1Interim Report

Net-Zero America:
Potential Pathways, Infrastructure, and Impacts
Princeton University:

Eric Larson,a Chris Greig,b Jesse Jenkins,c Erin Mayfield,d Andrew Pascale,e Chuan Zhang,eJoshua Drossman,f Robert Williams,g Steve Pacala,h and Robert Socolowi

External collaborators: Ejeong Baik,j Rich Birdsey,k Rick Duke,l Ryan Jones,m Ben Haley,m Emily Leslie,n Keith
Paustian,o and Amy Swanp(a) Co-Principal Investigator, Senior Research Engineer, Andlinger Center for Energy and the Environment, Princeton University.
(b) Co-Principal Investigator, Senior Research Scientist, Andlinger Center for Energy and the Environment, Princeton University.
(c) Co-Principal Investigator, Assistant Professor, Mechanical and Aerospace Engineering Department and the Andlinger Center for Energy and the Environment, Princeton University.
(d) Post-doctoral Research Associate, High Meadows Environmental Institute, Princeton University.
(e) Post-doctoral Research Associate, Andlinger Center for Energy and the Environment, Princeton University.
(f) Undergraduate student, Class of ‘22, Operations Research and Financial Engineering Department, Princeton University(g) Senior Research Scientist Emeritus, Andlinger Center for Energy and the Environment, Princeton University.
(h) Professor, Ecology and Evolutionary Biology Department and Director of the High Meadows Environmental Institute’s Carbon Mitigation Initiative, Princeton University.
(i) Professor Emeritus, Mechanical and Aerospace Engineering Department and High Meadows Environmental Institute, Princeton University.
(j) PhD candidate, Department of Energy Resources Engineering, Stanford University.
(k) U.S. Forest Service (retired)(l) Principal, Gigaton Strategies, LLC.
(m) Principal, Evolved Energy Research.
(n) Principal, Energy Reflections, LLC.
(o) Professor, Department of Soil and Crop Sciences & Senior Research Scientist, Natural Resource Ecology Laboratory, Colorado State University.
(p) Project Scientist, Natural Resource Ecology Laboratory, Colorado State University.

Suggested citation: E. Larson, C. Greig, J. Jenkins, E. Mayfield, A. Pascale, C. Zhang, J. Drossman, R. Williams, S. Pacala, R. Socolow, EJ Baik, R. Birdsey, R. Duke, R. Jones, B. Haley,
E. Leslie, K. Paustian, and A. Swan, Net-Zero America: Potential Pathways, Infrastructure, and Impacts, interim report, Princeton University, Princeton, NJ, December 15, 2020.

December 15, 2020 (v2)

Table of Contents
SectionForeword by John P. Holdren
Preface and Acknowledgments
Executive Summary
Motivation for the Net-Zero America study
Modeling methodology and key assumptions
Constructing multiple pathways to net-zeroHigh-level model results: emissions, primary energy, system costs
Pillar 1: End-use energy productivity – efficiency and electrification
Transportation sector
Buildings sector
Electricity distribution system
Industrial sector
Economy-wide electricity demand and demand-supply balancing
Pillar 2: Clean electricity
Solar and wind capacity deployment
Methodology for downscaling solar, wind, and transmission
Mapping solar and wind projects for E+ with base siting
Example area details of solar and wind projects, E+ with base siting
Transmission system for solar and wind, E+ with base siting
Mapping solar and wind for E+ with constrained siting
Transmission system for solar and wind, E+ with base siting
Mapping solar and wind for E+ RE+ with base siting
Transmission system for solar and wind, E+ RE+ with base siting
Cumulative land-use impacts of solar and wind deployment
Clean firm electricity sources
Timing of retirements and rebuilds of thermal generators

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SectionPillar 3: Bioenergy and other zero-carbon fuels and feedstocks
Spatial downscaling of bioenergy systems, E+
Spatial downscaling of bioenergy systems, E- B+
Hydrogen production and use
Pillar 4: CO2 capture, transport, usage, and storage
Pillar 5: Reduced non-CO2 emissions
Pillar 6: Enhanced land sinks
Agricultural soil carbon uptake potential
Forestry-sector carbon sink potential
Summary of 6 pillars of the transition
Implications of net-zero transitions
Land use
Capital mobilization
Fossil fuel industries
Coal
Oil
Natural gas
Employment
Air pollution and health
Potential bottlenecks to the transition
Priority actions for the 2020’s
List of separately available technical annexes

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Foreword (1/2)
By John P. Holdren
Professor in the Kennedy School of Government, Department of Earth and Planetary Sciences, and John A. Paulson School of Engineering and Applied Science at Harvard
University; formerly (2009-2017) Science Advisor to President Obama and Director of the White House Office of Science and Technology Policy.
December 11, 2020

