphasis on the energy inputs required to produce hydrogen and the climate, environmental, and
public health dimensions associated with its production and use. Based on this analysis, we identify
potential impacts, knowledge gaps, and key points of misalignment between existing plans, of which
there are many.
To identify these potential benefits, consequences, and uncertainties, we explored questions related
to the key steps for incorporating hydrogen into our energy system. We also asked questions about the
outputs of these process-related inquiries, focusing on the impacts both within and outside of the
energy system.
Key questions to fully characterize proposed hydrogen use include (Figure 1.1):
● How is hydrogen produced (e.g., from solar power or biofuels) and transported?
● What application will it be used for (e.g., in transportation, power plants, or industry)?
● Are there alternative non-hydrogen pathways to meet climate goals that may have lower
impacts or may be easier to achieve?
1
As directed in Assembly Bill 1279, the California Climate Crisis Act. (2022).
11 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Figure 1.1: Key Questions for Assessing Hydrogen Proposals. These questions focus on the process
of generating, transporting, and using hydrogen; the impacts of these various processes; and what
alternative pathways may be worth considering.
Key impact questions include:
● What are the potential environmental impacts of hydrogen production and use?
● What are the public health and safety risks? What equity concerns might arise?
● What are the climate benefits or concerns, including the climate impacts of hydrogen leakage?
2
● How quickly and how feasibly can hydrogen production scale up to meet the proposed level of
deployment and what would this cost?
3
● How do these challenges, impacts, or benefits compare to alternative pathways to achieve the
same climate goals, if such pathways exist?
In this report, we primarily focus on approaches that are under active consideration within the state of
California,
4
noting that exploring every possible pathway to produce and use hydrogen across
California is beyond our scope. We exclude a thorough analysis of so-called “gray hydrogen”
(produced directly from natural gas, and the primary means of production today across the globe) and
of “blue hydrogen” (gray hydrogen equipped with carbon capture and storage) because Californiaʼs
policies primarily focus on “green” or “clean” hydrogen produced from renewable or low-carbon
4
Nevertheless, the decisions made within the state also hold the potential to set a precedent and impact policies
and pathways adopted across the U.S.
3
We do not explore cost in detail in this report, but highlight it here as one key dimension for assessing hydrogen
plan feasibility.
2
Leakage of hydrogen into the atmosphere can cause indirect climate change impacts because it can affect
concentrations of other climate pollutants, such as methane, ozone, and water vapor.
12 | Green Hydrogen Proposals Across California | PSE Healthy Energy
energy (see Table 2.1 below). However, there are numerous proposed definitions of “green” and
“clean,” some of which may have much larger greenhouse gas impacts than their proponents claim
(see Section 5.2). These include approaches that propose using grid electricity (e.g., electricity
produced from gas plants) and “offsetting” the carbon footprint of that electricity with renewable
energy credits purchased from other sources. We also omit proposals such as the use of green
hydrogen to support oil and gas production, which is prohibited in most California initiatives.
We also strive to examine some of the systems-level considerations associated with hydrogen
deployment in order to better understand the effects of existing plans in aggregate and their
interaction with other decarbonization strategies. As part of this analysis, we identify competing
demands for renewable energy resources as a particularly important consideration. Because this
tension arises, for example, in CARBʼs heavy reliance on both green hydrogen and the direct air capture
(DAC) of carbon dioxide (CO
2
) to achieve 2045 greenhouse gas targets—both would require significant
energy inputs—we provide dedicated space in this report to address DAC and carbon capture and
sequestration (CCS). We examine how this systems-level analysis implies a very large total statewide
demand for renewable energy and an accelerated build rate—a challenge which likely requires
integrated planning, and would not be as apparent if each technology proposal were examined
individually.
Given that many of the current proposals do not detail full pathways to hydrogen production and use,
many aspects within our analysis remain uncertain. Throughout this report, we also highlight the
unknowns that still need to be addressed in order to better characterize the impacts of hydrogen
adoption in California.
1.2 Outline of This Report
This report aims to highlight a number of key issues related to hydrogen production and deployment
to achieve Californiaʼs climate goals. In Section 2 we provide a brief summary of some of the primary
proposals for hydrogen adoption across California, including those from CARB, LADWP, and ARCHES.
In Section 3, we evaluate the energy resource requirements needed to produce hydrogen from various
sources, including renewable electricity, biomass, and biogas, and calculate the energy efficiency of
each pathway. We compare this input energy demand to using renewable electricity to directly meet
end-use demand, including in the power sector, for transportation, and for heating. We also briefly
discuss considerations for different biofuel sources and water requirements for hydrogen production.
In Section 4, we examine the renewable electricity, biomass, and biogas deployment levels that would
be required to meet the level of 2045 hydrogen demand identified in the CARB Scoping Plan (2022a);
we also examine the combined system-level energy requirements to meet both hydrogen and direct
air capture energy requirements under the Scoping Plan. In Section 5, we discuss the climate
considerations associated with hydrogen production and use, including both the indirect atmospheric
impacts of hydrogen leaks as well as the climate considerations associated with the opportunity cost
13 | Green Hydrogen Proposals Across California | PSE Healthy Energy
of using renewable energy to produce hydrogen rather than directly displace fossil fuels. Section 6
examines public health and equity considerations, in particular related to emissions of nitrogen oxides
(NO
x
) associated with hydrogen combustion, including the risk of ongoing pollutant emissions in
state-defined “disadvantaged communities.” Section 7 provides a deep dive on LADWPʼs proposed
hydrogen repower of the Scattergood Generating Station, including the lack of existing green
hydrogen infrastructure. Finally, Section 8 outlines key policy considerations and trade-offs between
decarbonization pathways, and summarizes our findings, recommendations, and outstanding
uncertainties related to hydrogen deployment.
2. Overview of the Hydrogen Landscape in California
Proposals to use hydrogen to meet Californiaʼs climate goals have been advanced by both direct and
indirect policies and programmatic goals, as well as by various stakeholder groups throughout the
state. Direct funding, incentives, and initiatives include, but are not limited to 1) federal funding for
hydrogen hubs, 2) state-level incentives from the California Energy Commission (CEC) for hydrogen
pilot projects, and 3) plans by LADWP to repower its gas plants with hydrogen (U.S. Department of
Energy [DOE], n.d.-a; CEC, 2022; LADWP, 2022a). Indirect policies and programs include not only
overarching state goals, such as the 2045 climate targets outlined above, but also zero emission
vehicle programs, low carbon fuel standards for cars, and other technology-agnostic measures for
which hydrogen is being proposed. A partial list of these proposals is included in Table 2.1.
14 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Table 2.1. Partial List of Hydrogen Incentives, Programs, and Deployment Plans in California
11
California Energy Commission. (2024, March 11). 2023-2024 Investment Plan Update for the Clean Transportation Program. Docket No. 23-ALT-01, 57.
10
California Air Resources Board. Retrieved on March 1, 2024. LCFS Electricity and Hydrogen Provisions.
9
Projects with a minimum of 40 percent “renewable” hydrogen qualify for LCFS credits. “Renewable” includes hydrogen produced directly from natural gas
and “offset” through carbon capture of biomethane through “book and claim.” Source: California Energy Commission. (2024, March 11). 023-2024
Investment Plan Update for the Clean Transportation Program. Docket No. 28-ALT-01, 57.
8
California Energy Commission. (2022). Staff Workshop on the Implementation of the Clean Hydrogen Program.
7
ARCHES. (2023). California Awarded Up to $1.2 Billion to Advance Hydrogen Roadmap and Meet Climate and Clean Energy Goals.
6
CO
2
e = carbon dioxide equivalent
5
Federal Register (2023). Section 45v Credit For Production Of Clean Hydrogen; Section 48(A)(15) Election To Treat Clean Hydrogen Production Facilities As
Energy Property. Proposed Rule by the Internal Revenue Service.
15 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Examples of Hydrogen Incentives, Programs, and Plans in California
Region
Lead Agency
Name
Description
Status
(2024)
Hydrogen Greenhouse Gas or Energy Requirement
Programs
and
Incentives
Federal
Internal
Revenue
Service
45 V Tax Credit
5
Tax credit for clean
hydrogen (H
2
) production
Rule
proposed
in 2023
< 4 kg CO
2
e per kg H
2
(incentive increases as CO
2
e
declines)
6
Federal
U.S.
Department of
Energy
Clean Hydrogen
Hub Program
Up to $1.2 B awarded to CA
for the Alliance for
Renewable Clean Hydrogen
Energy Systems
7
Awarded
in 2023
< 4 kg CO
2
e per kg H
2
(incentive increases as CO
2
e
declines)
State
California
Energy
Commission
Clean Hydrogen
Program
$100 M in incentives for H
2
production and use
Allocated
by AB 209
in 2022
8
H
2
derived from Renewables Portfolio Standard-eligible
sources
State
California Air
Resources
Board
Low Carbon Fuel
Standard (LCFS)
Provides LCFS credits for
hydrogen used in various
transportation applications
Ongoing
Credits vary by application according to CARB
guidelines, including natural gas-produced hydrogen
offset with biomethane CCS
9,10
State
California
Energy
Clean
Transportation
Supports zero emission
vehicle infrastructure
Ongoing
33+ or 40+ percent renewable hydrogen, depending on
installation year;
11
currently follows LCFS
15
Los Angeles Department of Water and Power. (2022). 2022 Power Strategic Long-Term Resource Plan.
14
Will consider biogenic hydrogen in the next iteration.
13
California Energy Commission. (2023). 2023 Integrated Energy Policy Report.
12
California Air Resources Board. (2022). 2022 Scoping Plan Documents.
16 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Commission
Program
deployment, including H
2
fueling stations
Plans
State
California Air
Resources
Board
2022 Scoping
Plan for
Achieving
Carbon
Neutrality
12
Includes H
2
in portfolio to
meet stateʼs 2045 carbon
neutrality goals
Final;
updated
every five
years
Electrolytic H
2
from renewable energy and biogenic H
2
from biomass gasification with CCS and steam methane
reforming of biogas
State
California
Energy
Commission
2023 Integrated
Energy Policy
Report (IEPR)
13
Assesses use of hydrogen in
power and transportation
sectors
Dra; full
update
every two
years
Electrolytic hydrogen from renewable energy
14
Los
Angeles
Los Angeles
Department of
Water and
Power
Strategic Long
Term Resource
Plan (SLTRP)
15
Assumes five gas power
plants will be repowered to
burn H
2
by 2035
2022;
updated
every two
years
Likely alignment with federal tax incentive guidelines
In this report, we provide additional details on three of these hydrogen plans and initiatives below:
1. The California Air Resources Board Scoping Plan for Achieving Carbon Neutrality;
2. The federally-supported hydrogen hub Alliance for Renewable Clean Hydrogen Energy
Systems;
3. The Los Angeles Department of Water and Powerʼs Strategic Long-Term Resource Plan (SLTRP).
Notably, the proposals for hydrogen use by different agencies and regions frequently do not align. For
example, the Scoping Plan only relies on hydrogen use in power plants as an emergency backup to
ensure reliability in 2045, whereas ARCHES considers power plants to be a primary application for
hydrogen; and LADWP aims to begin repowering its gas plants to run on hydrogen in 2029. Moreover,
there is a lack of alignment between these plans and initiatives regarding what should be considered
“clean” or “green” hydrogen (as evidenced in Table 2.1), including how various biofuels are
incorporated and whether renewable energy generation should be co-located with hydrogen
production. These different definitions are addressed further in Section 5.2.
CARB 2022 Scoping Plan for Achieving Carbon Neutrality. Under Californiaʼs Global Warming
Solutions Act (AB 32, 2006), CARB is required to release a Scoping Plan every five years outlining a plan
for the state to achieve its economy-wide greenhouse gas targets (CARB, 2022b). CARBʼs 2022 Scoping
Plan Scenario includes a 1,700-fold increase in renewable hydrogen production by 2045, totaling 0.23
exajoules (EJ).
16
This amount is equivalent to about nine percent of the Scoping Planʼs projected total
2045 energy demand,
17
excluding the energy required to power direct air capture or to produce the
hydrogen itself, which are not included in CARBʼs energy demand projections. According to the
Scoping Plan, 87 percent of this hydrogen is allocated to the transportation sector, eight percent to
industry, and the remainder to the commercial and residential sectors as well as for oil and gas
production and refining, as detailed in Section 4.1. CARB assumes that 9.3 gigawatts (GW) of
hydrogen-burning combustion turbine power plants will be built by 2045, but no actual hydrogen fuel
is allocated to the power sector as these plants are only intended to be available for reliability (CARB,
2022c).
18
However, the Scoping Plan does include hydrogen blended into existing gas pipelines serving
buildings and industry. The hydrogen itself is produced using multiple energy sources: renewable
electricity resources such as wind and solar (the electricity is used to split water and produce hydrogen
via electrolysis); biogas (via steam methane reforming); and biomass (via gasification). The energy
18
The Scoping Plan documentation includes the build-out of hydrogen-burning power plants, but no fuel is
allocated to the power sector. Private communication with CARB staff indicated that these plants are not used in
modeled everyday power generation, but only added to provide reliability in the case of an emergency. However,
it is unlikely that in practice these plants would be built and yet burn no fuel; at a minimum, they would burn
hydrogen when an emergency situation does inevitably arise. It is unclear what the relative cost of these plants is
compared to alternative approaches to meet emergency peak demand, including demand response.
17
The Scoping Plan projects that Californiaʼs total economy-wide energy demand in 2045 will actually be about
half of todayʼs due to energy efficiency savings, including through electrification.
16
0.23 exajoules of hydrogen is equivalent to ~1.9 million metric tons (MMT) of hydrogen.
17 | Green Hydrogen Proposals Across California | PSE Healthy Energy
inputs required to produce hydrogen via each of these methods are detailed in Section 3.1. The
Scoping Plan also aims for the State to achieve carbon neutrality in part through the direct air capture
of CO
2
, which itself requires a significant energy input. In Section 4 we examine how much energy is
required to both produce hydrogen and power direct air capture as outlined in the Scoping Plan, as
well as what this combined resource build implies for the required deployment rates of renewable
resources such as wind and solar. We also look at additional sensitivity to a 2045 scenario developed
by the California Energy Commission in its 2023 Integrated Energy Policy Report (IEPR) in which
hydrogen is burned at power plants in lieu of the natural gas currently used in the Scoping Plan.
Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES). ARCHES is a public-private
partnership that was allocated up to $1.2 billion in 2023 by the U.S. Department of Energy to serve as a
hydrogen hub under the Clean Hydrogen Hub Program. The program is funded by the 2021 Bipartisan
Infrastructure Law to coordinate regional support for clean hydrogen development (DOE, n.d.-a).
ARCHES is initially focusing on projects using hydrogen in medium- and heavy-duty transportation,
ports, and power plants, which in the latter case could include both fuel cells and hydrogen
combustion (ARCHES, n.d.). Unlike the CARB Scoping Plan, ARCHES is not pursuing the blending of
hydrogen in gas pipelines. ARCHES aims to use hydrogen produced from renewable energy and
biomass resources, although it explicitly excludes dairy biogas and fossil-generated hydrogen offset
with biomethane credits (unlike the low carbon fuel standard (LCFS), as discussed in Table 2.1 and
Section 5.2) (DOE, n.d.-a). However, ARCHES has written to the Internal Revenue Service that it
believes clean hydrogen incentives 1) should not have explicit requirements to ensure that the
renewable energy powering hydrogen production is additional compared to existing renewable
resources, 2) nor should the renewable power be required to be located in the same region as the
hydrogen production, 3) nor should hydrogen producers be required to have hourly matching of its
energy use with actual hourly renewable energy production (see Section 5.2) (Galiteva et al., 2023).
University of California faculty have expressed concern that non-adherence to such requirements
might actually increase greenhouse gas emissions in California (UC Berkeley Faculty, 2023).
LADWP Strategic Long-Term Resource Plan. LADWP undertakes a periodic planning exercise, the
SLTRP, to ensure that there is sufficient capacity on its grid to meet the demand for energy and power
across Los Angeles while simultaneously meeting climate and clean energy goals. The mayorʼs office
and city council in Los Angeles have set goals to achieve 100 percent carbon-free electricity by 2035
(LADWP, 2021, 2022b). Simultaneously, three of LADWPʼs four in-basin gas-fired power plants are
required by the state to retire because they rely on once-through cooling using ocean water, which can
harm marine life (California State Water Resources Control Board [State Water Board], 2023a). In light
of these goals, and taking into account modeling done under the LA100 Study conducted by the
National Renewable Energy Laboratory (NREL), the 2022 SLTRP proposes burning hydrogen at new
units at all four of LADWPʼs in-basin gas plants by 2035 (NREL, 2021). It also relies on burning hydrogen
at Utahʼs Intermountain Power Project, from which LADWP imports power. LADWP plans to first build
and deploy new hydrogen-burning combustion turbine units at the Scattergood Generating Station in
18 | Green Hydrogen Proposals Across California | PSE Healthy Energy
2029 (see Section 7), followed by units at the Harbor, Haynes, and Valley Generating Stations. These
are planned to total 2.1 GW
19
by 2035 (notably, this is more than half of the 4.06 GW of hydrogen
combustion turbines that CARB expects to have available statewide in 2035, and none of CARBʼs
proposed plants are expected to be used except as backup). The SLTRP does not specify how the
hydrogen will be produced, although it does suggest that all of it will have to comply with federal clean
hydrogen tax incentive requirements for carbon dioxide equivalent (CO
2
e) emissions (see Table 2.1). It
also does not specify where the hydrogen will be produced. In parallel, Southern California Gas Co.
(SoCalGas) is proposing to build the Angeles Link pipeline to deliver hydrogen produced from
renewable energy to Los Angeles from outside the LA Basin, but it also does not specify the energy
resources nor the specific location where the hydrogen would be produced (SoCalGas, 2022a).
SoCalGas estimates that hydrogen demand in its territory, which Angeles Link would supply, would
reach 1.9–6 million tons per year of hydrogen in 2045 (SoCalGas, 2024). This is equivalent to 0.27–0.86
EJ and more than the Scoping Plan projects for the entire state.
These three plans are just some of those being pursued in California, but illustrate the array of
hydrogen applications, production sources, and rates of deployment under consideration in different
jurisdictions.
3. Background on Proposed Hydrogen Production and Use
The global hydrogen supply today is primarily produced from fossil fuels.
20
In the United States, 95
percent of hydrogen is produced via steam methane reforming (SMR) of natural gas (Hydrogen and
Fuel Cell Technologies Office, n.d.). However, because fossil fuel-derived hydrogen is associated with
significant greenhouse gas emissions, proposals to expand hydrogen use in California primarily
consider “green” hydrogen options. These proposals include hydrogen produced from water using
renewable electricity (via a process called electrolysis, which splits water into hydrogen and oxygen)
and hydrogen derived from biofuels, such as biomethane from dairy farms (via steam methane
reforming) and wood waste from forest management activities (via biomass gasification).
Since hydrogen is generated from other energy sources, producing and using it results in energy losses
associated with inefficiencies in every energy conversion process. The overall efficiency of substituting
hydrogen into existing systems depends on the technologies used to produce and compress it, how it
is stored and transported, any potential leakage throughout the hydrogen system, and its final
application.
20
There is a growing interest in the possibility of mining naturally-occuring hydrogen from underground geologic
formations, but this source is novel and there remain many unanswered questions about its potential. For more
on the potential lifecycle greenhouse gas impacts of mining hydrogen, including sensitivity to the methane
fraction in the fuel source, see Brandt (2023).
19
This is lower than todayʼs in-basin gas plant capacity.
19 | Green Hydrogen Proposals Across California | PSE Healthy Energy
In the following sections, we first review the efficiency of various hydrogen production, storage, and
transport pathways. Next, we evaluate the efficiency of various applications for hydrogen, such as
burning hydrogen at power plants to produce electricity. We then apply these efficiencies to the
Scoping Plan in Section 4 to better understand how much California would have to expand its
renewable energy capacity (or, in some scenarios, biomass usage) in order to have enough energy to
meet the Scoping Planʼs hydrogen goals.
3.1 Energy Efficiency of Proposed Hydrogen Production, Storage, and
Transport Methods
California stakeholders are considering three main methods for producing “green” hydrogen:
electrolysis, biomass gasification with carbon capture and storage, and steam methane reforming of
biogas. Each method requires different energy inputs, has different process efficiencies, and incurs
different environmental and climate hazards, risks, and impacts. We discuss climate impacts and
additional environmental and human health considerations in Section 5 and Section 6, respectively.
20 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Hydrogen transport and storage methods also influence the total efficiency of using hydrogen. Some
of the most critical factors are whether the hydrogen is stored as a gas or liquid and, if required, how
the hydrogen is transported to its final end use. Efficiency ranges for different steps in the hydrogen
production process are outlined in Table 3.1.
21 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Table 3.1. Efficiencies of Hydrogen Production and Delivery Process Steps. Given the limited deployment and rapidly changing
technological maturity of these technologies, many of the estimates below are uncertain or based on modeling results rather than in-situ
measurements. Additionally, the efficiency of transporting hydrogen fuel sources (e.g., water and biofuels) before hydrogen generation is not
included in this table. These factors will have an impact on the overall efficiency of using hydrogen. Additionally, not all methods for
producing, compressing, storing, and transporting hydrogen are included in the table.
Efficiencies of Hydrogen Production and Delivery Process Steps
Process Step
Efficiency
Range
21
Description
Source
Production
Alkaline
electrolysis
60–80%
A widely commercialized, well-known technology. Least expensive of existing electrolysis
options. Operates between 20–80°C and outputs hydrogen at 3–200 bar.