4Long after the terrible challenge of the COVID-19 pandemic has finally been surmounted and (one may hope) greatly improved preparations for inevitable future
pandemics have been put in place, the climate-change challenge will be marching on as the 21st century’s most dangerous and intractable threat to global society.
It is the most dangerous of threats because the growing human disruption of climate that is already far along puts at risk practically every aspect of our material wellbeing—our safety, our security, our health, our food supply, and our economic prosperity (or, for the poor among us, the prospects for becoming prosperous).
It is the most intractable of threats because it is being driven, above all, by emissions of carbon dioxide originating from combustion of the coal, oil, and natural gas thatstill supply eighty percent of civilization’s primary energy and over sixty percent of its electricity; and because, for quite fundamental reasons, the shares of electricity andnonelectric energy provided by these fossil fuels cannot be very rapidly reduced, nor can their emissions be easily or inexpensively captured and sequestered away from theatmosphere.
The index used by climate scientists to characterize, in a single number, the state of Earth’s climate is the annually and globally averaged temperature of the atmosphere at
Earth’s surface. The current value is about 1.1°C (2°F) above the value around the beginning of the 20th century. While that increase may strike one initially as modest, it isnot. Much like the human body temperature, the average surface temperature of the planet is a very sensitive indicator of the state of a very complex system, with smallchanges in the index indicative of major disruptions.
At a mere 1°C or so above the average temperature of 120 years ago, the world is experiencing increases in the frequency and intensity of deadly heat waves in many
regions; increases in torrential downpours and flooding in many others; large expansions in the annual area burned in regions prone to wildfires (and expansion of wildfires
into regions not previously prone to them); an increase in the power of the strongest tropical storms; expanded impacts of pests and pathogens across large parts of the globe;
disruptive changes in monsoons; other alterations in atmospheric and oceanic circulation patterns that, together with other impacts, are affecting agriculture and ocean
fisheries; an accelerating pace of global sea-level rise; and ocean acidification arising from absorption of some of the excess carbon dioxide in the atmosphere.
The momentum in Earth’s climate system and the inertia in society’s energy system together ensure that these impacts will grow for some time to come; but how muchthey grow will depend, above all, on the extent and speed with which human society works to reduce the emissions of carbon dioxide and other heat-trapping gases, toremove them from the atmosphere both biologically and technologically, to adapt our infrastructure and practices to the changes in climate that can no longer be avoided,
and, perhaps, to deploy solar-radiation-management technologies to offset some of the heating effect of the heat-trapping gases in the atmosphere (if this approach can beshown to be safe and at least partially effective).
Most of the global community of nations has long embraced a target of limiting the global-average surface temperature increase to 2°C (3.6°) above the “pre-industrial”
average. (That average was about the same as the value in the period 1880-1900.) It is clear that this figure would entail climatic disruption and impacts considerably greaterthan those currently being experienced at just half of that increase. The 2°C figure was agreed not because it would be “safe”, but because multiple analyses had indicated thatdoing much better would be extremely difficult technologically and economically. (Another factor was the view of some that “tipping points” plunging the world into
continues àForeword (2/2)
drastically different climate regimes were more likely above 2°C than below; in reality, though, the same argument holds for any other choice of target.) As part of the 2015
Paris Agreement of the Conference of the Parties to the UN Framework Convention on Climate Change, the 2°C target was again officially embraced, but a more ambitious,
aspirational target of 1.5°C was added in response to arguments that the likely impacts of 2°C, which science has been bringing into clearer focus, would be intolerable.
In the view of most analysts familiar with the technological and economic challenges of very rapid emission reductions, along with the limitations and uncertainties ofnatural and technological CO2-removal methods and solar-radiation management, holding the temperature increase to 1.5°C target is very unlikely to be achievable. A largepart of the analytical effort on pathways to deep emissions reduction continues to be focused, therefore, on investigating how reductions consistent with a 2.0°C target might
be achieved. In any case, though, it is much more important now to focus on what strategies for technological innovation and what policies will move the world more rapidly
onto a deep-reductions trajectory than to try to agree on exactly what ultimate temperature limit the world will be able to stay below.
A larger point related to this last one is that the benefit of any attempt to identify and model pathways into the energy-climate future is not in predicting the most likely
path on which that future will unfold. It is most improbable that any model will succeed in doing that, given the many respects in which the future is simply not predictable.
Rather, models of the ways in which the energy-climate future might evolve are most useful if they can clarify possibilities, using transparent assumptions and algorithms, inways that help other analysts, policy makers, and publics understand the consequences of different assumptions and choices and, most importantly, help us all shapepolicies and technological-innovation strategies that can be adjusted over time to respond to new realities as they unfold.
It has been clear for two decades or more that, for the industrialized countries to do something approaching a responsible share of a global effort to limit the averagesurface temperature increase to 2.0°C, they would need to reduce their emissions of heat-trapping gases by 80 to 100 percent by around 2050. Each year that has passed
without countries taking steps of the magnitude needed to move expeditiously onto a trajectory capable of achieving such a goal has increased the challenge that still lies
ahead.
At the same time, observations of actual harm from climate change and a continuing flow of bad news from climate science about likely future impacts has increased thesense of urgency in the knowledgeable community, while continuing advances in energy technology have engendered a degree of optimism about what emission reductions
might be possible and affordable. The result has been an increasing flow of (mostly) increasingly sophisticated modeling studies of how emissions of CO2 and other heattrapping gases might be reduced to near zero by 2050. In the United States, such studies have been conducted by the federal government (not always published), by the
National Academies, by national laboratories, by companies, by universities, by NGOs, and by consortia.
I believe that this Princeton Study, Net Zero America: Potential Pathways, Infrastructure, and Impacts, sets an entirely new standard in this genre. The superb
Princeton team—led by Eric Larson, Jesse Jenkins, and Chris Greig—has done an absolutely remarkable amount of new work, developing new models and new data toprovide an unprecedented degree of clarity and granularity about possible pathways to mid-century “net zero” for this country. They have analyzed technologicalpossibilities, as currently understood, in great detail; they have examined the “co-benefit” of reduced disease impacts from conventional air pollutants when fossil-fuel use isreduced; they have examined the employment consequences of alternative trajectories; and, perhaps most importantly, they have called attention to the most important
areas where policy measures are needed to enhance and preserve the nation’s options going forward, as events evolve and understandings grow.
None of the Princeton scenarios will prove to be “right”, but together they provide a compelling picture of possible paths forward. Everybody seriously interested in the
crucial question of this country’s energy-climate future—not least the new Biden-Harris administration—needs to understand the findings of this extraordinary study.
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Preface and Acknowledgments
This Net Zero America study aims to inform and ground political, business, and societal conversations regarding what it would take for the U.S. to achieve an
economy-wide target of net-zero emissions of greenhouse gases by 2050. Achieving this goal, i.e. building an economy that emits no more greenhouse gases into
the atmosphere than are permanently removed and stored each year, is essential to halt the buildup of climate-warming gases in the atmosphere and avert costly
damages from climate change. A growing number of pledges are being made by major corporations, municipalities, states, and national governments to reach netzero emissions by 2050 or sooner. This study provides granular guidance on what getting to net-zero really requires and on the actions needed to translate thesepledges into tangible progress.
The work outlines five distinct technological pathways all of which achieve the 2050 goal and involve spending on energy in line with historical spending as a shareof economic activity, or between 4-6% of gross domestic product (GDP). We are agnostic as to which of these pathways is “best”, and the final path the nation takes
will no doubt differ from all of these. Our goal is to provide confidence that the U.S. now has multiple genuine paths to net-zero by 2050 and to provide a blueprint
for priority actions for the next decade. These priorities include accelerating deployment at scale of technologies and solutions that are mature and affordable today
and will have high value regardless of what path the nation takes, as well as a set of actions to build key enabling infrastructure and improve a set of less maturetechnologies that will help complete the transition to a net-zero America.
With multiple plausible and affordable pathways available, the societal conversation can now turn from “if” to “how” and focus on the choices the nation and its
myriad stakeholders wish to make to shape the transition to net-zero. These conversations will need to be sensitive to the different values and priorities of diverse
communities. That requires insight on how the nation will be reshaped by different paths to net-zero, and the benefits, costs, and challenges for specific locations,industries, professions, and communities. Supporting these decisions requires analysis at a visceral, human scale.
The original and distinguishing feature of this Net Zero America study is thus the comprehensive cataloging across all major sectors at high geospatial and temporal
resolution of the energy infrastructure deployments and related capital expenditures required during a net-zero transition. This granularity allows us to assess
implications for land use, employment, air pollution, capital mobilization, and incumbent fossil fuel industries at state and local levels. The high resolution analysis
is aimed at helping inform federal and state policy choices and private-sector decision making in support of a transition to net-zero by 2050.
During this two-year research effort, the authors had many informative discussions with individuals in environmental research and advocacy organizations, oil andgas companies, renewable energy companies, national labs, industry trade organizations, universities, and elsewhere. The authors thank those individuals for theirtime and interest. The authors also thank the approximately 300 stakeholders who attended briefings where preliminary study results were presented. The feedback
received at and following those briefings have helped shape the contents of this report. Of course, any errors or omissions in this study are the responsibility of theauthors alone, as are any views or recommendations expressed herein.
For funding support, the authors thank the Andlinger Center for Energy and the Environment, BP and the Carbon Mitigation Initiative within Princeton’s High
Meadows Environmental Institute, ExxonMobil, and the University of Queensland.
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Executive Summary (1/9)
Synopsis
A growing number of pledges are being made by major corporations, municipalities, states, and national governments toreach net-zero emissions by 2050 or sooner. This study provides granular guidance on what getting to net-zero reallyrequires and on actions needed to translate these pledges into tangible progress.
Using state-of-the-art modeling tools, this study provides five different technologically and economically plausible energysystem pathways for the U.S. to reach net-zero emissions by 2050. We then further refine these model results to provide
highly-resolved mapping, sector-by-sector, of the timing and spatial distribution of changes in energy infrastructure, capital
investment, employment, air pollution, land use, and other key outcomes at a state and local level.
We find that each net-zero pathway results in a net increase in energy-sector employment and delivers significant
reductions in air pollution, leading to public health benefits that begin immediately in the first decade of the transition. The
study also concludes that a successful net-zero transition could be accomplished with annual spending on energy that iscomparable or lower as a percentage of GDP to what the nation spends annually on energy today. However, foresight andproactive policy and action are needed to achieve the lowest-cost outcomes.
Building a net-zero America will require immediate, large-scale mobilization of capital, policy and societal commitment,
including at least $2.5 trillion in additional capital investment into energy supply, industry, buildings, and vehicles over the
next decade relative to business as usual. Consumers will pay back this upfront investment over decades, making thetransition affordable (total annualized U.S. energy expenditures would increase by less than 3% over 2021-2030), but major
investment decisions must start now, with levels of investments ramping up throughout the transition.
Each transition pathway features historically unprecedented rates of deployment of multiple technologies. Impacts onlandscapes, incumbent industries and communities are significant and planning will need to be sensitive to regionalchanges in employment and local impacts on communities.