22, 23, 24, 25, 26,
27, 28
Proton
exchange
membrane
(PEM)
electrolysis
60–85%
A newer electrolysis technology. More flexible than alkaline electrolyzers but higher cost,
in part because electrolyzer membranes use noble metals. Operates at 20-200°C and
outputs hydrogen at 10–200 bar.
Solid oxide
electrolysis
74–97%
Still in the research and testing phase. High efficiency, high temperature electrolysis that
operates at 500–1,000°C and outputs hydrogen at 10–60 bar.
28
International Energy Agency. (2023). ETP Clean Energy Technology Guide.
27
DeSantis, D., James, B., & Saur, G. (2019). Current (2015) Hydrogen Production from Distributed Grid PEM Electrolysis. National Renewable Energy
Laboratory.
26
International Energy Agency. (2019). The Future of Hydrogen.
25
Deloitte. (2023). Green Hydrogen: Energizing the Path to Net Zero. Figure 26 Hydrogen production technology cost data.
24
Pashchenko, D. (2024). Green Hydrogen as a power plant fuel: What is energy efficiency from production to utilization? Renewable Energy, 223, 120033.
23
Alptekin, F.M., & Celiktas, M.S. (2022). Review on Catalytic Biomass Gasification for Hydrogen Production as a Sustainable Energy Form and Social,
Technological, Economic, Environmental, and Political Analysis of Catalysts. American Chemical Society, 7(29), 24918-24941.
22
Amores et al. (2021). Renewable hydrogen production by water electrolysis. Sustainable Fuel Technologies Handbook.
21
Efficiency ranges are reported in lower heating value (LHV).
22 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Gasification
(of biomass)
30–60%
Total process efficiencies depend on the type of biomass, its moisture content, the
gasification agent, whether heat is supplied externally or by combusting some of the
existing biomass, the gasification reactor design, the gas cleaning methods, and the
required hydrogen purity levels. Gasification also uses some natural gas and electricity.
Efficiency reported here does not include carbon capture and storage (CCS).
29, 30, 31, 32
Steam methane
reforming
(of biomethane)
74–85%
Reported efficiency does not include upgrading biofuels to the higher purity biomethane
that is used to generate hydrogen. Including biogas upgrading drops the efficiency to
64–74 percent, as this process is estimated to be roughly 87 percent efficient. The
efficiency of upgrading other biofuels (e.g., animal waste, wastewater sludge, etc.) to
biomethane depends on the specific fuel.
33, 34, 35
Compression
& Storage
Compression
(gaseous H
2
stored in
pressurized
80–97%
Energy requirements and process efficiency depend on starting pressure and desired
storage pressure (larger increases in pressure require more energy). Energy required for
compression is not linear with increasing pressures; for pressures greater than 700 bar,
energy required increases exponentially. Many sources indicate a 90–97 percent efficiency
36, 37, 38, 39, 40, 41,
42
42
Tarhan, C., & Cil, M. A. (2021). A study on hydrogen, the clean energy of the future: Hydrogen storage methods. Journal of Energy Storage, 40, 102676.
41
Noh et al. (2023). Environmental and energy efficiency assessments of offshore hydrogen supply chains utilizing compressed gaseous hydrogen, liquefied
hydrogen, liquid organic hydrogen carriers and ammonia. International Journal of Hydrogen Energy, 48(20), 7515-7532.
40
Kayfeci, M., & Kecebas, A. (2019). Chapter 4 - Hydrogen storage. Solar Hydrogen Production Processes, Systems and Technologies, 85-110.
39
Ghorbani et al. (2023). Hydrogen storage in North America: Status, prospects, and challenges. Journal of Environmental Chemical Engineering, 11(3),
109957.
38
Pashchenko, D. (2024). Green hydrogen as a power plant fuel: What is energy efficiency from production to utilization? Renewable Energy, 223, 120033.
37
Wang et al. (2022). Greenhouse gases, Regulated Emissions, and Energy use in Technologies Model Ⓡ (2022 Excel). Argonne National Laboratory.
36
Elgowainy et al. (2022). Hydrogen Life-Cycle Analysis in Support of Clean Hydrogen Production. Argonne National Laboratory.
35
Saur, G., & Milbrandt, A. (2014). Renewable Hydrogen Potential from Biogas in the United States. National Renewable Energy Laboratory.
34
Wang et al. (2022). Greenhouse gases, Regulated Emissions, and Energy use in Technologies Model Ⓡ (2022 Excel). Argonne National Laboratory.
33
Ibid.
32
Zhou et al. (2021). Life-Cycle Greenhouse Gas Emissions of Biomethane and Hydrogen Pathways in the European Union. International Council on Clean
Transportation.
31
Mann, M., & Steward, D. M. (2018). Current Central Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. National Renewable Energy
Laboratory.
30
Elgowainy et al. (2022). Hydrogen Life-Cycle Analysis in Support of Clean Hydrogen Production. Argonne National Laboratory.
29
Alptekin, F.M., & Celiktas, M.S. (2022). Review on Catalytic Biomass Gasification for Hydrogen Production as a Sustainable Energy Form and Social,
Technological, Economic, Environmental, and Political Analysis of Catalysts. American Chemical Society Omega, 7(29), 24918-24941.
23 | Green Hydrogen Proposals Across California | PSE Healthy Energy
cylinders)
range for compression up to 880 bar, though Kayfeci & Kecebas (2019) suggest that up to
20 percent of hydrogen's energy content may have to be used for compression at fuel
stations.
Liquefaction
(liquid H
2
stored
in low-
temperature
storage tanks)
60–72%
Energy intensive and incurs boil-off losses. Liquefaction efficiency depends on process
scale, with smaller operations showing lower efficiencies. Liquid hydrogen also suffers
boil-off losses of 0.1–4 percent per day, with higher losses from smaller tanks. The
efficiency of storing liquid hydrogen depends on the storage vessel size, insulation,
pressure, and cooling as well as the length of storage time. Cryo-compressed storage,
which uses cryogenic temperatures and high pressure, can also decrease boil-off losses.
43, 44, 45, 46, 47, 48,
49, 50
Geological
storage
(low-pressure,
gaseous H
2
78–92%*
Hydrogen can be stored in salt caverns, depleted oil and gas wells, aquifers, caverns, and
similar underground sites. The efficiency of geological storage is influenced by the
physical and chemical characteristics of the storage medium, with different operational
requirements dictating the required amount of compression, recovery ratios, amounts of
51, 52, 53 , 54, 55
55
Langmi et al. (2022). Chapter 13 - Hydrogen storage. Hydrogen Production by Water Electrolysis. Electrochemical Power Sources: Fundamentals, Systems,
and Applications, 455-486.
54
Zivar, D., Kumar, S., & Foroozesh, J. (2021). Underground hydrogen storage: A comprehensive review. International Journal of Hydrogen Energy, 46(45),
23436-23462.
53
International Energy Agency. (2019). The Future of Hydrogen.
52
Kayfeci, M., & Kecebas, A. (2019). Chapter 4 - Hydrogen storage. Solar Hydrogen Production Processes, Systems and Technologies, 85-110.
51
Okoroafor et al. (2022). Assessing the underground hydrogen storage potential of depleted gas fields in northern California. In SPE Annual Technical
Conference and Exhibition, D031S057R006.
50
Tarhan, C., & Cil, M. A. (2021). A study on hydrogen, the clean energy of the future: Hydrogen storage methods. Journal of Energy Storage, 40, 102676.
49
Noh et al. (2023). Environmental and energy efficiency assessments of offshore hydrogen supply chains utilizing compressed gaseous hydrogen, liquefied
hydrogen, liquid organic hydrogen carriers and ammonia. International Journal of Hydrogen Energy, 48(20), 7515-7532.
48
Morales-Ospino et al. (2023). Strategies to recover and minimize boil-off losses during liquid hydrogen storage. Renewable and Sustainable Energy
Reviews, 182, 113360.
47
Barthelemy et al. (2017). Hydrogen storage: Recent improvements and industrial perspectives. International Journal of Hydrogen Energy, 42(11),
7254-7262.
46
Kayfeci, M. & Kecebas, A. (2019). Chapter 4 - Hydrogen storage. Solar Hydrogen Production Processes, Systems and Technologies, 85-110.
45
Ghorbani et al. (2023). Hydrogen storage in North America: Status, prospects, and challenges. Journal of Environmental Chemical Engineering, 11(3),
109957.
44
Pashchenko, D. (2024). Green hydrogen as a power plant fuel: What is energy efficiency from production to utilization? Renewable Energy, 223, 120033.
43
Kurz et al. (2022). Chapter 6: Transport and Storage. Machinery and Energy Systems for the Hydrogen Economy, 218.
24 | Green Hydrogen Proposals Across California | PSE Healthy Energy
stored in
depleted gas
fields)
gas loss or leakage, and potential repurification requirements.
*Each method has different operational and efficiency considerations, and storage
efficiencies are an active area of research. (Further detail in Section 3.1.2.1.)
Transport
(200 miles)
Pipelines
96–99%
Transporting hydrogen through pipelines requires energy for compression. Kurz et al.
(2022) suggests the energy required is roughly 0.5 percent of hydrogen's higher heating
value
56
(HHV) for every 100 miles, which equates to roughly 1.18 percent of hydrogen's
lower heating value to travel 200 miles. Pipeline transport efficiency ultimately depends
on pipeline pressure, pipeline distance, and, in the case of blended fuels, the percentage
of hydrogen to natural gas. (Blends require more energy for compression along the
pipeline than natural gas alone. Further detail in Section 3.1.2.2.) Typical hydrogen
pipelines operate at 500–1,200 psi (35–83 bar), though high-pressure systems (up to
15,000 psi/1,034 bar) have been proposed, while natural gas pipelines typically operate at
200–1,500 psi (14–103 bar).
57, 58
Trucks
(compressed
gas in tube
trailers)
82–96%
Efficiency of transporting hydrogen by truck is driven by the amount of hydrogen a trailer
can carry, the weight of said trailer, and the distance traveled. The level of compression
used for transporting gaseous hydrogen varies. While DOT typically limits tube trailers to
250 bars, pressures above 500 bars can be used with special exemptions. DOE also
reports a common hydrogen carrying capacity of 380 kg for steel tube trailers and
560–900 kg for storage containers made with modern composite materials. Oak Ridge
National Laboratory illustrated that a truck's fuel efficiency decreases as weight
increases, and for heavy loads, converges around 3.5 MPG regardless of speed. The
efficiency range here is for the 200 mile, one-way transport of a 380–900 kg hydrogen
trailer by a low-sulfur diesel truck with a 3.5–7.2 MPG efficiency range, and considers the
energy required by the truck as a fraction of the energy in the hydrogen it is transporting.
59, 60, 61
61
Franzese, O. (2011). Effect of Weight and Roadway Grade on the Fuel Economy of Class-8 Freight Trucks. Oak Ridge National Laboratory.
60
Kurz et al. (2022). Chapter 6: Transport and Storage. Machinery and Energy Systems for the Hydrogen Economy, 218.
59
U.S. Department of Energy. (n.d.). Retrieved on April 9, 2024. Hydrogen Tube Trailers.
58
Penev, M., Zuboy, J., & Hunter, C. (2019) Economic analysis of a high-pressure urban pipeline concept (HyLine) for delivering hydrogen to retail fueling
stations. Transportation Research Part D: Transport and Environment, 77, 92-105.
57
Kurz et al. (2022). Chapter 6: Transport and Storage. Machinery and Energy Systems for the Hydrogen Economy, 218.
56
The heating value is the amount of energy contained within a combustible fuel. Higher heating values refer to the gross energy/caloric value, including the
latent heat from vaporizing water during combustion, while the lower heating value is the net energy/caloric value, assuming that the latent heat is not
recovered. For more precise definitions, please see the Pacific Northwest National Laboratoryʼs H2 Tools ʻLower and Higher Heating Values of Fuelsʼ.
25 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Trucks
(liquid H
2
)
88–99%
Liquid hydrogen can suffer boil-off losses between 0.1 and 4 percent per day. Losses of up
to five percent can also occur when transferring liquid hydrogen between storage
containers (e.g., during the final stage of transport and delivery), with potentially even
higher losses if transferring from high to low pressure. However, Petitpas suggests that
these losses can be almost entirely mitigated by using certain fill methods and recovery
solutions. Efficiency of this transport method also depends on the size of the tanker used,
with liquid H
2
tanks of 2,100–5,000 kg reported in the literature. The efficiency range here
is for the 200-mile, one-way transport of a 2,100–5,000 kg hydrogen tanker by a diesel
truck with a 3.5–7.2 MPG efficiency range, and considers a single dayʼs boil of losses and
the energy required by the truck as a fraction of the energy in the hydrogen it is
transporting.
62, 63, 64
Leakage
80–100%
Estimates of leakage rates at different points in the hydrogen production, storage,
transport, and end use process vary, ranging from 0.2–20 percent for the full value chain.
The highest leakage rates are associated with liquid hydrogen. Leakage associated with
electrolysis, compression, and gas transport oen range from 3–6 percent as outlined by
Fan et al. (2022) and Arrigoni & Bravo Diaz (2022), though higher values have also been
suggested.
65, 66, 67
67
Arrigoni, A., & Bravo Diaz, L. (2022). Hydrogen emissions from a hydrogen economy and their potential global warming impact. Publications Office of the
European Union, EUR 31188 EN, JRC130362.
66
Fan et al. (2022). Hydrogen Leakage: A Potential Risk for the Hydrogen Economy. Center on Global Energy Policy, Columbia SIPA.
65
Esquivel-Elizondo et al. (2023). Wide range in estimates of hydrogen emissions from infrastructure. Frontiers in Energy Research, 11, 1207208.
64
Kurz et al. (2022). Chapter 6: Transport and Storage. Machinery and Energy Systems for the Hydrogen Economy, 218.
63
Jallais, S., & Bernard, L. (2018). Pre-normative REsearch for Safe use of Liquid Hydrogen: LH
2
Installation Description.
62
Aziz et al. (2021). Liquid Hydrogen: A Review on Liquefaction, Storage, Transportation, and Safety. Energies, 14(18), 5917.
26 | Green Hydrogen Proposals Across California | PSE Healthy Energy
3.1.1 Conversion Efficiencies for Hydrogen Production Pathways
For each hydrogen production pathway, the total process efficiency will depend on the specific
generation technologies and their fuel sources, the pressures chosen for compression, the methods
used for storage and transport, and how far the hydrogen must travel to reach its end use. Efficiencies
and related considerations for electrolysis, biomass gasification, and steam methane reforming of
biogas—the three processes used to produce hydrogen in the Scoping Plan—are discussed below. We
also discuss the possible effects on efficiency of using intermittent renewable electricity to power
electrolysis.
3.1.1.1. Electrolysis
Electrolysis is one of the primary proposed methods of producing hydrogen in the Scoping Plan and
other proposals across the state. In the near term, electrolysis pathways will use alkaline or proton
exchange membrane (PEM) electrolyzers to generate hydrogen. Then, unless and until hydrogen
pipeline infrastructure is established in California, it is likely that hydrogen will be trucked to where it
is needed. Pressurized cylinders are a simple, commonly used way to store and transport hydrogen
and are useful for small-to-medium-scale storage. However, the low energy density of gaseous
hydrogen poses an efficiency challenge—with trade-offs required between the amount of compression
(higher compression requires significantly more energy) and the efficiency of transport (the lower the
compression, the lower the energy density, and the more energy required for transport). If hydrogen
does not need to travel far to reach its designated end use, it is likely most efficient for it to be stored
and transported as compressed gas. However, if large volumes of hydrogen need to be moved, it may
become more efficient to transport it as liquid hydrogen, despite the energy intensity of the
liquefaction process.
As shown in Figure 3.1, end-to-end hydrogen production and delivery process efficiency will likely
improve over time with the build-out of dedicated transport infrastructure including pipelines. These
improvements are likely to be modest unless there are additional efficiency improvements in specific
technologies, including electrolysis. Some efficiency estimates suggest that the longer-term scenario
gains in efficiency due to pipeline transport may be offset by losses in efficiency associated with the
need for underground storage. There is significant uncertainty surrounding this comparison, however,
because estimated underground storage efficiencies are still an active area of research. Additionally,
there is very little in-situ data from hydrogen storage in depleted gas fields, which are among the most
likely candidates for bulk hydrogen storage in California. Further confounding factors include the
transport distance and volume of hydrogen required, both of which affect the efficiency of hydrogen
transport and storage. The relative cost of various technologies may also preclude some
higher-efficiency options. Finally, end-use efficiency varies depending on the application, which
influences whether storage is required as well as the required amount of compression.
27 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Figure 3.1: Efficiency of Hydrogen Produced via Electrolysis. Chart a) shows possible efficiencies
achievable in a near-term scenario given a limited buildout of transport and storage infrastructure.
Transport and storage efficiencies are unlikely to simultaneously reach the highest ends of their
respective ranges, as higher transport efficiencies correspond with lower storage efficiencies, and vice
versa, due to the energy required for compression. Chart b) shows updated efficiencies assuming a
more extensive infrastructure build out, which includes the potential for underground storage and
hydrogen transport via dedicated pipelines. Achieving efficiencies in this range would require
significant amounts of dedicated hydrogen infrastructure. Long-term efficiencies may also increase
with electrolyzer technology improvements. (See Section 3.1.1.2 for more on this.) Storage in b)
reaches 100 percent efficiency to reflect that some use cases for hydrogen may not require it. Storage
in a) and transport in b) include the energy required for compression at hydrogen refueling stations, as
the Scoping Plan primarily uses hydrogen for transportation applications. (See Section 4.1.)
28 | Green Hydrogen Proposals Across California | PSE Healthy Energy
The final efficiency ranges in Figure 3.1 are largely due to uncertainties inherent in each process step
and how efficiencies from each step may chain together for a specific use case. For example,
generating hydrogen and transporting it via a pipeline for immediate use is more efficient than storing
the hydrogen underground before transport. As hydrogen leakage rates are not well characterized,
hydrogen lost to leakage may also be outside of the listed range, depending on production, storage,
and transport methods (See Section 5.2 for more on this.). In the future, the adoption of solid oxide
electrolyzers (which are not yet commercialized) or other future electrolyzer technologies may
increase overall efficiencies. Efficiency improvements may be particularly notable for the longer-term
scenario. However, the improvements will ultimately depend on how quickly electrolyzers are built in
California, when and whether projected future efficiencies are achieved, the cost of more efficient
technologies when compared to the cost of hydrogen, and other related factors. The electrolyzer
efficiencies above also do not reflect hydrogen generated using intermittent renewable energy (as
outlined in the Scoping Plan). We discuss potential impacts of renewable energy operations below.
3.1.1.2 Electrolyzer Operations Using Intermittent Renewable Energy
Solar and wind are intermittent and oen do not provide constant, steady state power. However,
electrolyzers require a baseline level of power in order to maintain the internal pressure and
temperature needed to operate safely—known as a minimum load requirement. For example, when a
PEM electrolyzer starts up aer a long idle period, such as overnight when there is no sun, this
minimum load requirement may be set as high as 34 percent of nominal power to ensure the startup
process is not interrupted before the electrolyzer reaches its minimum operating pressure (Lopez et
al., 2023). However, when the electrolyzer is already operating, the minimum load requirement is
much lower—as low as 7.6 percent for a PEM electrolyzer (Lopez et al., 2023). Thus, there can be
efficiency penalties for repeated cold start-ups, which could happen on a daily basis if electrolyzers are
powered by intermittent solar or wind energy.
Electrolyzers can also face performance and equipment concerns from the intermittent operations and
fluctuating currents characteristic of renewable energy (Table 3.2). Turning an electrolyzer on and off
to follow intermittent power generation can, in some cases, cause equipment to degrade faster than it
would with a steady source of power. Changes in weather conditions can also cause the incoming
electric current to fluctuate. For example, the current fluctuates as a solar panel receives different
amounts of sunlight based on the time of day and changes in cloud cover. This can change the voltage,
temperature, gas pressure, and gas purity within an electrolyzer, as well as cause some electrolyzer
technologies to wear out (e.g., degrade) more quickly (Kojima et al., 2023). Pairing solar and wind,
aggregating renewable energy from a wide geographic area, and pairing renewables with storage can
all help smooth out current fluctuations and increase the operating time of a plant (Kojima et al.,
2023). However, this may be difficult to accomplish for facilities using dedicated, off-grid solar power
systems, as proposed in the Scoping Plan. Producing hydrogen from renewable electricity that would
29 | Green Hydrogen Proposals Across California | PSE Healthy Energy
otherwise be curtailed may be an effective way to reduce input energy costs, but it may lead to higher
electrolyzer inefficiencies.
Table 3.2. Electrolyzer Operations Using Intermittent Renewable Energy. Different electrolyzer
technologies have different potential performance concerns when using intermittent renewables.
Electrolyzer Operations Using Intermittent Renewable Energy
Performance Given Fluctuating
Currents
68
Performance Given Intermittent
(On/Off) Operations
Can safely follow power fluctuations if a
protection current is used to prevent
on/off operations
Degradation of catalysts due to reverse
current during on/off operations
Alkaline Water
Electrolysis
Proton Exchange
Membrane (PEM)
Some performance degradation
Degradation only when quickly switching
between on/off (e.g., every 10 minutes)
Solid Oxide
Electrolyzer
Possible degradation depends on operating temperature and heat management
All electrolyzer cells degrade and become less efficient over time. This degradation can be accelerated
by certain characteristics inherent to operating with renewable energy, as described above. The extent
to which renewable-based operations will impact fuel cells also depends on attributes specific to each
technology. Based on current research, PEM cells face the least damage from intermittent operations.
Alkaline electrolysis cells can also maintain performance when power levels fluctuate, provided
intermittency is minimized. Solid oxide electrolyzer cells, which are still under development, currently
degrade quickly during all operations (Skae et al., 2022). Further research is needed to develop
cost-effective solutions to cell degradation and performance issues faced by all three technologies
when operating under renewable-energy-focused conditions.
68
Kojima et al. (2023). Influence of Renewable Energy Power Fluctuations on Water Electrolysis for Green
Hydrogen Production. International Journal of Hydrogen Energy. Volume 48, Issue 12.
30 | Green Hydrogen Proposals Across California | PSE Healthy Energy
3.1.1.3. Biomass Gasification
The production of hydrogen via biomass gasification is another approach being proposed for
hydrogen production, including in the Scoping Plan. The efficiency of this process is determined, in
part, by the gasification agent and the moisture content of each feedstock (Shayan et al., 2018).
Though not included here, the addition of carbon capture and storage (which is proposed in the
Scoping Plan) can also affect process efficiencies.
Efficiency ranges for biomass gasification vary widely in the literature, as seen in Table 3.1 and Figure
3.2. This is likely due to the fact that while gasification itself is a mature technology, biomass
gasification to produce hydrogen is not yet widely deployed (Zhou et al., 2021).
31 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Figure 3.2: Efficiency of Hydrogen Produced via Biomass Gasification. Efficiency ranges include
both a limited and more extensive infrastructure build-out. The highest end of the final efficiency
range assumes no storage and dedicated hydrogen pipelines. When stored in compressed gas
cylinders and trucked to final use-site, storage and transport efficiencies are unlikely to reach the
highest end of the above range.
Figure 3.2 shows the efficiency of producing hydrogen via biomass gasification; however, it does not
include the energy required to transport biomass to hydrogen generation facilities. The source of each
feedstock, and thus the transportation requirements to deliver feedstock to a gasification facility, will
also impact the overall efficiency and emissions from its use. Each of the biomass feedstocks outlined
in the Scoping Plan presents distinct challenges and may require different policy incentives to ensure
that enough feedstock is available for hydrogen production without unintended emissions or equity
consequences. (See Section 4.2.2.1 and Section 6.2.1 for more.)
3.1.1.4. Steam Methane Reforming of Biomethane
Until 2040, the Scoping Plan includes hydrogen generated via steam methane reforming of biogas. The
Plan indicates that this hydrogen is imported from out of state,
69
though it is somewhat unclear
69
It is somewhat unclear whether the biomethane used or the hydrogen itself is imported.
32 | Green Hydrogen Proposals Across California | PSE Healthy Energy
whether the biomethane used or the hydrogen itself is imported. Figure 3.3 outlines hydrogen
production efficiencies assuming the hydrogen is produced in California.
Figure 3.3: Efficiency of Hydrogen Produced via Steam Methane Reforming of Biogas. If hydrogen
is trucked to its final use site, storage and transport efficiencies are unlikely to reach the highest end of
their respective ranges. Efficiencies do not include transport of biogas to the hydrogen generation
facility nor any carbon capture and storage included in the process.
As steam methane reforming of biogas is phased out of the Scoping Plan by 2040, Figure 3.3 does not
include efficiencies for underground storage and pipeline transport. Additionally, the Scoping Plan is
unclear on exactly where the biogas used for steam methane reforming, or the hydrogen produced this
way, is coming from other than that it is being imported. Where and how the biogas for steam methane
reforming is sourced may add additional considerations around transport, leakage, and unintended
climate consequences. (See Section 4.2.2.2 for more.)
Regardless of the method used, the overall energy efficiency of hydrogen production depends not only
on the generation, compression, storage, and transport processes described above, but also on the
specific end use for the hydrogen. This is further discussed in Section 3.2.
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3.1.2. Hydrogen Storage and Pipeline Transport Considerations
Hydrogen can be stored as a gas or as a liquid. At smaller scales, gaseous hydrogen can be stored in
cylinders or vessels at a facility, typically at very high pressure. Liquid hydrogen, which is stored at
temperatures below -253˚C, is typically kept in cryogenic storage tanks (DOE, n.d.-b). At large scales,
various forms of underground bulk storage will likely be necessary.
The efficiency of hydrogen storage and transport in California depends on the surrounding
infrastructure. Hydrogen storage efficiencies vary by method, which in some cases may depend on
geography. Hydrogen transport efficiencies depend on both distance and method, with pipeline
transport as the most energy efficient. However, building out dedicated hydrogen pipelines is
expensive, and blending hydrogen into the existing natural gas stream carries its own costs,
challenges, and risks. Considerations for both hydrogen storage and transport, with a focus on
pipelines, are discussed below.
3.1.2.1. Bulk Hydrogen Storage
Building out a dedicated “green” hydrogen system in California will require significant amounts of
storage, although the magnitude is highly uncertain. Trucked hydrogen, for example, will require more
dedicated on-site storage relative to supply than a facility supplied by a pipeline, which can inherently
“store” some hydrogen within the pipeline itself.
Proposed formations for large-scale hydrogen storage include aquifers, abandoned mines, depleted
oil and gas fields, rock caverns, and salt caverns (Małachowska et al., 2022). Each of these proposed
options has its own set of efficiency considerations and geographical constraints. Bulk hydrogen
storage in salt caverns has already been demonstrated at a number of sites in the United Kingdom and
the U.S. (Miocic et al., 2023). In general, salt caverns have been identified as one of the most promising
underground geologic formations for hydrogen storage due to high reported efficiencies and expected
long-term structural integrity of the caverns, among other factors (International Energy Agency [IEA],
2019; Małachowska et al., 2022). However, as there is no capacity for underground storage of natural
gas in salt caverns in California, there is likely no capacity for underground storage of hydrogen in salt
caverns either (EIA, n.d.-a).
Other opportunities for underground storage of hydrogen in California are still under investigation.
The California Energy Commission (CEC) has identified knowledge gaps and allocated research
funding to better characterize the economics and technical feasibility of underground hydrogen
storage across the state, with a request for proposals outstanding as of April 2024 (CEC, n.d.). There
has been preliminary research on the potential of using saline aquifers in the Sacramento Basin and
depleted oil and gas fields in both Northern and Southern California (Sekar et al., 2024; Okoroafor et
al., 2022; SoCalGas, 2021a). (Depleted oil and gas reservoirs are the most common underground pore
34 | Green Hydrogen Proposals Across California | PSE Healthy Energy
space in California, with more than 150,000 abandoned or idle wells as reported in Fischer et al.
(2020).) However, both storage types have technical challenges leading to efficiency concerns. For
example, a study by Zivar et al. (2021) indicated possible efficiency losses due to unrecovered gas and
gas mixing. Gas mixing reduces the purity of the hydrogen when storing it in depleted gas reservoirs or
aquifers. While losses from unrecovered gas can be mitigated by using a lower-cost “cushion gas” such
as CO
2
, CH
4
, or nitrogen (N
2
) to increase the reservoir pressure and boost recovery efficiency, this can
introduce mixing. In some cases, microbial activity can also decrease storage efficiency. For example, a
study by Haddad et al. (2022) indicated that almost 40 percent of hydrogen injected into an aquifer
could transform into hydrogen sulfate, methane, and formate within 90 days because of microbial
activity. It is also worth noting that many of these same formations are under consideration for
geologic CO
2
storage, and to our knowledge there is no research on the relative value of using these
sites for either application or the system-wide potential for CO
2
and hydrogen storage (Kim et al.,
2022).
Potential risks associated with underground hydrogen storage range from cyclic stress on the storage
facility—which could lead to fault propagation, caprock failure, and well sealing failure—to the
acceleration of microbial growth that might clog pores or produce corrosive by-products (e.g.,
hydrogen sulfide) (Miocic et al., 2023). Across the U.S., others have proposed using existing natural gas
storage facilities (including for gas-hydrogen blends) (Lackey et al., 2023). Yet it is unclear whether the
existing gas infrastructure at these facilities would be subject to accelerated degradation when
exposed to hydrogen. Historic gas leaks from underground natural gas storage, including the
unprecedented Aliso Canyon leak in 2015, highlight the need for proper maintenance, monitoring, and
emergency response procedures for these and other potential underground hydrogen storage sites
(California Public Utilities Commission, n.d.).
70
This is mostly considered for import and export by countries outside of the U.S.
35 | Green Hydrogen Proposals Across California | PSE Healthy Energy
3.1.2.2. Pipelines
Several existing proposals, including CARBʼs Scoping Plan and the Angeles Link proposed by SoCalGas,
outline the delivery of large volumes of hydrogen via pipelines. As of 2023, California only has about 27
miles of dedicated hydrogen pipelines, clustered in industrial areas (Cerniauskas et al., 2023). The lack
of infrastructure for hydrogen means that California would likely have to rely on blending hydrogen
into existing gas transmission and distribution pipelines—of which there are more than 100,000 miles
spread throughout the state—if it were to try to transport hydrogen via pipeline in the near term
(California Public Utilities Commission, n.d.-a). However, dedicated hydrogen pipelines would likely be
needed to meet proposed hydrogen demand in the long term and may improve safety risks compared
to blending (discussed further below). There are significant unknowns related to the magnitude of
pipeline infrastructure buildout that would be required to meet statewide hydrogen targets, due in
large part to uncertainties about where the hydrogen would be produced. Hydrogen transmission in
pipelines, whether blended or stand-alone, also raises concerns related to safety, cost, and
deployment timelines.
Using Existing Pipeline Infrastructure (Blending). Several California utilities are proposing to blend
hydrogen with gas in existing pipelines to deliver to buildings, the power sector, and other end users.
Pacific Gas and Electric (PG&E) is partnering with the city of Lodi, the Northern California Power
Agency, and others on the Hydrogen to Infinity project. This project is a hydrogen gas transmission
facility that will test hydrogen production, transport, and storage as well as provide a blend of
hydrogen and gas for combustion at a power plant in Lodi (PG&E, n.d.). San Diego Gas and Electric
(SDG&E) has proposed a hydrogen blending project at the University of California, San Diego to study
the impacts of up to 20 percent hydrogen blending on gas distribution infrastructure (SDG&E, 2022).
SoCalGas is testing the use of this blend for gas-based home appliances such as heaters and stoves
(SoCalGas, 2021b; SoCalGas, n.d.-a). The Scoping Plan also relies on blending hydrogen into all
existing gas pipelines at a rate of 20 percent by volume (seven percent by energy) by 2040 (CARB,
2022d).
36 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Blending hydrogen with natural gas requires higher flow rates and higher pressures to deliver the
same amount of energy, due to the hydrogen's lower energy density. The increased pressure
requirements heighten the risk of gas leakage throughout the gas transmission and distribution
system. Initial studies suggest that hydrogen leaks through polymer pipes at a rate seven times higher
than natural gas, through joints at roughly a factor of four higher, and altogether that
hydrogen-natural gas blends substantially increase total gas leakage rates from pipelines (Penchev et
al., 2022).
Transporting hydrogen in steel pipelines also increases the risk of pipeline embrittlement due to
hydrogen adsorption, which makes the metal more susceptible to cracking or breaking. This could
lead to higher gas leakage rates over time, alongside safety risks (Energy Transitions Commission,
2021). The Hydrogen Blending Impact Study, commissioned by the California Public Utilities
Commission, found that hydrogen-gas blends with more than five percent hydrogen by volume
increased the risk of steel pipeline embrittlement and the associated leakage rates compared to pure
methane (Penchev et al., 2022). Some studies have suggested that blends of up to 20 percent hydrogen
by volume can operate without issue. However, the impacts of higher concentrations of hydrogen are
still uncertain, as are the abilities of end-use appliances or industrial applications to operate at higher
blends (Staffell et al., 2019). In contrast, some pipeline operators have indicated that significant
investments would be required to upgrade natural gas pipelines to operate safely with 20 percent
hydrogen blends (Martin, 2023). Significant retrofits may be required for pipelines transporting even
moderate fuel blends, while full replacements may be required for pipelines that are planned to
transport higher fractions of up to 100 percent hydrogen. Despite these issues, the Scoping Plan
assumes no additional pipeline maintenance or upgrade costs when blending hydrogen with natural
gas at 20 percent volume.
Another proposal under preliminary consideration is to institute hydrogen de-blending. This process
would mix hydrogen into existing gas systems and then apply technologies such as electrochemical
hydrogen separation and purification to 1) reduce the hydrogen concentration in gas blends passing
through sensitive infrastructure, and 2) separate out the hydrogen for end use.
71
The California Energy
Commissionʼs Gas Research and Development Program is currently considering hydrogen de-blending
as one of its primary research objectives in its proposed 2024-2025 budget plan (CEC, 2023a).
Building New Pipeline Infrastructure. In the long term, California will likely need to build out
pipeline capacity to meet the proposed levels of hydrogen demand and avoid the safety risks of using
hydrogen in infrastructure not designed for it (Khan et al., 2021; Cerniauskas et al., 2023). Initial
estimates suggest that hydrogen transmission pipelines will be somewhat more expensive than
71
It is unclear what the intended end use for this hydrogen would be, although the dra proposal includes a
figure indicating power plants, industry, transportation, and buildings would all be potential candidates. This
last application, if pursued, would stand in contrast to most other plans in California, and raises significant
additional concerns related to feasibility, cost, and safety.
37 | Green Hydrogen Proposals Across California | PSE Healthy Energy
natural gas transmission pipelines, due in part to more stringent design requirements to mitigate leaks
from welds, valves, and other components (Khan et al., 2021).
Based on the Scoping Plan, California will need to transport 0.06 EJ of hydrogen to end users in 2030,
ramping up to 0.23 EJ in 2045 (meeting nearly nine percent of total energy demand). Other
organizationsʼ forecasts vary significantly. In SoCalGas territory alone, the preliminary assessment
projects that 2045 demand may reach 1.9–6 million tons per year of hydrogen, which is equivalent to
0.27–0.86 EJ (SoCalGas, 2024). The magnitude of the required pipeline buildout is therefore very
difficult to estimate due to several significant uncertainties, including the total final demand, which
sectors will require hydrogen, and where and how hydrogen will be produced. For example, hydrogen
derived from biofuels would require very different transportation infrastructure if produced in
distributed locations near biomass sources, compared to centralizing biomass residues by truck
transport at a few larger hydrogen production facilities. Highlighting this uncertainty, the proposed
Angeles Link pipeline, intended to supply hydrogen to Los Angeles, has explored sourcing hydrogen
from locations ranging from the Central Valley, more than 200 miles away in Blythe on the Arizona
border, and even from Utah (SoCalGas, 2022b). (See Section 7 for more details on Angeles Link.)
As described above, California currently has less than 30 miles of hydrogen pipelines. The U.S. as a
whole has roughly 1,550 miles of hydrogen pipelines, mostly in the Gulf Coast (Khan et al., 2021).
Hydrogen flows more easily through pipelines than natural gas but is less energy dense, leading to an
estimated maximum energy flow of 88 percent compared to natural gas in a pipeline (Khan et al.,
2021). However, achieving these flow rates requires much higher pressure, resulting in the need for
more energy and cost to compress the gas as well as triggering additional safety and leakage concerns,
as noted previously.
Barring major protests, lawsuits, or other challenges, the permitting process for pipelines is expected
to take 2.5–4 years to get to the construction phase (Cerniauskas et al., 2023). However, given the
novelty of hydrogen pipeline siting in California—and the well-known challenges and delays
frequently faced by energy infrastructure proposals statewide—pipeline permitting may well take
longer. In addition, the significant uncertainty associated with supply and oakers (utilities,
companies, or other entities that agree to buy hydrogen) seems likely to extend hydrogen pipeline
development timelines further (California Council on Science and Technology, 2023). For example, the
Angeles Link pipeline, which was first proposed in February 2022, still has no agreed-upon hydrogen
supply nor route more than two years later (SoCalGas, 2022c). Adding on additional years for
construction, the State is likely many years away from having any dedicated “green” hydrogen
transmission pipelines. This raises numerous questions related to the security of supply. For example,
if Los Angeles converts its power plants to run on hydrogen beginning in 2029 as proposed, will this
hydrogen have to be delivered on trucks? Does this introduce price volatility risks? What happens if
storage is limited? Moreover, there are significant stranded asset risks with pipeline buildout. Building
a pipeline without dedicated oakers risks investing billions of dollars in what might be a stranded
38 | Green Hydrogen Proposals Across California | PSE Healthy Energy
asset, but even with dedicated oakers there are uncertainties related to building the infrastructure
within the currently proposed timelines.
3.2 Energy Efficiency of Hydrogen Use
Today, hydrogen is predominantly used in crude oil refining, ammonia production, and methanol
production (EIA, 2019b). However, climate and energy planners across California are now considering
hydrogen for a range of applications, including transportation and long-duration energy storage. The
energy efficiency of each of these uses depends on the application itself and should be evaluated in
comparison to possible alternatives. A few of these end uses are discussed below. The potential
climate impacts of these pathways and pathway trade-offs are discussed in Section 5.
3.2.1. Hydrogen in the Power Sector
There are numerous different proposed plans for using hydrogen in Californiaʼs power sector,
depending on the stakeholder. For example, many California utilities, including LADWP, SoCalGas,
SDG&E, and PG&E, are proposing to blend hydrogen and natural gas or burn hydrogen directly in
electric power plants to replace existing gas-fired electricity generation (LADWP, 2022a; SoCalGas,
n.d.-b; SDG&E, n.d.-b; PG&E, n.d.). At the State level, CARBʼs Scoping Plan proposes to meet all
electricity demand without burning hydrogen in power plants for everyday power needs. However, the
Plan does rely on the build-out of hydrogen-burning plants to provide emergency backup and to meet
resource adequacy requirements. This would, of course, inherently require some amount of hydrogen,
but this amount is not estimated in the Scoping Plan.
3.2.1.1. Using Hydrogen to Generate Electricity
While demonstration projects have shown that existing natural gas plants can burn low-level blends of
hydrogen and natural gas, hydrogen is not a drop-in replacement for natural gas in existing
infrastructure (EPRI, 2023; Larson, 2023). The different chemical properties of hydrogen require some
operational changes; for instance, the system needs to be fed more fuel per minute because hydrogen
is less energy dense than natural gas (Wilkes et al., 2022). It can also lead to operational instabilities,
including potential flashback (where the ignition flame blows backwards), potential blow out (where
the ignition flame goes out), and component damage from mechanical and heat stress (Cecere et al.,
2023). Additionally, hydrogen blending in existing systems can reduce combustion efficiency, change
cooling requirements, and lead to an increase in NO
x
emissions that must be managed (Wilkes et al.,
2022; Cecere et al., 2023). Using hydrogen in existing gas combustion systems would require either
significant retrofits, including for safety and leak detection systems, or full infrastructure replacement.
39 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Combustion turbines designed to burn 100 percent hydrogen have not fully entered the commercial
phase, but estimates of current technologies suggest they are roughly 40 percent efficient at
converting hydrogen to electricity (Nature Research Custom Media and Kawasaki, 2022).
Hydrogen fuel cells can also be used to provide electric power, as SDG&E is proposing to do with an
electrolyzer and fuel cell combination at its microgrid in Borrego Springs (SDG&E, n.d.-a). Depending
on the particular technology chosen, fuel cells are 40–60 percent efficient, with alkaline, PEM, and
solid oxide fuel cells at the higher (60 percent) end of that range (DOE, 2015). (Other fuel cell types
include phosphoric acid and molten carbonate, which are roughly 40 and 50 percent efficient,
respectively (DOE, 2015).)
3.2.1.2. Using Hydrogen to Store Electricity
Hydrogen is also under consideration as a means of storing electricity, much like a battery. This
approach would use renewable electricity to produce hydrogen and then store that hydrogen to be
converted back to electricity when needed. This is the plan for the electrolyzer and fuel-cell
combination at Borrego Springs. In this case, SDG&E plans to use local solar to produce hydrogen,
store it in tanks at the facility, and then use fuel cells to convert it back to electricity as needed (SDG&E,
n.d.-a).
Okoroafor et al. (2022) evaluated Californiaʼs potential for generating hydrogen from curtailed
renewables and storing it in depleted gas fields before converting it back to electricity. Assuming
hydrogen generation occurred near storage sites, they estimated a maximum
power-to-hydrogen-to-power roundtrip efficiency of 36 percent (Okoroafor et al., 2022). However, their
estimates are based on a 64 percent efficiency for converting hydrogen back to electricity, using GEʼs
9HA combined cycle turbine. Notably, this turbine currently does not support more than a 50 percent
hydrogen blend (GE Vernova, n.d.). More research is likely needed to determine these efficiencies
under real-world scenarios.
3.2.1.3. Battery Storage as an Alternative to Hydrogen in the Power Sector
The electricity used to produce hydrogen via electrolysis could also be used directly or stored in
batteries for later use. In Figure 3.4, we compare the full energy losses associated with electrolytic
hydrogen production and reconversion back to electricity with an alternative case, in which electricity
is stored in either lithium-ion batteries (for short-term storage) or iron-air batteries (for long-term
storage). While significantly more efficient than either hydrogen option, lithium-ion batteries are not
currently economical for long-duration energy storage on the grid. However, with stakeholders in
California considering hydrogen for use in peaker plants, which are typically only activated during
peak demand, storage comparisons are worthwhile for grid planning purposes.
40 | Green Hydrogen Proposals Across California | PSE Healthy Energy
Figure 3.4: Comparison of Electricity-to-Storage-to-Electricity Efficiencies for Hydrogen,
Lithium-Ion, and Iron-Air Batteries. In each instance, efficiencies are calculated as starting and
ending with electricity. For hydrogen, the production efficiency range covers both levels of
infrastructure build out depicted in Figure 3.1.