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Executive Summary (2/9)
Motivation, Objectives, Approach
Motivation•

Growing government and corporate net-zero-by-2050 pledges, but little detail on execution, costs and impacts.

Project objectives• Temporally and spatially resolve scales, costs, and pacing of required physical, institutional, and human-resource efforts
to reach net-zero by 2050 across the continental US.
• Focus on articulating a granular picture of prospective transitions. Identify potential bottlenecks to success.
• No advocacy of specific policies, but provide actionable details for policy- and decision-making; engage with stakeholders.
Analytical approach• Start with energy service demands projected to 2050 by US EIA (AEO 2019) for 14 regions across continental US.
• Construct multiple (diverse) technology pathways for meeting demands, while reaching net-zero emissions in 2050.
• End-use technologies to meet service demands are exogenously specified in 5-year time steps. This determines final
energy demands that must be delivered by the energy supply system.
• Optimization model finds the energy supply mix that minimizes the 30-year societal NPV of total energy-systemcosts. The model has perfect foresight and seamless integration between all sectors.
• Modeling results are downscaled from 14 regions to state or sub-state geographies to quantify local plantand infrastructure investments, construction activities, land-use, and jobs impacts, 2020 - 2050.

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Executive Summary (3/9)
Six pillars are needed to support the transition to net-zero

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1

End-use energy efficiency and electrification

2

Clean electricity: wind & solar generation, transmission, firm power3

Bioenergy and other zero-carbon fuels and feedstocks

4

CO2 capture, utilization, and storage

5

Reduced non-CO2 emissions

6

Enhanced land sinks

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Executive Summary (4/9)
Six pillars expand rapidly for 3 decades. By 2050:
1. Efficiency & Electrification
Consumer energy investment
and use behaviors change• 300 million personal EVs• 130 million residences with heatpump heating
Industrial efficiency gains• Rapid productivity gain
• EAF/DRI steel making

4. CO2 capture & storage
Geologic storage of 0.9 – 1.7
GtCO2/y• Capture at ~1,000+ facilities• 21,000 to 25,000 km interstate
CO2 trunk pipeline network• 85,000 km of spur pipelines
delivering CO2 to trunk lines• Thousands of injection wells
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2. Clean Electricity

3. Zero-Carbon Fuels

Wind and solar• Rapidly site 10s-100s of GW peryear, sustain for decades• 3x to 5x today’s transmission
Nuclear• In RE- scenario site up to 250 new
1-GW reactors (or 3,800 SMRs).
• Spent fuel disposal.
NGCC-CCS• In RE-, 300+ plants (@750 MW)
Flexible resources• Combustion turbines w/high H2• Large flexible loads: electrolysis,electric boilers, direct air capture• 50 - 180 GW of 6-hour batteries

Major bioenergy industry• 100s of new conversion facilities• 620 million t/y biomass feedstock
production (1.2 Bt/y in E- B+)
H2 and synfuels industries• 8-19 EJ H2 from biomass with CCS(BECCS), electrolysis, and/or
methane reforming• Largest H2 use is for fuels synthesis
in most scenarios

5. Non-CO2 Emissions
Methane, N2O, Fluorocarbons• 20% below 2020 emissions (CO2e)by 2050 (30% below 2050 REF).
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6. Enhanced land sinks
Forest management• Potential sink of 0.5 to 1 GtCO2e/y,
impacting ½ or more of all US
forest area (> 130 Mha).
Agricultural practices• Potential sink ~0.20 GtCO2e/y ifconservation measures adopted
across 1 – 2 million farms.

Executive Summary (5/9)
Net increase of ½ to 1 million jobs over REF in the 2020s.
Annual energy-related jobs (E+ scenario)
U.S. total: net gain of 0.6 million jobs

Green, yellow, and red
indicate average annual
employment in a decade is>15% above, within + 15%,or >15% below 2021
employment, respectively.