In Figure 3.4, we adopt Kawasaki Heavy Industries (n.d.) hydrogen turbine combustion efficiency of
roughly 40 percent and a fuel cell efficiency of 40–60 percent, as established in the literature (Jamal et
al., 2023; DOE, 2015). Using the electricity-to-stored-hydrogen efficiency of 37–82 percent as outlined
in Figure 3.1, this gives a total efficiency of roughly 15–50 percent using fuel cells and of roughly 15–35
percent via combustion for electrical energy stored as hydrogen and then converted back to electricity.
While the technology is not commercially operational, efficiency estimates for a reversible solid oxide
fuel cell system operating in 2030 are as high as 52 percent (Glenk and Reichelstein, 2022).
In contrast, existing battery storage options may be more efficient. Lithium-ion batteries are between
78–95 percent efficient, depending on factors such as the specific battery chemistry in use (e.g.,
lithium cobalt oxide, lithium-iron phosphate, etc.); temperature; operating requirements (e.g., rate of
charge or discharge); battery state-of-health (e.g., how old and degraded it is); and the battery
management system (Qian, 2011; Lin et al., 2023; Chen et al., 2020; EIA, 2021; NREL, 2022). In electric
grid applications, these batteries are typically used for shorter storage durations (roughly 2–6 hours),
due in large part to current market forces. Other technologies are currently in various stages of
development to provide longer-duration energy storage (e.g., daily, multi-day, or seasonal). For
41 | Green Hydrogen Proposals Across California | PSE Healthy Energy
example, iron-air batteries (which are just entering the commercial phase) are marketed for 100-hour
storage applications (Form Energy, n.d.). These batteries have poor energy density, so they are meant
for stationary applications, but use relatively low-cost, non-toxic materials. Their round-trip efficiency
is much lower than lithium-ion battery chemistries (estimates range from approximately 40–46
percent) (Wilson, 2022; Go et al., 2023). This is on par with hydrogen fuel cells but more efficient than
hydrogen combustion, although research is being undertaken to bring iron-air battery efficiency to
above 60 percent (Fraunhofer Institute for Environmental, Safety and Energy Technology, 2024).
The comparison of energy storage, hydrogen fuel cell, and hydrogen combustion technologies can be
overly simplistic without acknowledging that their varying characteristics make each one more or less
suitable for different grid applications. Additionally, each technology may operate most efficiently and
cost-effectively when meeting multiple grid needs at once. In many cases, a battery or a fuel cell may
not be optimally utilized if used as a one-for-one replacement of todayʼs natural gas plants. For one,
the need for a dispatchable supply of electricity is changing as California adds both renewable energy
and flexible demand (e.g., electric vehicles, smart thermostats) to the grid. For example, Californiaʼs
aging natural gas steam plants (including some of LADWPʼs plants) ramp up very slowly and run for
long periods of time, and this lack of flexibility means they do not pair well with intermittent
renewables. It may be better to replace these plants with a more flexible technology—which means
batteries and fuel cells may actually perform better than the plant they are replacing at meeting
specific needs as the grid continues to evolve. Second, energy storage can provide many services
beyond electricity supply. Energy storageʼs ability to manage a surplus of daytime solar (i.e., by
charging) and to reduce the need for distribution or transmission upgrades, among other applications,
means that it may provide significant value above and beyond replacing a natural gas plantʼs services,
and should be valued accordingly. And finally, even if one were to try to replace a gas plant
one-for-one, it may be best to do so with a mix of technologies. Examples include: using demand
response to address rare very high peak demand days; using lithium-ion batteries for short-duration
peak supply needs; and using long-duration energy storage or hydrogen fuel cells to manage multi-day
or seasonal variations in renewable energy supply. Combining technologies to replace a single gas
plant is typically referred to as a “virtual power plant.” This approach may be more cost-effective at
replacing, for example, LADWPʼs natural gas power plants, rather than simply swapping out all of the
existing natural gas turbines with hydrogen combustion turbines. Using a mix of technologies may also
provide more environmental health benefits than hydrogen combustion, which we discuss in Section
6.1.
3.2.2. Hydrogen in the Residential and Commercial Sectors
By and large, proposed hydrogen use in Californiaʼs residential and commercial sectors primarily
involves blending hydrogen gas into the existing natural gas system. This strategy and its implications
are discussed below. We also compare this decarbonization strategy to directly electrifying end-use in
42 | Green Hydrogen Proposals Across California | PSE Healthy Energy
the residential and commercial sectors, with a focus on the alternative approach of using heat pumps
to meet space heating needs.
3.2.2.1 Hydrogen Blended into Gas Distribution Pipelines
As mentioned previously, SoCalGas, SDG&E, and PG&E are all proposing to blend hydrogen into
existing natural gas pipelines in pursuit of decarbonizing the gas system (SoCalGas, n.d.-c; SDG&E,
n.d.-b; PG&E, n.d.). The Scoping Plan also intends for utilities to blend renewable hydrogen into
natural gas pipelines serving buildings and industry (at seven percent of energy, which is roughly 20
percent by volume). In 2023, the residential and commercial sectors (namely, buildings) were
responsible for 23 and 13 percent of the Stateʼs natural gas consumption, respectively; 31 percent was
consumed in the industrial sector (EIA, n.d.-b). In Californiaʼs residential and commercial sectors,
natural gas is primarily used for space and water heating (Itron, Inc., 2006; South Coast Air Quality
Management District, 2016). Based on data from the U.S. Energy Information Administration, natural
gas is the primary source of space heating in 64 percent of households in California and an estimated
54 percent of heated commercial buildings in the Pacific census region (EIA, 2022, 2024).
72
The main technologies used for natural gas-based heating are furnaces and boilers. Of the homes and
buildings that use gas as their main source of space heating, roughly 88 percent of homes in California
and 13 percent of commercial buildings in the Pacific region rely on furnaces, which are 59–98.5
percent efficient depending on their age (EIA, 2024). Almost half of commercial buildings that use gas
as their main source of space heating use boilers (EIA, 2022). An Energy Star-certified gas boiler has a
minimum efficiency of 90 percent, though the efficiency could be much lower for older systems (DOE,
n.d.-c).
The impact of hydrogen blends on the efficiency of this heating equipment is still uncertain. A 2022
study on space and water heating equipment funded by a group of gas distribution companies
suggested minimal efficiency impacts from hydrogen blends up to 30 percent (Glanville et al., 2022).
However, a 2022 study from the California Public Utilities Commission highlighted operational and
safety concerns, including impacts on household appliances, from blending hydrogen into the gas
system at more than five percent (Penchev et al., 2022). (For more on this, see Section 3.1.2.2 above
on pipeline blending.)
3.2.2.2 Heat Pumps as an Alternative to Hydrogen-Gas Blends for Decarbonized Heating
Numerous independent studies have concluded that using hydrogen instead of gas for space or hot
water heating is overall less efficient (and more expensive) than direct electrification alternatives such
as heat pumps, given the losses inherent in generating, transporting, and using hydrogen (Rosenow,
72
These data report commercial building information by region, rather than state. California is included within
the Pacific census region.
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2022; Makhijani and Hersbach, 2024). Air source heat pumps can provide two to three times more heat
energy than they consume in electrical energy, giving them comparable efficiencies of 200 to 300
percent (ENERGY STAR, n.d.). A review of 32 studies suggests that heating a home with hydrogen would
require roughly five times the amount of energy required for a heat pump to heat the same space,
even assuming an 80 percent electrolysis efficiency (Rosenow, 2022). These findings are higher than
our electrolysis efficiency estimates in this report but may be in line with future efficiencies achieved
using solid oxide electrolysis cells. The IEA Global Hydrogen Review (2023) also reaffirms that
electrifying heating with heat pumps and district heating is more efficient than heating buildings with
hydrogen.
In an effort to decarbonize residential and commercial heating, the Scoping Plan directs the
deployment of six million electric heat pumps and three million all-electric and electric-ready homes
by 2030 (CARB, 2022d). However, only an estimated 600,000 homes in California had heat pumps as of
2021 (Janusch, 2022). There are roughly 13.2 million occupied homes in California, roughly 2.7 million
of which use electricity and 8.4 million of which use natural gas for home heating (EIA, 2024). Some of
these six million new heat pumps will go to new construction and some to replace electric baseboard
heating systems (which are generally less efficient, and more expensive, than natural gas systems)
(CEC, 2022a). So under the Scoping Plan, a significant number of homes will likely remain reliant on
the existing natural gas system. For residential and commercial buildings still connected to the gas
system, the blending of hydrogen into gas pipelines discussed above would reduce greenhouse gas
emissions by a maximum of seven percent (see Section 5). But replacing gas for home heating with
heat pumps, and using renewable electricity to directly power them instead of producing hydrogen,
would reduce greenhouse gas emissions by a factor of five (Makhijani and Hersbach, 2024).
3.2.3 Hydrogen in the Transportation Sector
Roughly half of Californiaʼs greenhouse gas emissions are from transportation, and many
decarbonization pathways proposed for this sector rely heavily on hydrogen. This is due in part to
potential challenges with electrifying medium- and heavy-duty transport (CEC, 2019). For example, the
Scoping Plan assumes that nearly two-thirds of the total 2045 hydrogen supply will be used by
medium- and heavy-duty vehicles. It also assumes that by 2035, freight and passenger rail will rely
primarily on hydrogen fuel cell technology. Additionally, the Scoping Plan assumed that by 2045, 25
percent of ocean-going vessels will use hydrogen fuel cell technology, and 20 percent of aviation fuel
demand will be met by either hydrogen or batteries. (See Section 4.1 for more on the Scoping Planʼs
hydrogen-based transportation assumptions.)
Port authorities throughout California are also moving to incorporate hydrogen. In 2023, the Ports of
Los Angeles and Long Beach partnered to develop hydrogen fueling stations, mobile hydrogen fueling
trucks, hydrogen fuel cell cargo handling equipment, and ultimately, to support the buildout of
heavy-duty hydrogen fuel cell trucks (Port of Los Angeles, 2023). These ports are partnering with
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ARCHES and their work is supported by DOE hydrogen hub funds (Office of Governor Gavin Newsom.,
2023). The Port of San Diego is also exploring the potential of using hydrogen to achieve the
zero-emission heavy-duty cargo truck goals outlined in its Maritime Clean Air Strategy (Port of San
Diego, 2022).
Fuel cells, rather than combustion, are expected to dominate hydrogen use in the transportation
sector. Hydrogen fuel cells have a global efficiency of 40–60 percent, depending on technology (IEA,
2019; DOE, 2015). This is significantly more efficient than gasoline-powered internal combustion
engines, which are roughly 12–30 percent efficient, and slightly more efficient than diesel engines,
which are around 28–42 percent efficient (DOE, n.d.-d; Albatayneh et al., 2020). In the following
subsection we explore hydrogen fuel cell use in passenger vehicles, heavy-duty trucks, trains, and
boats.
3.2.3.1 Hydrogen for Passenger Vehicles
Californians are predominantly adopting electric cars (relying on batteries) to replace their
gasoline-powered cars, and none of the plans or proposals outlined above focus on hydrogen for use
in passenger (or “light duty”) vehicles (California Natural Resources Agency, n.d.).
73
However, the
overall efficiency of hydrogen fuel cell vehicles and battery-electric vehicles may still be worth noting.
Argonne National Laboratories suggests a 62 percent average drive cycle efficiency for the Toyota
Mirai, a hydrogen fuel cell electric vehicle (Lohse-Busch et al., 2020). (This efficiency is likely higher
than the fuel cell efficiency cited above because the Mirai also has a battery and uses regenerative
braking.) However, a study commissioned by Volkswagen suggests the overall efficiency of hydrogen
fuel cell cars could be much lower—on the order of 25–35 percent when including hydrogen
production, compression, and transport (Volkswagen, 2020).
For battery-electric cars, the overall efficiency is 60-90 percent, depending on electricity line loss,
battery efficiency, and whether regenerative braking is used (DOE, n.d.-d). In California, the amount of
electricity lost during transmission and distribution is roughly six percent.
74
Electric vehicle battery
capacity and efficiency decrease over time as batteries degrade. While fuel cells also degrade and lose
efficiency over time, their working lifespan for this application is longer than batteries (De Wolf and
Smeers, 2023). Battery electric vehicles are therefore expected to require 2–3 times less renewable
electricity to operate than hydrogen fuel cell vehicles. However, the relative environmental impacts of
the materials used in batteries as compared to fuel cells, over the full lifetime of the car (including any
replacements), should also be considered when comparing these alternatives.
74
Calculated from the EIA California State Energy Profile. (U.S. Energy Information Administration (n.d.). March
11, 2024. California State Energy Profile. Table 10.).
73
The Scoping Plan, for example, projects that only three percent of light-duty vehicle energy demand will be
met with hydrogen in 2045.
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3.2.3.2 Hydrogen for Heavy-Duty Trucks
In California, fuel cells are being considered more seriously for medium- and heavy-duty trucking. Fuel
cells may be more practical in some of these applications because hydrogen fuel cell powertrains can
offer longer ranges at lighter weights than their existing battery electric counterparts (Umicore, 2022).
Hydrogen fuel cell vehicles also have faster refueling times—refueling takes 10-15 minutes for
medium- and heavy-duty trucks with large tanks (DOE, n.d.-e). For comparison, battery electric trucks
can take roughly 10 hours to charge with an AC charger or two hours with a DC fast charger (Volvo
Trucks, 2021). This makes hydrogen fuel cell trucks a potentially attractive option for trucks used for
multiple shis during a single day, though further research is warranted given the dearth of data on
fuel cell trucks.
For fuel cell electric vehicles, fuel efficiencies of 11–15 miles/kg H
2
and 4.79–11 miles/kg H
2
have been
reported for medium-heavy and heavy-duty trucks, respectively. However, CARBʼs Vision 2050 model
projects these efficiencies to increase to 16.4–21 miles/kg H
2
and 5.1–16.1 miles/kg H
2
(Forrest et al.,
2020). A hydrogen fuel cell truck currently on the road in Europe has a fuel tank storage capacity of 31
kg H
2
and reports an all-electric range of 400 kilometers (roughly 250 miles) (Hyundai, n.d.).
For battery electric vehicles, fuel efficiencies of 1–1.93 kWh/mile and 1.97–2.47 kWh/mile have been
reported for medium-heavy and heavy-duty trucks, respectively. CARB projects these to increase to
1.62–2.09 kWh/mile and 2.11–6.61 kWh/mile by 2050 (Forrest et al., 2020). In 2020, the range for these
trucks was reported as roughly 170 miles (with battery capacities up to 324 kWh and 435 kWh for
medium- and heavy-duty, respectively)(Forrest et al., 2020). Light-duty trucks had reported ranges of
up to 300 miles (Forrest et al., 2020). While not yet on the road, Tesla has advertised the release of a
heavy-duty semi-truck with a fuel efficiency of around 2 kWh/mile, an estimated range of 500 miles,
and that can charge up to 70 percent in 30 minutes with fast charging (Tesla, Inc., n.d.; Kane, 2022).
Without efficiency improvements in either battery chemistries or truck designs, increasing the capacity
of these batteries could lead to higher weight, which may lower the truckʼs fuel efficiency. However,
efficiency improvements and faster charging times are an active area of research.
Despite their increased weight, battery electric trucks are more efficient than their hydrogen
counterparts. The relative efficiency of an electric truckʼs drivetrain is approximately 85 percent
compared to 50 percent for fuel-cell trucks (Gray et al., 2022). However, if we consider the initial
conversion efficiency of electrolytic hydrogen production from renewable electricity (assuming an
average conversion efficiency of roughly 60 percent (see Figure 3.1), then the total relative efficiency
of fuel cell trucks is only about 30 percent.
Battery electric vehicles may be better suited than hydrogen fuel cell options for replacing light-duty
trucks, particularly at shorter distances and for trucks able to charge overnight. However, for medium-
and heavy-duty trucks, hydrogen fuel cells could be a reasonable option given considerations such as
truck weights and fueling times. An analysis by Forrest et al. (2020) concluded that the ability of
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battery electric options to replace fossil-fuel models of medium- and heavy-duty trucks in California is
limited by battery capacities and charging rates, while fuel cell electric trucks are limited by their
efficiencies, tank size, and the availability of hydrogen refueling infrastructure. This indicates that the
efficiency of battery or fuel cell options will ultimately depend on necessary travel distances, truck
payload and cargo weights, truck schedules, charging infrastructure availability, and similar
factors—as well as future technology improvements.
3.2.3.3 Hydrogen for Trains
Hydrogen fuel cells have also been studied for use in trains, and California plans to convert certain
intercity rail lines to hydrogen (Fakhreddine et al., 2023; California Department of Transportation,
2022). Using methods outlined by Washing and Pulugurtha (2015), we estimate the efficiency of trains
powered by electrolytic hydrogen fuel cells to be roughly 20–50 percent. This compares to an
efficiency of roughly 65 percent for electrified trains that run using a connected catenary system,
though this external power system requires more associated infrastructure than on-board fuel
configurations. Electrified trains that rely on on-board batteries are currently used mostly for shorter
distances, due to similar challenges around charging times and vehicle weight as faced by large trucks
(Ghaviha et al., 2019).
A recent study out of Germany, however, determined that hydrogen trains were up to 80 percent more
expensive than full electric or battery hybrid options (Ministry of Transportation of
Baden-Württemberg, 2022). While the use of hydrogen for trains required little to no change in rail
infrastructure, the limited availability of “green” hydrogen and low efficiencies were both cited as
issues with the use of hydrogen for this application (Collins, 2022). The Baden-Württemberg state in
Germany has been operating a hydrogen rail line for a year, but now plans to switch to more
economical electric options (Collins, 2022; RailTech, 2023).
3.2.3.4 Hydrogen for Boats
Combined battery and hydrogen fuel cell systems have also been tested for ocean-going vessels, with
overall (combined battery and fuel cell) efficiencies around 60 percent (EO Dev, n.d.). In at least one
case, a PEM fuel cell supplied most of the power, with batteries providing energy for peak usage. In
2016, Sandia National Laboratories modeled a high-speed ferry powered by hydrogen fuel cells, which
achieved an optimal fuel cell efficiency of 53.3 percent (Pratt and Klebanoff, 2016).
Scripps Institution of Oceanography (Scripps) in San Diego is also developing a hybrid hydrogen
research vessel, alongside Sandia National Laboratories and Glosten (Reed et al., 2022). The vessel is
designed to use liquid hydrogen to meet most of its energy needs, with diesel generators supplying
additional power when necessary (Scripps, 2021). Research is also ongoing for other paired hydrogen
fuel cell and battery power systems for ocean-going vessels (Wang, Z. et al., 2022).
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3.2.4 Hydrogen in Industrial Processes
Some industrial processes, like cement production, rely on high temperatures that electricity alone
cannot generate efficiently. Such high-heat processes are difficult to electrify, and hydrogen offers a
promising replacement for fossil fuels in these industries. The Scoping Plan directs hydrogen use for
100 percent of process heat by 2045 for the pulp and paper industries, as well as chemicals and allied
products (the latter being those made through mostly chemical processes).
75
The Scoping Plan also
stipulates that dedicated hydrogen pipelines would be built in the 2030s to serve some industrial
clusters, recognizing the potential for hydrogen to replace fossil fuels in some industrial processes.
Oil refining operations, one of the largest sources of industrial emissions in California, already use
hydrogen. Notably, it is used as part of the refining process rather than to provide process heat and is
currently primarily produced from natural gas. However, as the state moves towards zero emissions,
this sector will likely shrink, requiring less hydrogen (and reducing greenhouse gas emissions overall)
(Energy and Environmental Economics, Inc., 2024).
While these industrial processes lack a direct electrification comparison, as previously discussed,
hydrogen is not a one-to-one replacement fuel in all industrial applications that currently use natural
gas. System retrofits would be required for any significant hydrogen blending in numerous industrial
applications, since control systems and other components of current gas turbines, engines, boilers,
and other gas combustion systems were not designed for hydrogen or hydrogen blends (IEA, 2019).
75
However, CARBʼs Scoping Plan data also shows the continued use of natural gas for process heat in these same
industries in 2045.
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4. CARB Scoping Plan: Hydrogen Energy Requirements and
Compounding Interactions with DAC and CCS
Many California planners are considering the role of green hydrogen in decarbonization efforts. The
CARB Scoping Plan provides the most comprehensive scenario for hydrogen deployment
economy-wide over the coming decades. In this section, we use the energy efficiency values for
hydrogen production and use described in Section 3 to estimate the energy demands required to
meet hydrogen deployment goals in the Scoping Plan as well as to calculate the rate of annual average
renewable energy deployment that this demand would entail. The energy inputs for hydrogen
production in the Scoping Plan are considered to be “off-grid.” However, here we add these inputs to
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the total renewable energy requirements projected by the Scoping Plan to decarbonize the stateʼs
energy systems. This allows us to better understand the total renewable energy deployment that may
be required statewide. Finally, we also look at the energy requirements for carbon capture and storage
as well as direct air capture of CO
2
—technologies that, like hydrogen, are omitted from the Scoping
Planʼs energy modeling. This analysis helps to better understand how these demands may compound
and affect total renewable energy requirements and deployment speeds.
4.1 Summary of CARB Scoping Plan Hydrogen Energy Requirements
The 2022 CARB Scoping Plan is the third update to CARBʼs original Scoping Plan of 2008 and the most
up-to-date California state roadmap for achieving sector-by-sector carbon neutrality by 2045. One of
the main goals of the current Scoping Plan (compared to previous iterations) is to develop a longer
20-year pathway informed by robust science and centered around equity, as required by Governor
Newsomʼs Executive Order No. 16-22 (2022).
The California 2030 greenhouse gas targets, as defined in statute by AB 32, include all in-state
greenhouse gas emissions plus those associated with imported power. By moving to a framework of
carbon neutrality by 2045 as directed in The California Climate Crisis Act (AB 1279, 2022), this Scoping
Plan is expanded to include all sources and sinks, including natural and working lands, direct air
capture (DAC), and other biological and mechanical carbon sequestration processes that are included
in the Intergovernmental Panel on Climate Change Sixth Assessment Report (CARB, 2022d, Figure 1-5).
Four separate scenarios were considered in the Scoping Plan for each of the AB 32 Greenhouse Gas
Inventory and natural and working lands sectors. The final Scoping Plan scenario integrates actions
across the AB 32 Greenhouse Gas Inventory and natural and working lands by choosing one of four
alternative scenarios for each of these two broad sectors. All scenarios were compared to a reference
scenario that assumes no change beyond the existing policies already in place to achieve the 2030
target of reducing greenhouse gas emissions to 40 percent below 1990 levels, and no new actions in
the natural and working lands sector.
The stated aim of the final Scoping Plan scenario is to achieve the AB 1279 targets of achieving carbon
neutrality and of reducing greenhouse gas emissions to 85 percent below 1990 levels by 2045 through
a technologically feasible, cost-effective, and equity-focused path. The hydrogen requirements in the
Scoping Plan scenario can be summarized as follows:
76
● 45 percent of heavy-duty trucks, 20 percent of buses, and 15 percent of medium-duty vehicles
use hydrogen fuel cell electric technology by 2045;
76
Table 2-1 in Scoping Plan Report and E3ʼs Scoping Plan PATHWAYS Model Outputs
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● 20 percent of the aviation fuel demand in 2045 is met by hydrogen (fuel cells) and electricity
(batteries), split equally;
● 25 percent of ocean-going vessels use hydrogen fuel cell electric technology by 2045;
● 100 percent of passenger and freight locomotive sales are zero emission by 2030 and 2035
respectively, relying primarily on hydrogen fuel cell technology;
● Hydrogen is used for 25 percent of process heat by 2035 and 100 percent by 2045 in the
chemicals, pulp and paper, and allied products industries;
● Renewable (“green”) hydrogen is blended in gas pipelines, ramping up linearly from zero
percent energy in 2030 to seven percent energy (~20 percent by volume) in 2040 and remaining
constant at seven percent energy thereaer. Dedicated hydrogen pipelines are expected to be
constructed in the 2030s to serve certain industrial clusters.
The projected hydrogen energy demand by sector is shown in Figure 4.1 below.
Figure 4.1: Hydrogen Energy Requirements by Sector. Projected hydrogen fuel energy demand by
sector under the Scoping Plan. Hydrogen requirements are given in exajoules (EJ).
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Figure 4.2: Hydrogen Energy Requirements for the Transportation Sector. Projected hydrogen fuel
energy requirements for transportation sub-sectors under the Scoping Plan. Hydrogen requirements
are given in exajoules (EJ).
The transportation sector's projected hydrogen energy demand under the Scoping Plan is by far the
greatest: the 2045 hydrogen-fuel energy demand in the transportation sector is 10 times greater than
in the industrial sector, which, in turn, is 10 times greater than in any of the other sectors. The total
projected energy demand for hydrogen fuel in 2045 is 0.23 EJ (~1.9 million metric tons). This is roughly
1,700 times the current hydrogen supply in California. Nearly 90 percent of the hydrogen energy
demand (0.2 EJ) is projected to be in the transportation sector, nearly two thirds of which will come
from heavy-duty trucking (Figure 4.2).
4.2 Hydrogen Production Under the Scoping Plan
4.2.1 Renewables Capacity Expansion Required to Meet Scoping Plan Targets
The Scoping Plan proposes that roughly two-thirds of the total 2045 hydrogen supply is produced via
electrolysis. We estimate that this portion of the hydrogen supply would require about 23–26 GW of
additional “off-grid” solar capacity by 2045 that is otherwise not included in the Scoping Planʼs
projected renewable energy needs (CARB, 2022d, Appendix H). Figure 4.3 shows the projected
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cumulative renewable resource build-out under the Scoping Plan, inclusive of this dedicated off-grid
solar needed for hydrogen production by electrolysis.
Figure 4.3: Projected Renewable Resource Build Under the Scoping Plan Scenario. This graph
shows the additional dedicated off-grid solar needed to meet hydrogen production requirements with
electrolysis.
The rest of the hydrogen supply under the Scoping Plan would be produced through steam methane
reforming of biomethane and biomass gasification with carbon capture and sequestration. However,
there is a high degree of uncertainty around the climate, land use, and environmental justice impacts
of using biomass and biomethane for hydrogen production—see Sections 5.2 and 6.2 below for more
details. There is also uncertainty about the scalability of biomass and biomethane to produce this
quantity of hydrogen, as we discuss below.
4.2.2 Biofuel Capacity Expansion Required to Meet Scoping Plan Targets
The Scoping Plan proposes that between 36 and 73 percent of California's hydrogen supply will be
produced using biofuels, which would require significant growth in biomass and biogas supply and
hydrogen production capacity. This is first driven by steam methane reforming of biogas, which starts
at 68 percent of the hydrogen supply in 2023 then tapers off to zero by 2040. Hydrogen produced with
biomass begins in 2028, ramps up to 53 percent of supply in 2035, and decreases to 36 percent in 2045.
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The Scoping Plan relies on an in-state supply of biomass for gasification, paired with carbon
sequestration, to produce hydrogen. In contrast, hydrogen produced from biogas via steam methane
reforming is assumed to be imported from out of state. Sourcing for these potential biofuel supplies is
addressed in the following subsections.
4.2.2.1 Biomass Gasification with CCS
The Scoping Plan assumes that urban, agricultural, and forestry management residues (biomass that
currently exists mostly as a waste byproduct) will serve as a feedstock for hydrogen production. The
Scoping Plan estimates that California will have 5.3 and 8.1 million bone dry tons
77
per year of
agricultural residues, urban wood waste, and biomass from forest management activities available at
an appropriate cost for hydrogen production in 2030 and 2045, respectively (Figure 4.4). These
sources are expected to supplement biomass currently used for electricity generation. The Scoping
Plan estimates that biomass will supply the same amount of electricity in 2045 as in 2023, suggesting
this existing biomass supply is unavailable for diversion to biofuels.
77
A bone dry ton refers to one ton of biomass with zero percent moisture content.
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Figure 4.4: Estimated Mobilizable Biomass Feedstocks. The amount of agricultural residues, forest
residues (not including mill residues), and urban wood waste used for electricity generation at
biomass power plants in 2022. (Le) The amount of those same biomass feedstocks that the Scoping
Plan estimates will be available at a reasonable cost for new energy applications such as hydrogen
production in 2030 and 2045, respectively. (Middle and Right) The only change between the Scoping
Plan estimates for 2030 and 2045 is the amount of mobilizable urban wood waste.
The Scoping Plan indicates that biomass will supply 0.028 EJ of hydrogen in 2030 and 0.083 in 2045. If
5.3 million bone dry tons of biomass are available in 2030, as suggested in the Scoping Plan, California
should have enough biomass to produce this hydrogen in 2030 (Figure 4.5). However, our calculations
suggest that the 8.1 million bone dry tons available in 2045 may not be sufficient to generate the
hydrogen supplied from biomass gasification as outlined for that year. Even if gasification plants,
storage, and transport methods all operated at the highest ends of their respective efficiency ranges,
California may not reach this target without more biomass or significant efficiency improvements.
78
78
We suspect our estimate is lower than the Scoping Plan because the latter only accounted for the efficiency of
the biomass-to-hydrogen process (excluding related process efficiencies for compression, transport, and
storage) and used the heating value of wood fuel to represent the energy content of all biomass sources. In
contrast, our analysis included the aforementioned related processes and used the heating values of each
proposed fuel type, which are lower than wood, for the associated volume of fuel.
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Figure 4.5: Projected and Estimated Hydrogen Supply from Biomass Feedstocks. Higher and lower
estimates use the high and low ends of the hydrogen production efficiency estimates from Figure 3.2,
and were derived using the mobilizable biomass breakdowns provided by the Scoping Plan as seen in
Figure 4.4. Energy estimates were calculated using higher heating values for each biomass source
provided by the Pacific Northwest National Laboratoryʼs H2 Tools (2019) fuel heating calculator.
Lawrence Livermore National Laboratory (LLNL) suggests that California has extensive biomass
potential, estimating 28.8 and 32 million tons per year of urban, agricultural, and forestry
management residues in 2025 and 2045, respectively (Baker et al., 2020). However, it is not clear how
much of this biomass could actually be available for hydrogen, as LLNL does not account for existing
or preferential uses of these residues. LLNL also considers different economic constraints in its
estimation of available forest management residues compared to CARBʼs Scoping Plan. Electric power
plants in California accepted roughly 3.7 million tons of biomass residue in 2022, with roughly 893,000
tons from agriculture, 895,000 tons from urban waste, and 868,000 tons from forestry management
(the remaining 1.1 million tons were from mill residues, which are not included as an option in the
Scoping Plan) (CalRecycle, 2023a, 2024). With the exception of forestry residues, these numbers are
lower than previous years. CalRecycle partially attributes this decline to less expensive sources of
power, which makes it less profitable to use biomass to generate electricity (CalRecycle, 2023a). Taken
together, this suggests that while California may have extensive biomass resource potential, there may
not be a coherent system or market setup for collecting, transporting, and processing it all to generate
hydrogen without cannibalizing existing or preferential biomass uses. Given the uncertainties
surrounding the availability of biomass for hydrogen production, we explore what it would take to
instead provide all of Californiaʼs hydrogen supply with solar in Section 4.2.3.
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Additionally, unless biomass gasification facilities are located only where the appropriate biomass
feedstocks are abundant, making use of Californiaʼs existing biomass resources will require
transporting them throughout the state.
79
Transporting this biomass will have energy, emissions, and
cost implications. Policies to support the use of any of these waste streams would need to ensure they
do not create unintended negative outcomes, such as inadvertently increasing emissions and local
traffic pollution in already overburdened communities.
79
This large-scale truck transport of biomass would also have cost, air pollution, and CO
2
emissions implications.
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4.2.2.2 Steam Methane Reforming of Biomethane
Biomass gasification with CCS is projected to meet hydrogen demand only to the extent permitted by
feedstock availability. The remaining hydrogen demand in the Scoping Plan Scenario is met with a mix
of electrolysis production (as discussed above) and steam methane reformation (SMR) of biomethane
through 2040, aer which the SMR production path is retired. SMR hydrogen produced from biogas is
assumed to be imported and therefore not utilizing available in-state biogas feedstocks.
80
This includes non-forest branches and stumps, clean dimensional lumber, engineered wood, pallets/crates
from construction and demolition (C&D) sites, and other recyclable woods. It excludes treated/painted/stained
wood from C&D sites, which require special handling, and non-forest prunings and trimmings smaller than 4
inches in diameter.
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Biogas feedstocks considered in the Scoping Plan include landfills, wastewater treatment facilities,
landfill-diverted organic waste, and dairy manure digesters. This biogas is used to produce
biomethane, which is then used in the transportation sector for vehicles running on compressed
natural gas and in pipeline blending with natural gas. The use of biomethane in transportation is
projected to decrease over time, allowing its diversion to pipeline blending or as feedstock for
hydrogen production post-2025 (CARB, 2022d, Appendix H, Table H-13).
While the Scoping Plan states that biogas for hydrogen production will be imported, it does not state
where it would come from. In the box below, we outline the various in-state sources of biogas on the
contingency that a reliable import source cannot be secured.
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4.2.3 Alternatives to Expanding Biofuel Capacity
In principle, instead of relying on biofuels, all of the hydrogen supply required under the Scoping Plan
by 2045 could be produced by renewable electricity from solar (which the Scoping Plan currently
assumes will be off grid). Using the mean values of the hydrogen production efficiency ranges outlined
in Figure 3.1 (55 and 60 percent), our calculations indicate that relying solely on electrolysis and
off-grid solar to produce hydrogen would require roughly 41–45 GW of dedicated solar to be deployed
by 2045 (Figure 4.6). These calculations depend in part on how hydrogen is transported (e.g., by truck
or pipeline), whether it needs to be stored, and potential losses from leakage. Using the lower end of
this range (41 GW of dedicated solar) would imply that the total solar capacity in California in 2045
would need to be approximately 30 percent higher than projected solar under the Scoping Plan
scenario, and that the overall renewables capacity would have to be about 18 percent higher. To meet
this projected demand, the average annual build rates of renewables would have to double compared
to historic annual build rates (see Section 4.5 below).
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Figure 4.6: Projected 2045 Solar Capacity Required Under the Scoping Plan. Included is the
additional off-grid solar needed to meet the projected 2045 hydrogen production requirements with
electrolysis, as well as an electrolysis-only contingency scenario without the inclusion of biofuels to
meet hydrogen needs.
4.3 Direct Air Capture Energy Inputs in the Scoping Plan
Direct air capture (DAC) of CO
2
has received growing interest in recent years as ongoing carbon
emissions threaten to push atmospheric concentrations of CO
2
well beyond the levels required to
maintain temperature increases below 1.5˚C or even 2˚C. DAC fits into a broader set of carbon dioxide
removal (CDR) strategies aimed at curbing excess CO
2
in the atmosphere, including additional efforts
such as carbon-sequestering land management techniques. Many consider DAC a necessary approach
to mitigating the impacts of greenhouse gas (GHG) emissions and believe that even if GHG emissions
stopped today, CDR technologies will be valuable to draw down atmospheric CO
2
concentrations.
Others are concerned about both the potential for a moral hazard in employing DAC—namely, that it
will enable ongoing CO
2
emissions and the emissions of associated air pollutants. Additionally, as with
any nascent technology, the potential for unknown public health and safety risks associated with DAC
has raised concerns over the industryʼs growth. In-depth analysis of these issues is beyond the scope
of this report, but we do discuss them in further detail in Section 6.
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In this section we examine the energy inputs required for DAC. While this report focuses primarily on
hydrogen, we include DAC here because 1) the Scoping Plan estimates suggest that it will require a
significant amount of energy to power, and 2) because a siloed analysis of the energy requirements for
hydrogen alone may obscure the potential for competing demands for renewable energy to meet
economy-wide climate goals.
Executive Order B-55-18 (2018), from Governor Jerry Brown, set a goal of achieving California-wide
carbon neutrality by 2045 and net negative emissions thereaer. In 2022, AB 1279 made the 2045
carbon neutrality target binding. Importantly, the goal for emission reductions was set at only 85
percent below 1990 levels. As such, the remaining 15 percent of emissions could be directly captured
using techniques such as carbon capture and storage, or offset with DAC or other carbon removal
technologies. In its Scoping Plan, CARB relies on a mix of 1) carbon sequestration in natural and
working lands, 2) DAC, and 3) bioenergy with carbon capture and sequestration to remove 75 million
metric tons (MMT)of CO
2
e from the atmosphere per year by 2045. However, DAC is relied upon far more
than the other two strategies due to perceived challenges in scaling more sequestration in natural and
working lands. This level of removal (75 MMT CO
2
e per year) is equivalent to roughly 20 percent of
Californiaʼs total annual GHG emissions today, which totaled 369 MMT CO
2
e in 2020 (CARB, 2022e). The
Scoping Plan also relies on the capture of another 25 MMT of CO
2
e per year using carbon capture and
sequestration at facilities such as cement manufacturing and gas plants, which we discuss in Section
4.4.
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We attempted to create a rough estimate of the energy requirements for DAC in 2045, looking at a few
possible targets. Governor Gavin Newsom set a carbon removal target of 20 MMT CO
2
e by 2030 and 100
MMT CO
2
e by 2045. The Scoping Plan assumes that 64.4 MMT CO
2
e per year of carbon removal will
come from DAC in 2045. We note that if we were to assume that 15 percent of 1990 emissions must be
removed using DAC (assuming 85 percent direct emission reductions, as directed by law) this would
also lead to removal of an estimated 64 MMT CO
2
ein 2045 (CARB, n.d.). Therefore, we ask the question:
how much renewable energy would we need to remove 64 MMT CO
2
e per year from the atmosphere?
The Scoping Plan sets a DAC target of 2.26 MMT CO
2
in 2030, growing to 64.4 MMT CO
2
in 2045. Using
the values calculated above, we estimate this would use approximately 0.017 EJ of energy in 2030, and
0.48 EJ of energy in 2045. This represents an 18 percent total increase in energy consumption in 2045
compared to the existing sectoral end uses modeled in the Scoping Plan (currently modeled at 2.63
EJ). In other words, 15 percent of Californiaʼs entire energy demand by 2045 would have to go towards
removing Californiaʼs remaining GHG emissions directly from the atmosphere. The Scoping Plan does
not include the energy demand for DAC because it assumes all energy inputs will be “off grid.”
However, the Scoping Plan estimates California would need roughly 64 GW of off-grid solar for DAC in
2045. Assuming the energy demand for DAC is met with solar power at a 30 percent capacity factor, we
calculate DAC would require 2.6 GW of solar in 2030 and 74 GW of solar in 2045.
The calculation above excludes any energy storage (e.g., electric or thermal batteries) that might be
needed to smooth out the variable renewable energy inputs for use in DAC.
The energy demand for DAC could be met through multiple channels. Additionally, there may be
opportunities to use waste heat, solar thermal energy, or geothermal energy to support the high
thermal demand of many of the DAC technologies. A key question for future research is how much
waste heat, geothermal energy, or other resources could be dedicated to DAC to mitigate the need to
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build additional solar and wind resources. In addition, these technologies are likely to operate close to
all of the time, not just when wind or solar energy is generated, although this may depend on the
technology type. Finding alternative heat sources to support DAC would therefore also mitigate some
of the need for energy storage for wind and solar energy.
4.4 Carbon Capture and Storage Energy Inputs in the Scoping Plan
In addition to DAC, carbon capture and storage (CCS) at existing carbon-emitting facilities is widely
proposed as a mechanism to reduce carbon emissions and achieve carbon neutrality. The energy
inputs for CCS are typically lower per ton of CO
2
captured than for DAC because the emissions streams
have a higher concentration of CO
2
, making it easier to capture. However, CCS at existing facilities runs
the risk of continuing to propagate, or even increase, the emissions of other health-damaging air
pollutants from the facilities themselves and throughout the lifecycle of input fuels used. For example,
unless stringency of on-site emissions controls is increased, the adoption of CCS technologies at gas
power plants would likely increase the amount of natural gas burned in order to run CCS processes.
This, in turn, would run the risk of increasing on-site health-damaging air pollutant emissions. It would
also risk increasing the total upstream emissions of health-damaging air pollutants and lifecycle
greenhouse gases associated with the production, processing, and transport of natural gas because
total natural gas demand would increase (Michanowicz et al., 2021). The full impacts related to CCS are
beyond the scope of this report. Instead, we focus on the energy requirements of CCS to better
understand how these might combine with DAC and hydrogen production to estimate the total
amount of renewable energy that must be built by 2045.
The Scoping Plan targets the capture and storage of 25 MMT of CO
2
emissions by 2045 (above and
beyond DAC), including specifically for gas power plants (16.7 MMT), cement non-energy emissions
(4.2 MMMT), petroleum refining (2.8 MMT), and other industrial energy-use emissions (1.3 MMT). Of
note, the Scoping Plan assumes no CCS will occur at power plants until 2045, and all CCS will be added
at once (CARB, 2022f). This seems unlikely, since such a massive deployment of infrastructure would
necessarily require a ramp-up time to deploy, not only for the CCS systems at the plants themselves,
but also for transporting and storing the carbon. Depending on the application, CCS requires
approximately 2.8–4.1 MJ per metric ton of CO
2
, accounting for capture and compression but not
transportation and storage energy (Young et al., 2019; Dávila et al., 2023). We estimate this comes to
about 0.08 EJ of energy demand in 2045. It is unclear exactly how much of this energy demand is
reflected in the Scoping Plan. The Scoping Plan, which estimates a need for approximately 0.01 EJ of
energy to support CCS at refineries, is unclear about energy demand for other industrial CCS, and
states that the efficiency impacts of CCS at gas power plants are not included. Following similar
calculations as above, we estimate that the energy required to support CCS in 2045 would be the
equivalent of the generation from 12.2 GW of solar. To be conservative, we assume industrial CCS
energy demand is already included in CARBʼs modeled resource build-out, so we include an additional
8 GW of “solar” to support CCS at power plants in 2045. Of course, there is a reasonable probability
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that such energy demand would come from increased gas generation at these power plants, but we
include “solar for CCS” as a proxy for this energy demand.
4.5 Cumulative Energy Requirements of Hydrogen, DAC, and CCS
Adding the energy resource requirements for CCS, DAC, and hydrogen production to the proposed
renewable energy additions under the Scoping Plan enables us to see the true scale of renewable
energy deployment required to meet our greenhouse gas targets. We find that adding CCS, DAC, and
hydrogen doubles the renewable energy resources California needs to deploy by 2045, reaching nearly
250 GW of new solar and wind (and significant energy storage as well, although estimating these
values are beyond the scope of this report). This cumulative renewable energy resource build is shown
in Figure 4.7. This total declines slightly if we produce hydrogen in part from biofuels, as proposed in
the Scoping Plan. However, even if biofuels are the source of 36 percent of the hydrogen supply, the
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total renewable energy capacity required increases by three quarters compared to the renewables
currently projected as needed to replace existing economy-wide fossil fuel use.
Figure 4.7. Cumulative Renewable Energy Resource Capacity Added 2023–2045 Including CCS,
DAC, and Hydrogen Requirements.
We also consider a contingency scenario based on California's 2023 IEPR where natural gas used for
electricity production with CCS under the Scoping Plan is replaced by green hydrogen (CEC, 2023b).