Thousand jobs

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Executive Summary (6/9)
Big air pollution health benefits starting in 2020s
Cumulative air quality benefits, 2020 – 2050,
include 200,000 to 300,000 premature deaths
avoided (2 - 3 T$ estimated damages)

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Executive Summary (7/9)
Net-Zero America by 2050 is possible and affordable if:
Ø Technology and infrastructure are deployed at historically unprecedented rates
across most sectors.
Ø Expansive impacts on landscapes and communities are mitigated and managed to secure
broad social license and sustained political commitment.
Ø Large amounts of risk-capital are mobilized rapidly by government and private sectors.
Ø Electrification uptake by consumers is rapid across all states (EV’s, space heating, etc.).
Ø Industry transforms (electrification, hydrogen, low-carbon steel and cement, etc.)
Ø Ambitious expansion of low-carbon technology starts now, with 2020s used to:§ Increase and accelerate deployment of wind and solar generation, EVs, heat pumps§ Invest in critical enabling infrastructure (EV chargers, transmission, CO2 pipelines)§ Demonstrate and mature technology options for rapid deployment in the 2030’s and 2040’s

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Executive Summary (8/9)
A Blueprint for the Next DecadeThis study provides a blueprint for action, including a set of robust measures needed this decade to get on track to net-zeroemissions by 2050, regardless of which net-zero pathway the country follows in the longer term. This implies that big
energy investments can be made this decade with confidence that they will deliver value over the long term.
Priority actions for now to 2030 include:• Get roughly 50 million electric cars on the road and install 3 million or more public charging ports nationwide• Increase by more than double the share of electric heat pumps for home heating (23% vs. 10% today) and triple the use ofheat pumps in commercial buildings• Grow wind and solar electricity generating capacity fourfold (to approximately 600 gigawatts), enough to supply roughly
half of U.S. electricity (vs. 10% today)• Expand high-voltage transmission capacity by roughly 60% to deliver renewable electricity to where it is needed• Increase annual uptake of carbon stored permanently in forests and agricultural soils by 200 million metric tons of CO2-e• Reduce non-CO2 greenhouse gas emissions, including methane, nitrous oxides and hydrofluorocarbons, by at least 10%
Actions for the 2020s also include a set of important investments in enabling infrastructure and innovative technologies tocreate real options to complete the transition to net-zero beyond 2030:• Plan and permit additional electricity transmission to enable further wind and solar expansion• Plan and begin construction of a nationwide CO2 transportation network and permanent underground storage basins• Invest in maturing key technologies to make them cheaper, scalable and ready for widespread beyond 2030, including:carbon capture for a various industrial processes and power generation technologies; low-carbon industrial processes;
clean “firm” electricity technologies, including advanced nuclear, advanced geothermal, and hydrogen combustion
turbines; advanced bioenergy conversion processes & high yield bioenergy crops; hydrogen and synthetic fuel production
from clean electricity, and from biomass and natural gas with carbon capture; and direct capture of CO2 from the air.
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Executive summary (9/9)
Added capital invested (vs. REF) in 2020s is at least $2.5TTotal additional capital invested, 2021-2030, by sector and subsector for a net-zero pathway vs. business as usual (billion 2018$)

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Includes capital invested pre-financial investment decision (pre-FID) and capital committed to projects under construction in 2030 but in-service in later years.
All values rounded to nearest $10b and should be considered order of magnitude estimates. Incremental capital investment categories totaling less than $5B excluded from graphic.
Other potentially significant capital expenditures not estimated in this study include establishment of bioenergy crops and decarbonization measures in other industries
besides steel and cement, non-CO2 GHG mitigation efforts, and establishing enhanced land sinks.

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TABLE OFCONTENTSNet-Zero America: Project motivation
Summary of this section• A growing number of pledges are being made by major corporations, municipalities, states, andnational governments to reach net-zero emissions by 2050 or sooner.
• Achieving net-zero emissions for the nation as a whole presents a major challenge for reasons that
include the high level of emissions today, the country’s still-heavy dependence on fossil hydrocarbon
fuels, and the diverse and firmly established nature of the existing energy infrastructure.
• This study is motivated to help provide analysis that informs a diversity of stakeholders who must
engage to achieve a Net-Zero America – governments, businesses, civil-society organizations, and the
public at large.
• The study aims to provide insights at visceral, human scales of how the nation will be reshaped bydifferent technological pathways to net-zero, and the benefits, costs, and challenges for specificlocations, industries, professions, and communities.

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A dozen states have pledged net-zero by 2050 (and counting)StatuteExecutive Order

2020
2020

2019

2019

2019
2020

2020

2018

2019

2020

2020
2018

Last updated November 15, 2020. Source: https://www.c2es.org/content/state-climate-policy/

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Legislation introduced
in both houses of
US Congress

Growing number of companies have pledged net-zero by 2050
Electric Utilities

For others, see https://sepapower.org/utilitytransformation-challenge/utility-carbon-reduction-tracker/

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Oil & Gas ** These companies’ pledges include
scope 3 emissions.

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Materials

Airlines

Sizing up the challenge: Net emissions today are ~6 GtCO2e/y7000 energy & industry

7000

Million metric tonnes CO2e

Million metric tonnes CO2e

8000
residentialcommercial
agriculture

6000
5000

industry

4000
3000

electricity generation

2000
1000
0
1990

6000
5000
4000
3000
2000

1000 agriculture
0transportation
1995

2000

2005

2010

2015

land sink

-1000
1990

EPA GHG Inventory

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Net Emissions

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2000

2010

2020

Sizing up the challenge: Industrial facilities and power plant emission
sources are widely dispersed today
Economy-wiseemissions by sector
power
plantsindustrytransport

agric
bldgs

Transport
Electricity
heavy industries
Agriculture
power plantsBuildings

EPA flight databaseoil, gas, coal operations

7,515 greenhouse gas emitting facilities
reporting > 25,000 tCO2e/y each (2017)(~ 3 GtCO2e/y total)
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all other industries

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Indu

Sizing up the challenge: 2/3 of final energy today is hydrocarbons
REFERENCE (EIA AEO 2019)

Note: All fuel values
reported in this slide
pack are on HHV basis.