The IEPR estimates that approximately 1.8 million metric tons of green hydrogen would be required to
provide the same amount of energy as the natural gas remaining for electricity generation in 2045. The
total solar capacity needed to generate the electricity for producing this hydrogen via electrolysis
(assuming a 30 percent capacity factor) is equivalent to 36 GW.
The total impact of adding DAC, CCS, and hydrogen (including the IEPR contingency) on renewables
build-out by 2045 compared to the Scoping Plan scenario is illustrated in Figure 4.8. Adding CCS, DAC,
and hydrogen nearly doubles the renewable energy resources needed by 2045, reaching nearly 300 GW
of solar and wind. Adding the IEPR contingency increases the renewable energy resource capacity
needed by 2045 to roughly 325 GW.
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Figure 4.8. Renewable Energy Resource Capacity in 2045, Including Hydrogen, CCS, DAC, and
IEPR Contingency Requirements.
To meet the Scoping Plan target, we estimate that about 5.5 GW of wind and solar, on average, would
have to be built every year between now and 2045. This exceeds the maximum historic simultaneous
annual build rates of wind, utility solar, and distributed solar combined, which is about 4.1 GW. The
sum of the maximum annual build rates California has achieved for each resource
individually—summing the maximums for the different years in which the most wind, utility solar, and
distributed solar were built, which did not occur at the same time—is 5.8 GW. So the Scoping Plan
average annual build is roughly equivalent to seeing the maximum annual deployment of utility solar,
the maximum annual deployment of distributed solar, and the maximum annual deployment of wind
every year for more than two decades. The average historic annual build over the last ten years has
only been 2.8 GW, meaning California would have to nearly double its average annual rate of
renewable energy construction. To meet the Scoping Plan targets when including both biomass and
solar to produce hydrogen, the solar+wind build rate increases to 6.6 GW a year. If expanding biomass
as a feedstock proves infeasible for hydrogen production, the annual build rate increases to 7.3 GW. If
we include energy for direct air capture and gas power plant CCS as well as hydrogen (assuming all the
energy comes from off-grid solar), then the annual build rate is nearly four times the historic average,
and more than 2.5 times the maximum historic annual growth in renewables. Adding the IEPR
contingency of replacing natural gas needed for electricity generation in 2045 with green hydrogen
further increases the annual build rate to 4.3 times the historic average, and roughly 3 times the
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maximum historic annual growth in renewables. These annual addition requirements are shown in
Figure 4.9.
Figure 4.9. Historic and Projected Annual Solar+Wind Capacity Build Rates.
It is worth noting that the Scoping Plan also assumes widespread adoption of energy efficiency,
including through electrification (e.g., electric cars are more efficient than gasoline-powered vehicles),
such that economy-wide energy consumption in their model is projected to drop to half of 2023 values
by 2045. If these efficiency savings are not achieved, the resource buildout would have to be even
larger. However, as described in Section 3, the direct use of electricity (or electricity and batteries) is
more efficient than using hydrogen in many cases. If we can reduce the number of resources powered
by hydrogen compared to electricity, the renewable resource build will partially decline. For example,
Makhijani and Hersbach (2024) estimated that heating homes with renewable electricity would use
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one fih of the electricity of heating a home with electrolytically-produced hydrogen. Even these
potential savings in the renewable resource build for hydrogen, however, will still be dwarfed by the
amount of renewable resources needed to meet DAC demand.
These estimates have numerous caveats. For example, if waste heat, or direct geothermal heat, can be
used to power DAC, it will reduce the amount of wind or solar that must be built. However, this
calculation does give a general idea of the magnitude of renewable energy buildout required when
incorporating CCS, DAC, and hydrogen to meet Californiaʼs 2045 carbon neutrality goals. We also did
not include any additional energy storage needs. As noted previously (and further discussed in
Section 5), there are going to be trade-offs for whether direct air capture and hydrogen production are
run in response to available wind and solar power—reducing their overall efficiency and increasing the
required facility capacity needed for each—or whether wind and solar are coupled with batteries. The
batteries would ensure a consistent renewable energy supply, but also require significant additional
upfront costs and materials. Future research should model the cost trade-offs between these two
approaches.
5. Climate Considerations
5.1 Greenhouse Gas Implications of Hydrogen Use
The production and use of hydrogen holds multiple implications for climate change. Currently, “green”
hydrogen deployment is being proposed across California in order to directly displace fossil fuels, and
therefore displace fossil fuel greenhouse gas emissions. However, the climate benefit of using “green”
hydrogen is not as straightforward as simply calculating the greenhouse gas reductions associated
with the displaced fossil fuels. This is due to a number of considerations, which fall into three broad
categories:
1) Indirect atmospheric climate impacts: Hydrogen is not a greenhouse gas, but it can
indirectly contribute to climate change when leaked into the atmosphere by affecting the
concentration of other greenhouse gases.
2) Production and infrastructure emissions: The energy source (e.g., biogas) used to produce
hydrogen can have a greenhouse gas impact, as can the build-out of associated infrastructure
(e.g., use of cement).
3) Deployment pathways and alternatives: The impacts (both positive and negative) of
hydrogen adoption depend on what energy source it is displacing and what alternatives might
exist for that end-use, as well as alternative applications of the energy used to produce the
hydrogen itself.
We discuss these categories in the California context below.
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5.2 Hydrogenʼs Indirect Climate Impacts
Hydrogen has the potential to leak throughout its production, transport, and use, similar to natural
gas (Penchev et al., 2022; Mejia et al., 2020; Alvarez et al., 2018). Once in the atmosphere, hydrogen is
relatively short-lived compared to greenhouse gases such as CO
2
and methane, with an atmospheric
lifetime of approximately two years (Novelli et al., 1999). In the atmosphere, hydrogen can affect
climate change by 1) increasing the atmospheric lifetime of methane, a potent greenhouse gas; 2)
increasing tropospheric ozone, which also acts as a greenhouse gas; 3) increasing stratospheric water
vapor, which can amplify the greenhouse effect; and 4) having additional aerosol production impacts,
which can positively and negatively affect climate change (Sand et al., 2023). The cumulative effect of
hydrogenʼs atmospheric impacts is still an area of active research. One recent meta-analysis suggested
a 100-year global warming potential (GWP) of 8 (±2) and another aggregation of models estimated 11.6
(±2.8) (Derwent, 2023; Sand et al., 2023). Over a 20-year period, this latter study estimates that
hydrogen has a GWP of 37.3 (±15.1)—namely, that a molecule of H
2
has a warming effect in the
atmosphere that is 37.3 times as powerful as CO
2
.
As a result of these indirect warming impacts, any leakage from hydrogen infrastructure could further
accelerate climate change. Hydrogen leakage rates are also highly uncertain, with limited in situ
measurements. Still, there are reasons to be concerned about the potential for hydrogen leaks to pose
climate risks. First, we know that existing natural gas infrastructure leaks methane (Alvarez et al.,
2018). Given that hydrogen is both the smallest molecule and must be transported at higher pressure,
it is likely that hydrogen would pose even higher leakage risks—and as noted previously, natural
gas-hydrogen blends have been found to leak at higher rates than pure natural gas (Penchev et al.,
2022). A recent literature review found full value chain estimates of hydrogen leakage ranged from
0.2-20 percent (Esquivel-Elizondo et al., 2023). Ocko et al. (2022) estimated that a 10 percent leakage
rate of “green” hydrogen (i.e., produced from renewables) replacing fossil fuels would actually increase
the climate impact by approximately 74 percent over the near term (0–5 years). More recently, Sun et
al. (2024) found that a 10 percent leakage rate would reduce the 20-year climate benefit of replacing
fossil fuels with “green” hydrogen by roughly 25 percent. Bertagni et al. (2022) found that “green”
hydrogen leakage rates over nine percent would increase atmospheric concentrations of methane,
even when the hydrogen is used to displace fossil fuels, and that lower leakage rates still undermine
the climate benefits of replacing fossil fuels with hydrogen. Moreover, all of these findings rely on the
assumption that the hydrogen in question is truly green—that is, that it has no lifecycle GHG emissions.
However, there are numerous approaches to defining green or clean hydrogen including, for example,
how the federal government defines “clean” for its 45V Hydrogen Tax Credit. How policymakers define
“green” hydrogen will have long-lasting implications for its climate impacts. These considerations are
detailed in the box at the end of this subsection.
The Scoping Plan includes hydrogen produced from both biofuels and renewables. The methane
leakage rates associated with proposed biofuel feedstocks are uncertain. However, it is likely that
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biogas would leak from production and transportation infrastructure much like natural gas—where
methane leakage is known to occur throughout the gas infrastructure. This could make biogas-based
hydrogen more similar to blue hydrogen (i.e., produced from natural gas with carbon capture and
sequestration) than green. Ocko et al. (2022) found that if three percent of methane is leaked during
blue hydrogen production and use
81
then switching from fossil fuels to blue hydrogen would not yield
any climate benefit for more than 25 years. Bertagni et al. (2022) estimate that a two percent methane
leakage rate would actually mean switching to blue hydrogen would increase overall methane
emissions.
Biofuels are sometimes considered climate neutral due to the fact that they oen rely on biomass
feedstocks that have absorbed CO
2
from the atmosphere. In the Scoping Plan, biomass gasification is
coupled with CCS with the goal of achieving negative carbon emissions. But these assumptions must
be made with caution: carbon re-released in the form of methane is significantly more potent that any
CO
2
removed from the atmosphere (by a factor of 83 on a 20-year timescale according to IPCC (2021)),
and biogas produced from non-natural sources such as waste streams cannot necessarily be
considered carbon-neutral.
It should also be noted that like all energy resources, any infrastructure associated with hydrogen will
have its own climate footprint. This footprint is due to the energy required to produce input materials
and direct greenhouse gas emissions from material production processes (e.g., from cement).
Estimating hydrogen's climate footprint falls beyond the scope of this report, but measures can be
taken (e.g., electrifying equipment; incorporating captured CO
2
into cement) to reduce some of these
potential impacts.
In spite of the uncertainties surrounding hydrogenʼs indirect climate impact, one general finding is
clear: hydrogen leakage should be minimized to ensure the climate benefits of any proposed hydrogen
use. Given the lack of data on hydrogen leakage, increased data collection and monitoring is required
before hydrogen adoption can be assumed to benefit Californiaʼs climate goals to the degree projected
in current climate plans. Similarly, before using biogas and biofuels as a feedstock for hydrogen
production, increased measurement and data collection of lifecycle greenhouse gas emissions is
needed. In particular, more information is needed to determine the climate footprint of methane
leakage from biogas production and use and to identify opportunities to mitigate any leaks.
81
This is only slightly higher than estimates by Alvarez (2018), which provides a leakage estimate of 2.3 percent of
natural gas gross withdrawals or 2.9 percent of natural gas by end use.
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5.3 Comparing Hydrogen Adoption Pathways and Alternatives
The potential climate impacts of hydrogen fuel adoption depend, in part, on the application proposed,
what the hydrogen is replacing, and what alternatives exist to meet that end use. In this section, we
focus on the climate impacts of a few specific applications for hydrogen.
Power Plants. Currently, the LADWP, among others, is proposing to replace natural gas used in power
plants with hydrogen. However, not all California decisionmakers assume hydrogen-based power
generation is a core component of decarbonization. The Scoping Plan proposes a build-out of
hydrogen-burning power plants for backup reliability purposes but reports nominal actual expected
hydrogen combustion at these plants. Burning “green” hydrogen (produced from wind or solar power)
instead of natural gas at a power plant ostensibly reduces direct CO
2
emissions by approximately 0.44
metric tons/MWh—the emission rate of natural gas combustion (EIA, 2023). When considering lifecycle
methane emissions, this amount rises to approximately 0.85 metric tons/MWh using a 20-year GWP
using emissions estimates from Alvarez (2018). However, these estimates do not consider alternative
approaches to meeting power demand. As we saw in Figure 3.4, burning “green” hydrogen in power
plants results in efficiency losses of 65 percent or more. The mix of viable alternatives that can be used
in lieu of burning hydrogen in power plants will depend, in part, on how the power generated by that
plant is expected to be used. Batteries, for example, may be able to replace peak power provided by
power plants, but may not be suited to replace all power plant operations. Hydrogen, in contrast, may
be more useful for long duration and seasonal storage applications, as discussed in Section
3.2.1—although hydrogen fuel cells may provide a reasonable alternative to hydrogen combustion.
However, in cases where multiple technologies can meet energy system requirements, their relative
energy input requirements should be evaluated.
For the case of peaking power plants, which generate power to meet multi-hour demand spikes (such
as on hot summer aernoons), the renewable energy used to produce hydrogen could instead be
paired with a lithium-ion battery. For this application, roundtrip losses would be less than 20 percent
and perhaps much lower—the specifications for a lithium iron phosphate battery (a type of lithium-ion
battery), for example, report losses under five percent (Mongird et al., 2020; Battery Space, n.d.). The
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resulting implication is that using renewable energy and batteries could replace more than three times
the amount of gas power generation compared to using “green” hydrogen in the power plant. This
means that hydrogen use in a power plant would only reduce greenhouse gas emissions by less than
one third compared to the renewable plus battery option.
For smoothing out multi-day and seasonal fluctuations in the availability of renewable energy
resources, long-duration energy storage technologies will be needed. Even if energy is stored in a
lower-efficiency long-duration battery, such as iron-air (estimated at ~45 percent efficient), the climate
benefit of the input electricity would be more than 40 percent higher compared to combusting
hydrogen in a power plant due to the higher potential for displacing natural gas. The indirect
atmospheric climate impacts of hydrogen leakage further reduce the relative climate benefit of
combusting hydrogen in the power sector. Hydrogen fuel cells have similar efficiency—and, therefore,
similar climate benefits—as long-duration batteries such as iron-air. But fuel cells' climate benefits can
be eroded if hydrogen leakage rates are high because of the indirect climate impacts of hydrogen in
the atmosphere (and to a smaller extent, due to energy loss).
Hydrogen Gas Pipeline Blending for Residential and Commercial Use. The Scoping Plan relies on
blending hydrogen into all existing gas pipelines at a level of 20 percent by volume by 2040, with the
goal of achieving climate benefits by displacing natural gas. At 20 percent by volume, hydrogen would
supply only about 6–7 percent of the energy in the gas mixture due to its lower energy density
compared to methane. Thus, the maximum climate benefit of this hydrogen blend is inherently no
more than a 6–7 percent reduction in greenhouse gas emissions (Bard et al., 2022). Similarly, Makhijani
and Hersbach (2024) found that this 20 percent hydrogen blend in gas would only reduce greenhouse
gas emissions by six percent. As before, this is an upper limit that could be further diminished by the
climate impact of hydrogen leakage. As noted previously, higher delivery pressures, leakage rates
through polymer pipes, and pipeline embrittlement risks may all contribute to increased leakage.
Additional research is required to fully characterize the climate impact of methane plus hydrogen
leakage in blended pipelines, as well as from end-use appliances themselves.
Hydrogen for Transportation. Hydrogen has been proposed for numerous transportation-related
applications across California, as shown in Figure 4.2. CARB has proposed that the largest supply
would be dedicated to running heavy-duty trucks on fuel cells. Using “green” hydrogen to replace
diesel in heavy duty trucks would eliminate on-road CO
2
(and, importantly, diesel particulate matter)
emissions, but may have some risk associated with the near-term climate impacts from any hydrogen
leakage (Makhijani and Hersbach, 2024). Sun et al. (2024) found that the climate benefits of using
hydrogen fuel cells in heavy-duty trucks is particularly sensitive to the hydrogen leakage rate,
compared to other applications.
The primary proposed alternative for decarbonizing trucking is to use battery-electric trucks.
Currently, hydrogen may be favorable in some situations, due to 1) longer ranges for fuel cell trucks
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(although battery-electric trucks are rapidly increasing their range); 2) faster fueling times; and 3) the
lighter weight of fuel cells compared to batteries, which is particularly important for applications
where local infrastructure has weight limitations (such as ports). However, as discussed in Section
3.2.3.2, battery electric trucks are more efficient than hydrogen fuel cell trucks because the latter have
a relative total efficiency of only around 30 percent when accounting for energy lost from the
production and transport of electrolytic hydrogen. All else being equal, the same amount of renewable
electricity could replace about 2.8 times as much gasoline, and therefore greenhouse gas emissions, if
used in battery-electric trucks than if converted to hydrogen and used in hydrogen fuel cell trucks.
6. Health and Safety Risks, Equity, and Unknowns
6.1 Hydrogen Combustion
Hydrogen gas itself is not a health-damaging air pollutant. However, its flammability poses safety
risks, and the combustion of hydrogen produces nitrogen oxides (NO
x
). Much like natural gas,
hydrogen gas is transported and stored under pressure and is flammable upon ignition. Like any fuel,
leaks of hydrogen can also cause safety concerns if it ignites. Compared to natural gas, hydrogen
ignites more easily, has a lower ignition energy, a lower flammability limit, and a wider flammability
range (DOE, n.d.-f). As noted previously, hydrogen is typically transported at higher pressures than
methane, and its presence in gas pipelines can cause embrittlement, increasing the risk of leakage as
pipelines age (Khan et al., 2021; Penchev et al., 2022). Californiaʼs historic experience with the natural
gas system—including the San Bruno pipeline explosion, which killed eight people, as well as the
unprecedented 2015 leak at the Aliso Canyon underground gas storage facility—informs a number of
safety-related needs to ensure safe hydrogen adoption (Pipeline Safety Trust, n.d.; California Public
Utilities Commission, n.d.). Essential safety measures include:
1) Dedicated funding for inspections and maintenance throughout the lifespan of any hydrogen
infrastructure.
2) Significantly better characterization of the risks of hydrogen use in existing gas infrastructure,
in dedicated hydrogen infrastructure, and both as a standalone fuel and when blended with
gas in a wide range of pipeline materials.
3) Planning and funding to safely prepare for the end-of-life of any infrastructure.
4) Appropriate ventilation and leak detection systems.
5) Comprehensive emergency management plans, including dedicated emergency response
messaging in multiple languages. For example, the Merrimack Valley gas explosions in 2018
highlighted the need for dedicated communication in commonly-spoken languages in the
affected region (Massachusetts Emergency Management Agency, 2020).
6) Tailored guidelines, standards, and engagement considerations for environmental justice
communities, including a consideration of whether risk contributes to cumulative burdens in
the surrounding community.
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In addition to the safety concerns associated with hydrogen systems, the combustion of hydrogen
raises public health concerns due to the production of nitrogen oxides (NO
x
). NO
2
, which is part of NO
x
along with NO, is considered a criteria air pollutant by the U.S. Environmental Protection Agency due
to its adverse effects on the respiratory system. It also reacts in the atmosphere to form both ozone
and particulate matter (PM
2.5
), which are associated with a wide range of cardiovascular and
respiratory health impacts. Children, the elderly, and those with underlying conditions are particularly
vulnerable to exposure to these air pollutants (U.S. Environmental Protection Agency, 2023).
Although NO
x
is not produced when hydrogen is used in fuel cells, it is a byproduct of hydrogen
combustion in applications such as power plants. The level of NO
x
emitted depends, in part, on the
emissions controls available in any given technology. Since hydrogen burns at higher temperatures
than natural gas, NO
x
production typically increases at higher temperatures. Actual NO
x
emission rates
depend on numerous additional factors, such as whether an appliance burning a natural gas-hydrogen
blend has sensors that enable it to automatically adjust the fuel-to-oxygen ratio (which also affects
carbon monoxide production) (Penchev et al., 2022). Although in some cases, NO
x
emissions per unit
energy of hydrogen burned may exceed those from natural gas, standard emission controls in
applications such as power plants can mitigate these increases (EPRI, 2023). As a result, replacing
natural gas with hydrogen fuel leads to increased or constant NO
x
emissions, with reductions unlikely
unless emission standards change. Large facilities with emissions controls, and appliances with
automatic sensors, may better maintain similar levels of NO
x
emissions than non-adaptive appliances,
such as stoves with a pre-set air excess ratio (Penchev et al., 2022). More research is needed to better
understand how these public health risks may vary with different natural gas-hydrogen fuel blends,
home appliance settings, and other factors.
6.1.1 Health and Equity Dimensions of Hydrogen Combustion at California Power
Plants
As noted above, numerous stakeholders have proposed repowering gas plants in California with
hydrogen, though these proposals vary widely. LADWP aims to burn hydrogen at all of its gas plants in
the Los Angeles Basin by 2035. In contrast, the CARB Scoping Plan (2022d) envisions hydrogen as an
emergency backup at combustion turbines, while ARCHES (n.d.) supports hydrogen use in the power
sector but sets no specific targets. Repowering gas plants with hydrogen across California raises a
range of public health and equity concerns. First, Californiaʼs gas plants are disproportionately located
in the stateʼs disadvantaged communities, as defined by the stateʼs environmental justice screening
tool CalEnviroScreen (OEHHA, 2023). Figure 6.1 shows a map of Californiaʼs gas plants overlaid with
CalEnviroScreen (le) alongside the distribution of plants by CalEnviroScreen score (right). This plot
shows that the stateʼs gas plants are disproportionately located in places with high cumulative public
health, environmental, and socioeconomic burdens. This trend holds when analyzing populations
living within a 6-mile radius of each plant as well, rather than just the census tract where the plant is
located (Krieger et al., 2016).
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Figure 6.1: California Gas Plants by Census Tract CalEnviroScreen Score Percentile. Map of
California gas plants by capacity (MW) overlaid with census tract CalEnviroScreen Score (le);
distribution of gas plants census tract CalEnviroScreen score (right). Adapted from Krieger (2020).