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25~ 25 EJHHV of final energy demand (1/3 of total)
are non-hydrocarbon and could be met using
zero carbon electricity

53~ 53 EJHHV (2/3 of total) are hydrocarbons, forwhich there are the following approaches:• Energy productivity (efficiency, mode
shifting, conservation)• Electrification• Drop-in zero-carbon fuels• Fossil fuel use with CO2 capture +some negative emissions to offset

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Decarbonization pathway modeling methodology & key assumptions
Summary of this section
•
•

•

•
•

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All scenarios satisfy the same demand for energy services (e.g. vehicle miles traveled, area of building
space heated/cooled), consistent with U.S. EIA (Annual Energy Outlook 2019 Reference scenario).
The Energy PATHWAYS model is used to construct two different demand-side scenarios, specifying in
5-year time steps the evolution of energy consuming vehicles, appliances, building stock, etc. to meetthose energy service demands: one with nearly complete electrification of most transportation andbuilding and water heating, and another with slower electrification. These scenarios determine final
energy demand for electricity, gasoline, pipeline gas, and other fuels.
A detailed optimization model, RIO, is then run to determine the lowest-cost (30-year societal netpresent value) mix of supply-side and network infrastructure to meet demand for fuels and reach net
zero emissions by 2050 (with linearly declining emissions). The model has perfect foresight andseamless integration between sectors, and it models power sector operations at hourly resolution for 41
representative days, while tracking fuels and energy storage volumes across days.
Only technologies that are commercially available or have been demonstrated at commercial scale areconsidered; no fundamentally new technologies or scientific breakthroughs are assumed.
Modeling results are only the beginning of the analysis, and serve as inputs for customized highlyresolved “downscaling” analysis performed sector-by-sector (and reported in subsequent sections).
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Pathway modeling tools

Modeling performed by
LIGHT DUTY VEHICLES EXAMPLE

EnergyPATHWAYS
scenario tool*

RIO
optimization tool**

Scenario analysis tool used todevelop economy-wide energy
demand scenarios.

Cost-minimized portfolios of lowcarbon technology deployment forelectricity generation and balancing,alternative fuel production, anddirect air capture.

EnergyPATHWAYS produces
parameters for RIO’s supplyside optimization:• Demand for fuels(electricity, pipeline gas,
diesel, etc.) over time
• Emissions caps by year
• Hourly electricity loadshape

* Open-source software.

RIO returns supply-side decisions to
EP for cost and emissions
accounting:• Electricity sector portfolios,
including renewable mix,
energy storage capacity &duration, capacity for reliability,transmission investments, etc.
• Biomass allocations for fuels

Population

Demandkm per liter(by vintage)

Technology
Efficiency
Cars on the road(by vintage)
Inputs per unitof refined fuelTechnology
Stock

SupplyTechnology
Efficiency** Evolved Energy Research proprietary.

Note: By convention, all fuel values input to EnergyPATHWAYS
and RIO are expressed as higher heating values (HHV); alloutputs are likewise expressed as HHVs. All fuel values reported
in this slide deck are HHVs, unless stated otherwise.

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DemandDrivers

Technology
Stock
Fuels production (oilrefineries, bio-fuel plants,
electro-fuel plants)

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Vehicle km
traveled

Energy Service
DemandGJ of gasoline
demandEnergyDemandEnergy Service
Efficiency
Tonnes of CO2

Emissions

GJ/km
tCO2/GJ ofgasoline
Input-Output
Matrix Linking
Supply Nodes

Electricity
Dispatch

Emissions
Factors

RIO power-sector temporal modeling: Hourly operations for 41
sample days; long-term operations over full chronology
Jan

Samples from historical data representing full range of system conditions

1

2

3

4

5

Detailed short term
dispatch for every
sample day. Dispatch
decisions are the sameacross all days
represented by thesame sample

12000
10000

MW

Data

Short
Term

14000

Dec

8000
6000
4000
2000
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 222324

Long
Term
Do so for all modeled years based on exogenous loads and RPSTime sequential longterm storage operations
across sample day
dispatches. Long-term
dispatch decisions aredifferent across days,
based on long term needs

2020
2025
2030
Jan

24

Dec

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Renew

Storage+

Storage-

Load

10000
5000
0
1
6
11
16
21
26
31
36
41
46
51
56
61
66
71
76
81
86
91
96
101
106
111
116

Map sample days back into historical chronology using day matching

MW

15000
ThermalThermalRenew

Storage+

Storage-

LoadModel inputs are at state level; outputs are reported for 14 zones(consolidated eGRID regions)

25

RETURN TO
TABLE OFCONTENTSKey assumptions• Concerted efforts to enhance land sinks (natural climate solutions).
• Progress in reducing non-CO2 emissions (CH4, N2O, etc.).
• Same energy-service demands to 2050 across all scenarios, based on Energy Information Administration
Annual Energy Outlook (2019) Reference Case
• Two levels of end-use electrification (high and less-high) of transportation and buildings.
• Same-fuel end-use efficiency improvements: adoption of most-efficient equipment at end-of-life
replacement for buildings sector, plus aggressive industrial productivity improvements and reductions inaviation energy use per seat-km.
• Technology performance and costs:• Light duty EV capex parity with ICE by 2030
• Power generation and battery storage: NREL 2019 Annual Technology Baseline (mid-range).
• Biofuels, H2, synfuels from literature sources.
• Direct air capture: American Physical Society, 2011.
• Biomass supply: DOE “Billion Ton Study” + conversion of ethanol-corn & Conservation Reserve Program
lands.
• CO2 transport and storage costs developed in consultation with industry experts.
• Oil and gas prices are AEO 2019 lowest-price projections.
26

RETURN TO TABLE OF CONTENTSKey assumptions
CO2 emissions
Land CO2 in 2050

- 0.85 Gt/y (- 0.7 Gt/y today and declining)

Non-CO2 in 2050

1 GtCO2e/y (50% reduction from today)

Energy/Industry CO2- 0.17 GtCO2 in 2050

Technology installed capital costs in 2016$ (some later slides express values in 2018$, assuming 4% escalation from 2016)
Utility solar, $/kWAC$1,400/kW (2020) à $900/kW (2050) [including grid connection costs]

Onshore wind, $/kW

$1,500 - $2,700/kW (2020) à $1000 - $1,900/kW (2050) [including grid connection costs]

Nuclear power, $/kW

$6,600/kW (2020) à $5,500/kW (2050)

NG power w/CC, $/kW

NGCC-CC, $2,200 (2020) à $1,700 (2050). NG-Allam (99% capture, available from 2030), $2,300/kW.

H2 capex, $/kWH2HHV

Biogasification w/CC, $2,600/kW. NG-ATR w/CC, $800/kW. Electrolysis, $1,700/kW (2020) à $420/kW (2050).

Biopower, $/kW

$3,672/kW (2020) à $3,329/kW (2050)

with CC, $/kW
Biopyrolysis, $/kWliq.HHV
with CC, $/kWliq.HHV
Direct air capture, $/tpy

Bio-IGCC (90% capture), $6,338/kW. Bio-Allam (99% capture, available from 2035), $7,144/kW.
$2,500/kW$4,000/kW (available from 2035)
Direct air capture (available from 2035), $2200 per tCO2/y installed capital cost

Resource costs in 2016$ (some later slides express values in 2018$, assuming 4% escalation from 2016)27

Oil and gas prices

AEO2019 lowest projected prices (2050: crude oil @ $56/bbl & natural gas @ $3.6 - $4.7/GJHHV)

Biomass feedstocks$30 - $150 per dry tonne delivered, based largely on DOE Billion Ton Study (2016)

CO2 transport & storage

Cost varies by location and volume stored. Bulk of supply is in the range of $35/tCO2

AEO 2019 low oil and natural gas price projections assumed due toflat or falling demand (as U.S. and other nations decarbonize)•

For comparison purposes,
all scenarios (including
Reference) are assumed tohave same oil/gas prices.

•

Reduced oil/gas demand islikely to put downward
pressure on prices.

•

Lower prices should thus beexpected in net-zero
pathways vs. Reference(business as usual).
Without a generalequilibrium model, theexact price effect is
uncertain; we take aconservative approach inthis study and treat oil/gas
prices as the same in both
Reference and net-zero
pathways.

•

•

28

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This choice likely
understates cost savings
from reduced oil & gas use
in net-zero paths.

Net-zero emissions by 2050 sets decarbonization target for energy
and industrial process emissions
Gt CO2e

1990
2005
2010
2015
2020
2025
2030
2035
2040
2045
2050

Energy & Industrial system
Non-CO2* Land sink**
1.1
1.19
1.24
1.35
1.22
1.19
1.09
1.04
1.05
1.04
1.02

-0.7
-0.7
-0.7
-0.7
-0.7
-0.73
-0.75
-0.78
-0.8
-0.83
-0.85

5.06
5.92
5.52
5.43
5.2
4.3
3.41
2.51
1.62
0.72
-0.17

* United States Mid-Century Strategy for Deep Decarbonization
benchmark scenario (U.S. Whitehouse, 2016)** Natural plus enhanced land sink.

29

ModeledNet emissions

GtCO2eYear

Historical

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Constructing multiple decarbonization pathways
Summary of this section
We define and model five different net-zero energy-system scenarios (or pathways), each with different
assumptions about energy-demand and energy-supply technology options available in the future. The
pathways help highlight the role of three key elements in energy system transitions: 1) extent of end-use
electrification in transport & buildings, 2) extent of solar & wind electricity generation, and 3) extent ofbiomass utilization for energy. Each of the 5 scenarios has its own short-hand label used in presenting results:
E+
Assumes aggressive end-use electrification, but energy-supply options for minimizing total energysystem cost while meeting the goal of net-zero emissions in 2050 are relatively unconstrained
ELess aggressive end-use electrification, but same supply-side options as E+
E- B+

Electrification level of E-; Higher biomass supply allowed to enable possible greater biomass-based
liquid fuels production to meet liquid fuel demands of non-electrified transport
E+ RE- Electrification level of E+; On supply-side, RE (wind and solar) rate of increase constrained to max
historical build rate. Higher CO2 storage allowed to enable the option of more fossil fuel use that E+
E+ RE+ Electrification level of E+; Supply-side constrained to be 100% renewable by 2050, with no new
nuclear plants built, and no underground carbon storage by 2050.
A large number of sensitivity cases were run to test the impact of changing input parameter values.