These findings raise a number of concerns for repowering these plants with hydrogen. The first
concern is that substituting hydrogen for natural gas at these plants, even if total emissions do not
increase, will continue to disproportionately impact some of the state's most vulnerable populations
and overburdened communities. Second, introducing hydrogen—a fuel with poorly characterized
safety risks such as those associated with building out hydrogen pipelines and storing hydrogen
on-site—may introduce new hazards to these communities. Finally, although gas plants are not the
primary contributors to poor air quality across the state, they are expected to continue meeting peak
electricity demand in the future. It is likely they will be used on hot summer days when air quality is
already poor, exacerbating acute air quality conditions. Some gas plants in the San Joaquin Valley
have been shown to have two-thirds of their operations occur on days when air pollution exceeds
federal air quality standards—worsening these conditions (Krieger et al., 2016). Without careful
planning, repowering these gas plants with hydrogen could perpetuate safety and public health risks
in the stateʼs most disadvantaged communities. One possible pathway to mitigate public health risks,
though not infrastructure safety risks, is to use fuel cells instead of hydrogen combustion at power
plants because fuel cells do not produce NO
x
as a byproduct.
6.1.2 Health and Equity Dimensions of Hydrogen Use in Transportation
Using hydrogen in the transportation sector will also have significant health and safety impacts. While
hydrogen combustion in transportation will release NO
x
, most proposals for the transportation sector
rely on hydrogen fuel cells rather than hydrogen combustion (unlike the power sector). Supporting
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hydrogen fuel cell adoption in the transportation sector, much as for the power sector, will likely help
reduce air pollutant emissions. Since the transportation sector in California is one of the primary
drivers of poor air quality, and because vehicle pollution disproportionately impacts the stateʼs
disadvantaged communities, pathways to reduce these emissions (e.g., by using hydrogen fuel cells in
heavy-duty trucks) are likely to reduce pollution levels in some of the stateʼs most environmentally
burdened areas (California Energy Commission, 2019; Reichmuth, 2019). This is particularly true for
replacing diesel in medium- and heavy-duty trucking but may be less true for using hydrogen in light
duty vehicles, which can use renewable electricity more efficiently through direct use in batteries (see
Section 3.2.3.1 above). If batteries become more economical at powering heavy-duty trucks in the
future, they would use renewables more efficiently than hydrogen fuel cells, therefore enabling any
new renewable energy builds to displace more fossil fuels and hence more health-damaging air
pollutants. However, any transition that increases hydrogen access along these transportation
corridors, must consider that any safety risks will likely also disproportionately affect these same
communities.
6.1.3 Health and Equity Dimensions of Hydrogen Combustion in Homes
Current concerns regarding hydrogen use in homes and businesses are primarily the result of
proposals to blend hydrogen in gas pipelines, as in CARBʼs Scoping Plan. Most existing proposals cap
the hydrogen fraction in pipelines at 20 percent by volume. As noted, even low fractions of hydrogen
can embrittle pipelines, potentially increasing gas leakage rates. This embrittlement, coupled with
hydrogen's wider flammability range compared to gas, may heighten safety risks. Burning
hydrogen-gas blends in home appliances may also increase indoor NO
x
emissions, depending on
appliance settings.
There is also a risk that wealthier homes and homeowners may more readily afford the switch to
electric appliances such as heat pumps and induction stoves, resulting in lower-income and renter
households being le behind on gas appliances and pipelines. The populations face a significant risk
of being stranded on the natural gas system, with gas rates expected to skyrocket due to the
diminishing number of customers le on the gas distribution system (Krieger et al., 2020). Blending
expensive hydrogen into pipelines will likely exacerbate the problem of rising gas distribution costs.
The same renter and lower-income households le covering those costs will also face the public health
and safety risks associated with hydrogen combustion in homes.
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82
For discussion of health-damaging air pollutant emissions throughout the oil and gas supply chain, see:
Michanowicz et al. (2021).
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6.2 Biofuel Feedstocks and Ammonia
The use of biofuels (e.g. biomass and biogas) as proposed by the Scoping Plan poses potential public
health and safety risks, particularly during the transport of feedstocks and production of hydrogen.
Using ammonia as a chemical carrier for hydrogen, discussed in Section 3, can also contribute to
health concerns. Both are discussed below.
6.2.1 Biomass
Biomass gasification for hydrogen production poses some public health risks, including increased
on-road emissions from biomass transport and potential pollution near generation facilities. Biomass
gasification plants require significant amounts of feedstock that must be transported to wherever
facilities are located. This will result in increased pollution along common trucking corridors and
potentially in the communities surrounding the gasification plants unless biomass feedstocks are
transported using zero-emission vehicles. The process of biomass gasification also has the potential to
increase pollution near the plant if emissions and effluent are not carefully controlled (Intelligent
Energy for Europe Programme, 2009). Dust, soot, tar, and particulate matter are all components of the
gas created during gasification, and the exhaust gas contains carbon monoxide, harmful organic
compounds such as benzene, NO
x
, and particulate matter (Intelligent Energy for Europe Programme,
2009). Existing models suggest that while biomass energy CCS (BECCS) facilities can help meet
Californiaʼs greenhouse gas targets and reduce statewide emissions of health-damaging air pollutants,
their use would still lead to localized increases in health-damaging pollutants, in particular PM
2.5
(Wang et al., 2020).
Both transport and gasification pollution risks could exacerbate existing inequities in certain regions.
For example, agricultural residue is primarily generated in the Central Valley, which is also host to at
least some usable CO
2
storage locations (Kim et al., 2022). This may incentivize companies to build
biomass gasification with CCS facilities in the region. However, the area is already beset by heavy air
pollution and is home to a significant portion of Californiaʼs disadvantaged communities (OEHHA,
2023; CARB Scoping Plan, 2022d, Figure 4-12). Siting these facilities in or near already overburdened
communities in the Central Valley has the potential to increase local pollution from biomass transport
to these facilities, further harming public health. In certain areas of the state, including in the Central
Valley, water availability could also become a key issue (as discussed at the end of Section 3).
6.2.2 Biogas
Landfills and the dairy-livestock industry are the two largest sources of methane emissions in
California (CARB, 2022d, Figure 4-12). As discussed in Section 5, Californiaʼs Low Carbon Fuel Standard
(LCFS) allows dairy/livestock operators and landfills to generate “carbon-negative” credits if they
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capture methane that would otherwise be emitted from their operations into the atmosphere and use
the captured biomethane to displace fossil-fuel combustion.
One major concern is that hydrogen producers who make hydrogen in the conventional way—via
steam methane reforming of natural gas—will be able to purchase carbon offsets from California dairy
farms and landfills and claim that the hydrogen they produce is green. This type of book-and-claim
accounting system fails to tackle the real-world impacts of SMR hydrogen production, including not
only the carbon emissions associated with it, but also the emissions of harmful air pollutants
impacting nearby communities, including NO
x
, particulate matter, and volatile organic compounds
(Sun et al., 2019).
Another concern about book-and-claim practices is that they may create perverse incentives for
livestock operators to manage their manure and operations in ways that increase their methane
emissions in order to earn more LCFS credits from capturing them. Incentivizing biogas production at
large concentrated animal feeding operations creates the additional issue of how to dispose of the vast
amounts of liquid residue that are oen loaded with antibiotics and other chemicals. Spreading the
residue on land requires long-distance transport, leading to increased on-road emissions along
trucking corridors.
6.2.3 Ammonia
While hydrogen can be converted to ammonia for transport and storage (as discussed in Section 3.1),
ammonia has the potential to contribute significantly to PM
2.5
and ozone pollution levels if used
directly, as it contributes to the formation of NO
x
emissions (Rathod et al., 2023; Ma et al., 2021;
Pedersen et al., 2023). This concern is alleviated if ammonia is converted back to hydrogen before use.
However, ammonia is still toxic, corrosive, and flammable, with a detectable smell at even low
atmospheric concentrations (DOE, n.d.-g). Although used safely in industrial and agricultural
applications, ammonia poses occupational health and safety risks during handling, such as damage to
the skin and lungs (Ma et al., 2019; IEA, 2019; National Institute for Occupational Safety and Health,
n.d.) Additionally, using ammonia as an energy-dense carrier for hydrogen may lead to ammonia odor
in neighborhoods where trucks carrying ammonia either sit in traffic or unload their product. It also
increases the risk of ammonia spills, which are particularly damaging to aquatic environments such as
lakes and rivers (DOE, n.d.-g). Finally, ammonia combustion can increase the emissions of nitrous
oxide (N
2
O), a powerful greenhouse gas (Pedersen et al., 2023).
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7. Case Study: Repowering Scattergood with Hydrogen
The Los Angeles Department of Water and Power
(LADWP) plans to repower its four in-basin gas plants
with hydrogen by 2035, starting with the Scattergood
Generating Station in 2029 (LADWP, 2022a).
Scattergood, built in the 1950s on the coastline next
to the Los Angeles International Airport, currently
uses sea water in a once-through cooling process.
Current regulations require phasing out this process
by the end of 2029 to mitigate harms to marine
wildlife (State Water Board, 2023b). LADWPʼs 2022
Strategic Long-Term Resource Plan (SLTRP) plans to
meet this target by replacing its once-through cooling
units at Scattergood with 688 MW of
hydrogen-burning combined cycle units. This plan
stands in contrast with the Scoping Plan, which only
relies on hydrogen combustion turbines for backup
in the power sector. LADWP aims to begin with a 30
percent hydrogen blend at Scattergood in 2029,
phasing up to 100 percent by 2035. However, limited
details are provided about LADWPʼs plan, and LADWP highlights numerous potential risks and
challenges, ranging from a lack of technology maturity to the absence of green hydrogen
infrastructure in Los Angeles. We outline these and some additional challenges and unknowns below,
as well as possible alternative strategies to meet Los Angelesʼs peak power demand.
Technology Maturity. Although many companies are currently working on creating hydrogen-burning
power plants, to our knowledge no commercial power plants exist that can run on 100 percent
hydrogen. Mitsubishi developed a commercial turbine that can run on 30 percent hydrogen, and says it
is aiming to complete “rig tests” on a turbine that can run on 100 percent hydrogen by early 2025,
although it is unclear when they hope to bring a commercial turbine to market (Mitsubishi Heavy
Industries Group, n.d.). GE Vernova (n.d.) has also commercialized a turbine that runs on a 50 percent
hydrogen blend. Other companies, such as Siemens, are developing similar technologies but they are
still under development and timelines are uncertain (Siemens Energy, n.d.). The LADWP plan for
Scattergood aims to rely on a “fast-ramping combined-cycle unit” to burn hydrogen that will begin
operation in 2029, but highlights “technology maturity” as a potential risk (LADWP, 2022a). The CEQA
analysis for the Scattergood Modernization Project proposes a 3.5-year project construction timeline
beginning in early 2026 (LADWP, 2023).
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A handful of demonstration projects have briefly blended hydrogen at existing plants, including up to
38 percent by volume (about 17 percent by energy) at a combined cycle gas plant in Alabama in 2023
and 44 percent by volume (21 percent by energy) at a simple cycle combustion turbine in New York
(Constellation Energy, 2023; EPRI, 2022). These demonstrations have highlighted a few concerns and
limitations. The demonstration at a Wärtsilä gas turbine in Michigan blended up to 25 percent hydrogen
into its fuel—but had to drop this to 17 percent to run at full load (Wärtsilä Corporation, 2023). It is
unclear if this limitation applied to the other demonstrations as well. The demonstration in New York
highlighted the need to greatly increase the pressure of the gas in order to increase the hydrogen
blend fraction, but there is a dearth of data on what the long-term impact might be of this increased
pressure on power plant equipment. Similarly, there is a lack of data on what the long-term impact of
hydrogen blending might be on power plant equipment, given the well-known problem of
hydrogen-induced embrittlement of steel pipelines.
It is also worth noting that the 44 percent blend of gas by volume at the New York turbine described
above is only equivalent to about 21 percent from an energy standpoint. As a result, blending
hydrogen into gas at relatively high volumes has a much lower impact on total CO
2
emissions than
burning pure hydrogen. The New York Brentwood demonstration project, for example, found that at a
35 percent hydrogen blend, CO
2
emissions were only reduced by 14 percent (EPRI, 2022). Applying data
from this same study to Scattergood suggests that a 30 percent by volume blend in 2029 is likely to
only reduce CO
2
emissions by about 12 percent.
Green Hydrogen Supply. To power Scattergood with green hydrogen, the power plant would need to
secure supply by 2029. There is general agreement that there is insufficient in-basin renewable energy
capacity to produce green hydrogen in Los Angeles itself, although potentially some curtailed
renewables could be dedicated to this purpose. LADWP released a Request for Information on green
hydrogen to address this and other challenges, and the CEQA analysis for the Scattergood
Modernization Project states that supply will be addressed in a future CEQA analysis (LADWP, 2023). It
is unclear exactly how much hydrogen is expected to be needed for Scattergood. The CEQA analysis
states that Scattergood will run at a “low capacity factor” compared to today (which is approximately
27 percent) but does not give a value. In contrast, the SLTRP shows a base case capacity factor of over
40 percent for Scattergood in 2030 (Case 1) (LADWP, 2022a).
We can use these values to estimate the amount of green hydrogen required to power Scattergood.
Since the conversion of Scattergood is staged, only 346 MW is expected to be hydrogen-ready by 2030.
At a 40 percent capacity factor, this means that the Scattergood hydrogen unit would need to produce
1.2 million MWh of electricity in 2030. At a 30 percent blend, hydrogen is responsible for only about 12
percent of the MWh generated. Given efficiency losses, this would still require approximately 300 MW
of solar (at 30 percent capacity factor) to produce sufficient hydrogen for the plant in 2030, and likely
more when the plant expands to 688 MW and is expected to burn 100 percent hydrogen in 2035
(although the capacity factor at this point is uncertain).
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All of this solar to produce green hydrogen would have to be produced somewhere. SoCalGasʼs
proposed Angeles Link suggests exploring locations such as the Central Valley, Mojave/Needles, and
Blythe as candidate locations—which are approximately 100+, 150+, and 225 miles from Scattergood,
respectively (SoCalGas, 2022b). SoCalGas has even considered pipeline routes extending to Utah.
However, there are no commercial green hydrogen production sites at these locations. Providing green
hydrogen to Scattergood via AngelesLink would therefore be contingent on the siting, permitting, and
construction of green hydrogen production facilities somewhere outside of the Basin, as well as a
hydrogen pipeline connecting those sites to Los Angeles, all within five years. If the latter is not built,
hydrogen could potentially be trucked in. Given a number of potential off-takers—including the Ports
of Los Angeles and Long Beach—this lack of extant supply raises concerns about supply reliability as
well as price volatility if there are production, delivery, or storage choke points.
Infrastructure. In addition to supply infrastructure, there is a lack of green hydrogen delivery and
storage infrastructure, also highlighted by the SLTRP. There are currently no green hydrogen
transmission and distribution pipelines nor storage facilities in Los Angeles. The SLTRP notes that:
“Space constraints preclude onsite production and storage of hydrogen at the generating stations” and
that there are significant space constraints in the surrounding communities. If appropriate siting is
found for such infrastructure, it frequently takes a significant amount of time to permit and build. For
example, LADWP notes the 12-year period it took to permit and build an 11.5-mile-long underground
electric transmission line in West Los Angeles. As noted above, if Angeles Link were to deliver hydrogen
to Los Angeles in time to supply Scattergood, it would likely need to build more than 100 miles of
pipeline—and perhaps more than 200 miles—in less than five years. In addition, local transmission,
storage, and subsequent distribution infrastructure would likely be necessary. The SLTRP states that a
“continuous” hydrogen supply is necessary to deliver hydrogen to LADWP power plants since “on-site
storage is impractical.” It is unclear if a lack of pipeline capacity could be solved with trucking in
hydrogen in the near term (LADWP, 2022a).
One of the additional risks associated with building out this infrastructure is the risk of stranded
assets. For example, if hydrogen trucking and delivery infrastructure is needed to deliver fuel by 2029
but is phased out by 2035 if a pipeline is built, the associated investment might not be fully recovered.
Moreover, as noted above, the predicted amount of hydrogen needed is wildly variable. Scattergood
might operate at capacity factors of over 40 percent according to the SLTRP (LADWP, 2022a). Across all
Los Angeles plants, without transmission upgrades, the SLTRP projects an average capacity factor of 18
percent between 2028–2045. And with transmission upgrades, that average drops to two percent,
because larger transmission capacity would enable more electricity imports into the Los Angeles Basin
and displace the need for local power generation. This calculation implies both a wide range of
potential outcomes, as well as the potential for a significant drop in demand over this time frame.
Building out the infrastructure to deliver sufficient hydrogen to power Scattergood at a 40 percent
capacity factor, with the potential for this to rapidly drop to only two percent, suggests that these
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infrastructure investments might quickly become stranded assets as well. These are not purely
hypothetical concerns. As noted previously, Shell Global, which had begun building out passenger
vehicle hydrogen fueling infrastructure across California, canceled 48 planned stations in 2023, and
shut down its remaining seven operational light-duty vehicle (LDV) fueling stations in early 2024 due to
supply and market barriers—such as the very low adoption rates of hydrogen LDVs (Martin, 2024).
Successfully building hydrogen production, transmission, and storage infrastructure will also require
significant ongoing monitoring for safety risks, in particular due to its immaturity as a technology.
Insufficient inspections and upkeep of natural gas infrastructure has contributed to significant events
in the past, such as the Aliso Canyon gas leak in 2015. Near-term hydrogen maintenance and
inspections will likely require even more intensive attention due to the current lack of long-term
operational and degradation data for hydrogen infrastructure. This need will likely require significant
additional workforce training and development to ensure there are enough workers to conduct
inspections and maintain infrastructure. In addition, safety and emergency management plans will
require ensuring communication about risks, and any incident messaging, is provided in numerous
languages and across a broad range of platforms in order to adequately reach Los Angelesʼ diverse
population.
Air Pollutant Emissions. Replacing natural gas with hydrogen in power plants has the potential to
provide some broad natural gas system air pollutant benefits, including the reduction of upstream
health-damaging air pollutant emissions associated with gas production, processing, and
transmission infrastructure (Michanowicz, 2021). However, co-firing hydrogen at the New York
demonstration project described above led to an increase in NO
x
emissions at the stack. These can be
mitigated by air pollution control technology, which will be required under air quality regulations, but
there is no reason to believe that NO
x
emissions per MWh of generation will be any lower than what is
currently permitted for gas. Moreover, if the capacity factor of Scattergood increases from 27 percent
to 40 percent, these emissions will likely go up. There is limited data on NO
x
emissions during start-up
and shut-down of hydrogen gas turbines—partly due to the lack of maturity of the technology—but
NO
x
emissions do increase for gas turbines during start-up and shut-down operations. From
2010–2018, Scattergood ran an average of 610 hours every time it was turned on, suggesting it was
running in relative steady state rather than having frequent start-ups (Krieger, 2020). However, the
proposed Scattergood turbine is fast ramping, suggesting that LADWP plans to operate it to flexibly
respond to load, rather than at steady state, and therefore suggesting a risk that its operation might
lead to an increase in emissions.
Power plants in Los Angeles currently contribute a relatively low fraction of total NO
x
emissions in the
Basin, but they do tend to operate simultaneously on hot summer days (when ozone is oen high) to
meet peak cooling demand, suggesting an ongoing risk that these plants will continue to cumulatively
exacerbate air quality on some of the worst air quality days. In 2018, for example, Scattergood only
operated at a capacity factor of 17 percent, but 48 percent of its total generation occurred on days
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exceeding the EPAʼs National Ambient Air Quality Standards (NAAQS) for ozone, and six percent on
days exceeding NAAQS standards for particulate matter.
There are also some concerns related to site-level construction emissions at the Scattergood facility.
The CEQA analysis suggests that during construction, up to 40 off-site trucks may serve the site per
day, risking an increase in diesel pollutant emissions (LADWP, 2023). The census tract Scattergood is
located in has insufficient population to have a full CalEnviroScreen 4.0 score, but it is ranked as more
polluted than 97 percent of census tract in California (OEHHA, 2023).
Alternatives. While a full analysis of alternatives to the repowering Scattergood with hydrogen is
beyond the scope of this report, we will note a few technologies that were not fully considered in the
SLTRP. For example, LADWP did not fully consider long-duration energy storage technologies, which
are also under development but are beginning to build real-world demonstration projects (CEC,
2023c). One study has suggested that all of Californiaʼs gas plants could be replaced with long-duration
energy storage (Go et al., 2023). While these projects will certainly face scale and deployment
challenges, much like hydrogen, they should be included in the potential resource deployment mix as
candidates for helping reach peak demand. In addition, LADWP did not fully explore the potential for
demand management—in particular, utilizing the rapidly electrifying vehicle fleet—to mitigate peak
demand. Finally, the state is rapidly moving forward with offshore wind, including sites off the coast of
Southern California, which tend to have the highest wind speeds on summer evenings, which aligns
relatively well with LADWPʼs identified time of projected peak demand (Wang et al., 2019; Musial et al.,
2016; LADWP, 2022a). It would be valuable to model the impact of integrating this offshore wind supply
into LADWPʼs modeling to identify its impacts on LADWPʼs identified need for in-basin hydrogen
combustion.
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8. Key Findings, Policy Considerations, and Recommendations
We discuss the key findings from our report in Section 8.1 below. These findings reflect significant
unknowns and uncertainties about the benefits and impacts of green hydrogen deployment to achieve
Californiaʼs climate targets, due in part to the nascent nature of the industry alongside inconsistent
policy goals from decision-makers across the state. Therefore, in Section 8.2, we highlight important
policy considerations and guiding questions that can help inform hydrogen-related decision-making in
the context of these unknowns. Finally, in Section 8.3, we provide recommendations and suggest
future research areas that can help inform decision-making while California continues to develop
decarbonization strategies.
8.1 Key Findings
Decision-Makers in California are Not Aligned on Hydrogen. Californiaʼs agencies, utilities, and
other decision-makers have limited alignment on the role of hydrogen in a decarbonized California.
Across the state, decision-makers have set a wide range of targets for hydrogen deployment, with
different primary end-uses, timelines, and definitions of what makes hydrogen “clean” or “green.” This
lack of alignment is illustrated in variation in hydrogen goals proposed by CARB, ARCHES, and LADWP,
as well as scenarios explored in the 2023 IEPR from the CEC between numerous local and state
planners. Unless addressed, these divergent proposals may encounter energy security and supply
challenges, or risk undermining cross-California decarbonization efforts.
Existing Hydrogen Plans Lack Detail. Many of the proposed “green” hydrogen plans lack sufficient
detail, including locations and methods of hydrogen production, energy sources for hydrogen
production (whether in-state or imported energy, grid electricity, or off-grid renewables), delivery
methods, and the impacts of these factors on the ability to meet other energy demands. As a result, it
is impossible to determine the total cost of the proposed build-out of hydrogen infrastructure and the
appropriate safety measures. This lack of detail raises questions about the feasibility of many
hydrogen deployment proposals and inhibits alignment between stakeholders. These unknowns also
make it difficult to fully characterize the potential system-level impacts of hydrogen use, including
equity, public health, environmental, climate, and economic concerns.
California Will Need to Rapidly Accelerate Hydrogen Infrastructure Deployment to Meet Proposed
Goals. Achieving proposed hydrogen deployment goals across California will require the rapid
deployment of associated infrastructure, including of technology that is not yet commercial. For
example, LADWP is aiming to begin to repower its gas plants with hydrogen in 2029, leaving five years
to identify a hydrogen supply, build a means of hydrogen transport and storage, and install and
operate hydrogen combustion technology that is not yet on the market. The proposed rapid adoption
of emerging technologies without adequate operational, performance, safety, and longevity data
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suggests the need for planning and funding to support accompanying monitoring and safety measures
over the lifespan of these projects.
Renewable Energy Deployments Will Need to Increase Multifold to Meet Hydrogen and Direct Air
Capture Goals. To meet the energy demands for hydrogen production and direct air capture as laid
out in the Scoping Plan (CARB, 2022d), renewable energy (e.g., wind and solar) must nearly quadruple
the historic annual average build rate, and more than double the maximum annual historic build rate
every year from now through 2045. These estimates may change as direct air capture technology
matures and energy requirements become clearer. But this compounding effect on renewable energy
builds highlights the need to look at deployment goals comprehensively and to assess their
implications at an economy-wide level, rather than on individual technologies or sectoral
deployments.
Green Hydrogen Production Inefficiencies Make Direct Electricity Use More Suitable for Many
Applications. Electrolytic hydrogen production is roughly 60–70 percent efficient, depending on the
technology and associated processes, and hydrogen produced via biomass gasification is roughly
40–70 percent efficient depending on the moisture content of the biomass. Certain applications, such
as burning hydrogen in power plants to generate electricity, compound inefficiencies, resulting in
roundtrip efficiencies of less than 30 percent. As a result, using hydrogen in certain applications, such
as electricity production, home heating, or in light duty vehicles, would require a significantly larger
buildout of renewable energy than if these renewables could be used directly or stored in batteries.
However, for some applications, such as long-duration energy storage where lithium-ion batteries are
considered too expensive at present, hydrogen may still be an appropriate option.
California May Benefit from Prioritizing Certain Hydrogen End-Uses Over Others. Given
uncertainties in the ability to rapidly scale hydrogen production and delivery infrastructure, and viable
alternatives for many proposed hydrogen end uses, it may make sense to prioritize certain
hard-to-electrify end-uses over others. For example, prioritizing the use of hydrogen for certain
high-heat applications that typically require fossil fuels, rather than blending hydrogen in gas
pipelines to decarbonize residential heating, which could be done via electrification using efficient
heat pumps. Given unknown future costs of both hydrogen and other decarbonization infrastructure
(e.g., long duration energy storage), such prioritization will likely have to be frequently revisited.
Hydrogen Buildout as Planned Poses Stranded Asset Risks. Unknown future demand for
hydrogen—in particular for end uses that have viable or proposed alternative technologies—presents
a risk that the build-out of hydrogen production and delivery infrastructure may become stranded
assets, as has already been seen for light duty vehicle fueling stations in California. Prioritizing certain
hydrogen end uses and focusing initial production and delivery infrastructure on only the
hardest-to-abate sectors may help manage such risks. Aligning, clarifying, and adding detail to these
plans may also help hydrogen stakeholders minimize the risk of stranded assets.
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Hydrogen Pipeline Blending Presents Safety Risks and Limited Climate Benefits. Proposed
blending of hydrogen in existing gas pipelines presents safety risks due to hydrogen embrittlement of
pipelines, hydrogen leakage, and other factors. Proposed hydrogen blending levels—up to
approximately 20 percent by volume—result in a fuel blend that is only seven percent hydrogen on an
energy basis because hydrogen is less dense, meaning that the maximum climate benefit of such a
blend would be at most a seven percent reduction in greenhouse gas emissions. This benefit would be
further eroded if the hydrogen production pathway has any associated greenhouse gas emissions,
such as those associated with hydrogen leaks or using biogas as a feedstock.
Hydrogen Use Poses Climate Risks. Hydrogen has indirect climate warming effects in part because its
presence in the atmosphere affects atmospheric concentrations of methane, ozone, and water vapor,
resulting in an estimated global warming potential of roughly 37 times that of CO
2
over 20 years and
8–12 times that of CO
2
over 100 years. Any hydrogen leakage therefore undermines the benefit of fuel
switching to hydrogen. Studies of hydrogen leakage rates are preliminary and have not been studied
across all proposed applications, making it difficult to accurately characterize the scale of leakage
across proposed hydrogen deployment scenarios, but they have demonstrated that leakage does
occur. Hydrogen produced from biogas is likely to have increased climate impacts due to the risk of
methane leakage from the biogas supply chain, although these values are also poorly characterized.
Additionally, using biomass to produce hydrogen requires the transport of that feedstock to hydrogen
production facilities. Unless transport methods are zero-carbon (e.g., using zero-emission vehicles),
this biomass transport could have impacts as well.
Hydrogen Combustion Perpetuates Public Health Impacts from NO
x
. Hydrogen combustion
produces NO
x
and may even increase NO
x
emissions compared to gas combustion unless mitigation
strategies are put in place. Scrubbers may be used at power plants to limit NO
x
emissions to permitted
levels, but even permitted levels can continue to have public health impacts. Studies on NO
x
emissions
from hydrogen use in commercial and residential appliances show mixed results but appear to
indicate these emissions either stay constant or increase, meaning they would contribute to poor
indoor air quality and associated public health impacts much like natural gas combustion in homes.
Equity Impacts from Hydrogen Use Vary by Application. The use of hydrogen holds equity
implications, although these vary significantly by application. For example, expanding hydrogen
combustion at existing gas power plants risks perpetuating NO
x
emissions in the stateʼs disadvantaged
communities. Similarly, risks may be posed by industrial facility use of hydrogen combustion. Use of
hydrogen fuel cells in trucks, which also disproportionately release diesel particulate matter into
disadvantaged communities, is likely to help reduce pollution burdens. The build-out of hydrogen
fueling infrastructure along busy transportation corridors will require significant community input,
safety measures, emergency response preparations and messaging in multiple languages, and other
efforts to ensure that safety risks are mitigated in places that have historically faced numerous
environmental health burdens due to fossil fuel transportation. The full lifecycle of hydrogen
94 | Green Hydrogen Proposals Across California | PSE Healthy Energy
production and use should be evaluated when addressing potential equity impacts, in particular
because some proposed feedstocks—such as biomass and biogas—have known potential
environmental and public health risks, and production-related impacts on exposed populations
should be considered.
The System-Level Impacts of Hydrogen Pathways and Possible Alternatives Are Unclear. The
system-level impacts of proposed hydrogen use are difficult to evaluate given the lack of detail in
hydrogen proposals, but these system-level impacts are important for fully understanding the benefits
and impacts of hydrogen use for various applications. For example, “green” hydrogen fuel cells might
have a direct climate benefit if used to replace gas in a power plant. However, if that power could have
been replaced with renewable energy stored in a lithium-ion battery, then using hydrogen would have
incurred a significant opportunity cost—the hydrogen pathway requires nearly twice as much wind or
solar energy as the battery pathway, and those surplus renewables could have been used to displace
fossil fuels elsewhere. Understanding these indirect impacts and opportunity costs requires an
expansion of economy-wide decarbonization modeling to better incorporate the renewable energy
inputs for hydrogen production.
8.2 Key Policy Considerations and Guiding Questions to Address Unknowns
Our findings highlight numerous policy and regulatory considerations that state and local planning
processes have not fully addressed. The largest of these include lack of detail in plans and lack of
alignment between planners. A number of assumptions and requirements regarding the scale of
hydrogen production and use in California may prove to be unrealistic and/or not fully supported by
science. These gaps pose multiple risks in the rollout of hydrogen across the state, including that
multiple competing demands for hydrogen might undermine the ability of any individual organization
or agency to achieve its hydrogen goals and associated climate targets; that lack of coordination may
result in inefficient infrastructure investments and potential stranded assets; and that lack of
coordination and prioritization around the many needs for renewable electricity, including direct use,
hydrogen production, CCS, and direct air capture, may lead to inefficient build-out of energy
resources. Moreover, these competing plans may have indirect system-level impacts (e.g., on
greenhouse gas emissions, workforce needs, etc.) that are impossible to model and address without
coordinated planning.
Moving forward with plans without clear certainty on details also leaves significant unknowns about
the public health, equity, and climate implications of hydrogen infrastructure buildout—and inhibits
the ability to address or mitigate any unexpected impacts. In addition, many decarbonization planning
goals are reliant on being able to deploy renewable energy and hydrogen rapidly and at previously
unachieved scales, and there is limited contingency planning for what to do if these goals are not
achieved. Below, we highlight: 1) Key questions that will help better characterize the impacts of
95 | Green Hydrogen Proposals Across California | PSE Healthy Energy
hydrogen policies and projects, 2) Important unknowns and contingencies that need to be addressed
before moving forward, and 3) Additional policy considerations.
Key Questions to Better Characterize the Impacts of Hydrogen Policy and Deployment Proposals
● Alternatives. What alternatives exist for any proposed application for hydrogen? When
evaluating the impacts and benefits of a project, how do you define a counterfactual scenario?
Example: How do the cost, infrastructure, public health, climate, equity, and environmental
impacts of burning hydrogen in power plants compare to meeting flexible power demand with
renewable energy and batteries?
● Lifecycle Impacts. What are the lifecycle energy, water, and climate implications for any
proposal, and how does this compare to alternatives? Example: What are the lifecycle
greenhouse gas impacts of using biogas-derived hydrogen? How much water is needed, and is
this available in the places where—and the seasons when—biogas-derived hydrogen is expected
to be produced?
● System Impacts. How does any proposal affect the energy system as a whole? How do these
impacts change when you simultaneously consider multiple hydrogen proposals or other
goals for Californiaʼs energy system? Example: How does hydrogen use in heavy duty
transportation affect the renewable energy build rate and the required build-out of hydrogen
pipeline and storage infrastructure? How might this build rate for renewables impact the ability
to meet direct air capture goals? How does the capital cost expenditure on hydrogen projects
affect the capital available for other decarbonization efforts?
● Stranded Infrastructure Risk. What is the likelihood an investment, such as a hydrogen
production facility, will be needed in the future? What happens and who pays for it if it is not
needed? If an investment is not made, will it turn an associated investment, such as a
hydrogen storage facility, into a stranded asset? Example: Who covers the costs if a pipeline is
built and there are insufficient off-takers?
● Safety and Public Health. What do we know and not know about the safety and public health
risks of hydrogen production, transportation, and use for various applications? Who is most
likely to be affected by an adverse outcome? Example: If hydrogen blended into gas pipelines
accelerates pipeline degradation at a faster rate than expected, who lives nearby and faces the
greatest associated safety risks if there are high levels of leakage or an explosion? What are the
in-home public health risks of hydrogen combustion?
● Investments in Priority Communities. How should hydrogen investments be targeted
towards—or not targeted towards—disadvantaged communities (as defined by SB 535), or
other priority communities? What counts as a “benefit” to a disadvantaged community (rather
than just being located in a disadvantaged community) and what could be considered a “risk”
for that community? Who gets to determine what community benefits are or how they should
be defined? Example: Should policy incentivize hydrogen infrastructure in specific communities?
96 | Green Hydrogen Proposals Across California | PSE Healthy Energy
And if it is, how can policymakers ensure the community is receiving tangible benefits such as
long term, local job creation for existing members of the community?
● Competing Demands. What are the competing demands for hydrogen, particularly at early
stages of deployment? How do these change over time? If hydrogen is directed towards one
application, would that preclude its use elsewhere? What are the opportunity costs of any
given hydrogen use case? What are the energy security implications of these competing
demands? Example: If green hydrogen is used at power plants in Los Angeles, will this limit the
quantity or reliability of the hydrogen supply available to the Port of Los Angeles to decarbonize
its operations?
● Sensitivity to Assumptions. Given the many unknowns and uncertainties in hydrogen
infrastructure and deployment, what is the sensitivity of project success to input assumptions?
Example: See next subsection.
Unexplored Sensitivity Scenarios and Implications for Contingencies
● Definition Scenarios. Policymakers are still considering different definitions for green (or
clean) hydrogen. What is the sensitivity of lifecycle climate benefits of hydrogen adoption to
the definition of green hydrogen? How much does adherence to the three pillars (co-location,
additionality, and hourly time matching) affect climate benefits at a system level?
● Demand Scenarios. CARBʼs Scoping Plan includes a reduction of vehicle miles traveled per
capita to 30 percent below 2019 levels by 2045 and California is targeting widespread
electrification. What are the implications for hydrogen demand if reductions in vehicle miles
traveled are or are not achieved? What is the magnitude and location of power sector impacts
if electrolytic hydrogen blended into gas pipelines is replaced with electrification?
● Technology, Infrastructure, and Scaling Scenarios. If proposed technologies do not mature
as quickly as expected (e.g., hydrogen combustion turbines; direct air capture) or if renewable
energy resources cannot scale as quickly as expected, what are the implications for meeting
climate targets? If supporting infrastructure is not built quickly enough, what are the climate,
cost, and energy security implications of switching end-use applications to hydrogen? (E.g., if
Angeles Link is not built quickly, what are the implications for price volatility at Scattergood?)
Additionally, what is the sensitivity of the climate benefit of various hydrogen production and
use pathways to different levels of fuel leakage (e.g., biogas, hydrogen)?
● Biomass Scenarios. Biomass inputs may prove hard to scale (either through state-based
programs or imports from out of state) and the location of hydrogen production facilities is still
an open question. If biomass inputs are lower than anticipated, what are the implications for
renewable energy buildout to support hydrogen production? What are the implications of
incentivizing biofuels, particularly biomethane, for hydrogen production to increase their
97 | Green Hydrogen Proposals Across California | PSE Healthy Energy
availability?
83
How sensitive are energy, cost, and environmental health outcomes to whether
small hydrogen production facilities are co-located with biomass source locations, or if
biomass is transported to larger centralized production facilities?
8.3 Recommendations
● Develop Stringent, Consistent Definitions for “Green” or “Clean” Hydrogen. Adopting the
three pillars of green hydrogen production—namely, additionality, hourly-matching, and
co-location of renewable energy generation with hydrogen production—will help minimize
unintended climate and system impacts of green hydrogen production. This will also require a
consistent definition of “renewable” energy specifically addressing how biofuels are
categorized.
● Better Characterize Hydrogen Leakage Rates Before Investing in Infrastructure. Given the
huge uncertainty in hydrogen leakage rates, it is important to improve our understanding of
these leaks, as well as develop comprehensive processes to monitor for and mitigate them
before greatly expanding hydrogen infrastructure. Comprehensive and ongoing monitoring at
pilot projects may help improve this understanding.
● Improve Interagency Coordination on Hydrogen Planning. Investing in significant hydrogen
infrastructure expansion, or over-relying on hydrogen to meet climate targets, without proper
coordination between California agencies, utilities, and other decision-makers increases the
risk of failure.
● Build Safety into Hydrogen Infrastructure Development. Ensure sufficient funding is
allocated to maintain and monitor hydrogen infrastructure and mitigate safety risks in the
near- and long-term. This includes funding for equity-focused considerations such as
developing emergency preparedness and response communication in multiple languages.
Novel technologies (including hydrogen, DAC, and CCS) should require an additional level of
stringency—including requirements related to community input, community benefits, and
extra protections for historically disinvested and vulnerable populations—as well as data
collection of the long-term operation and risks associated with each technology.
● Consider System and Lifecycle Implications in Policy Planning. Any cost-benefit or other
analysis of the impact of hydrogen infrastructure adoption should consider lifecycle and
system-level impacts (e.g., cost, equity, climate, public health) in addition to
application-specific benefits.
● Evaluate Alternative Technologies and Deployment Scenarios. Ensure that planning efforts
fully evaluate alternative technologies for various end uses, alternative deployment scenarios,
83
California is not currently considering purpose-grown biofuels for hydrogen production. This is good, as
biofuel-based hydrogen pathways that use purpose-grown biofuels are emissions- and water-intensive.
98 | Green Hydrogen Proposals Across California | PSE Healthy Energy
and sensitivity to assumptions regarding future costs and technology maturities before
investing in hydrogen projects.
● Ensure There are Strict Emissions Controls and Enforcement for Hydrogen Production
and its Input Fuels (e.g., Biofuels). Ensuring both biofuel-based hydrogen production and
biogas production facilities have strict and enforced emissions limits in place—and that facility
siting minimizes impacts on environmentally overburdened communities and sensitive
receptors (e.g., schools) and is conducted with meaningful community input and
engagement—will help reduce unintended emissions from this hydrogen production pathway.
● Avoid Hydrogen Pipeline Blending. The minimal potential climate benefits of hydrogen
pipeline blending do not justify the unknown safety, cost, and public health risks associated
with blending hydrogen in existing gas pipelines.
● Prevent Book-and-Claim Schemes. Ensure that hydrogen producers who make hydrogen in
the conventional way—via steam methane reforming of natural gas—are not eligible to receive
incentives or subsidies for green hydrogen when they purchase biomethane “carbon-negative”
credits.
Additional hydrogen-focused research, as well as an exploration of how its potential adoption
interacts with other proposed climate mitigation strategies, will help drive better-informed
decision-making about hydrogen deployment strategies and trade-offs. Although there is preliminary
research on some of these issues, we find that a few key emergent research questions that merit
attention include:
● Comprehensive Energy Modeling. How would the inclusion of both electrolytic hydrogen and
direct air capture within energy demand modeling affect the optimal mix and magnitude of
renewable energy resources and energy storage in the coming decades. How does this
compare to the resource mix in models (e.g., in the Scoping Plan) that exclude this energy
demand?
● Electrolyzer Efficiency. How does a variable renewable energy supply affect electrolyzer
efficiency and the required installed capacity of various electrolyzer types, and what are the
cost and infrastructure trade-offs between using energy storage to provide a steady power
supply to electrolyzers, or oversizing electrolyzers to accommodate a variable supply? Put
simply, is it better to build fewer electrolyzers that each have storage, or more electrolyzers, if
they are powered by variable renewable energy?
● Curtailed Electricity. How much curtailed electricity might be available for either hydrogen
(or direct air capture) from now through 2045? Given the inconsistent nature of this supply,
how does including curtailed energy in economy-wide electricity system optimization affect
the optimal use of curtailed energy for hydrogen, direct air capture, and other purposes? How
does this affect system costs, including given irregular electrolyzer use described in the
previous question? How does the reason for the curtailment (e.g., excess supply, transmission
99 | Green Hydrogen Proposals Across California | PSE Healthy Energy
constraints, etc.) affect the ability to utilize this energy source for various proposed
applications?
● Water Use. Water consumption estimates for hydrogen production are quite variable. Can we
develop better water use estimates for hydrogen produced from wind, solar, and various
biofuel sources? How do water resources align with the proposed requirements for hydrogen,
DAC, and CCS, and are these aligned geographically across California? Do we expect to see
competing demands? Will shis in seasonal water availability impact the cost or availability of
hydrogen?
● Land Use. What are the land use impacts of “off grid” renewable resources proposed to
support hydrogen and DAC?
● Prioritization. Where would clean hydrogen deployment be most beneficial, both in 2045 and
in the near term, to support decarbonization? If there is a limited supply, what sector should
get it first?
● Economic Risks. How do we better characterize the economic risks associated with supply
volatility and stranded assets while building out hydrogen infrastructure?
● Leakage, Safety, and Climate. What are the long-term safety and climate impacts of using
hydrogen in pipelines, industry, appliances, and other infrastructure? How does leakage
evolve over time?
● Opportunity Costs. What is the opportunity cost of investing in hydrogen blending or
otherwise ongoing use of fossil fuel infrastructure as compared to investments in renewables
or other decarbonization efforts such as direct electrification of home heating heat pumps?
● Hydrogen Storage. What is the technical and economic potential for bulk hydrogen storage
across California, and how does this potential interact with competing demand to use these
sites for CO
2
storage? How do these relate to safety, equity, and public health concerns?
● DAC Energy Needs. It is difficult to characterize the competing energy and water needs of
hydrogen and DAC without a better understanding of DAC energy and water requirements.
How much geothermal, waste, and solar thermal energy could reasonably be dedicated to
direct air capture to minimize wind + solar photovoltaic energy input requirements? Which
direct air capture technologies have the lowest energy and water inputs?
100 | Green Hydrogen Proposals Across California | PSE Healthy Energy
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