30

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Five pathways, each with distinguishing features, for a net-zeroenergy/industrial system by 2050
REF
~AEO 2019

E+

E-

E- B+

E+ RE-

E+ RE+

high electrification

less-high electrificationhigh biomass

renewable constrained

100% renewable

High

High

CO2 emissions target- 0.17 GtCO2 in 2050

Electrification

Low

High

Less highWind/solar annual buildn/a

10%/y growth limit

10%/y growth limit

Existing nuclear

50% à 80-y life

50% à 80-y life

50% à 80-y life

50% à 80-y life

50% à 80-y life

Retire @ 60 years

New nuclear

Disallow in CA

Disallow in CA

Disallow in CA

Disallow in CA

Disallow in CA

Disallowed

Fossil fuel use

Allow

Allow

Allow

Allow

Allow

None by 2050

Maximum CO2 storagen/a

1.8 Gt/y in 2050

1.8 Gt/y in 2050

1.8 Gt/y in 2050

3 Gt/y in 2050

Not allowed

Biomass supply limit

n/a

13 EJ/y by 2050 (0.7 Gt/y biomass)[No new land converted to bioenergy]

31Less high10%/y growth limit Recent GW/y limit 10%/y growth limit

23 EJ/y by 2050
(1.3 Gt/y biomass)

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13 EJ/y by 2050 (0.7 Gt/y biomass)[No new land converted to bioenergy]

A large number of scenario variants have been run to test thesensitivity of results to input assumptions.
Land & nonCO2

Natural gas
prices

1 E+ Land+
2 E+ Land3 E+ Gas+
4 E+ Gas5 E+ NGCC+
6 E+ NGCC-

7 E+ Nuclear+Power
sector
8 E+ Nuclearcapital costs
9 E+ Solar_Wind+
10 E+ Solar_Wind11 E+ Trans+
12 E+ TrRate13 E+ WindPower
sectorcapacitybuild rates

14 E+ Tr&Wind15 E+ NuRate16 E+ RE- NuRate17 E+ RE- NuRate&CCS-

Flex load
options

18 E+ No Electrolysis
19 E+ No Electrolysis No Eboiler
20 E+ BioH2+

H2
21 E+ BioH2production
capital costs 22 E+ ATR+

32

23 E+ ATR-

Higher net land sink + non-CO2 emissions (2050 CO2emission cap for energy/industry changes from -0.17 to 0.27
Lower net land sink + non-CO2 emissions (2050 CO2 emission
cap for energy/industry changes from -0.17 to -0.73 Gt)
AEO2020 'low oil and gas supply' scenario (e.g. 2050 Texas NG
price changes from 3.53 to 6.56 USD/MMBtu)
AEO2020 'high oil and gas supply' scenario (e.g. 2050 Texas
NG price changes from 3.53 to 2.54 USD/MMBtu)
Higher NGCC-CCS capex (2050 capex changes from 1725 to2589 $/kW)
Lower NGCC-CCS capex (2050 capex change from 1725 to 1380$/kW)
Higher nuclear capex (2050 capex changes from 5530 to 8295$/kW)

H2 turbines 24 E+ 2035H2GT
25 E+ Synfuel+Fuels
26 E+ Synfuelproduction
capital costs 27 E+ BioFT+
28 E+ BioFT-

Direct air
captureLower nuclear capex (capex changes from 5530 to 4423 $/kW)
Higher solar/wind capex (e.g. 2050 NJ onshore wind TRG1
goes from 1723 to 2280 $/kW; PV TRG1 from 869 to 1144
Lower solar/wind capex (e.g. 2050 NJ onshore wind TRG1 goesfrom 1723 to 1433 $/kW, PV TRG1 from 869 to 453 $/kW)
Higher transmission cost (e.g. 2050 Mid-Atlantic<-->New Yorktransmission cost doubles to 5642 $/kW)
Higher transmission capacity constraint (e.g. 2050 MidAtlantic<-->New York capacity limit 3830 MW instead of 19145
GW wind installed capacity limits in 2050 (% of E+ capacity):
onshore 50%; offshore-wind 100%, except 70% in Mid-Atlantic
Constrained wind build rate + constrained transmission build
rate (combination of cases 12 and 13)
Constrained nuclear capacity built rate (10GW/year maximum
from 2030)
Constrained nuclear capacity built rate (10GW/year maximum
from 2030)
Constrained nuclear capacity built rate (10GW/year maximum
from 2030) & CO2 storage potential limit of 1.8 Gt/yDisallows electrolysis, one of the hourly flexible loads
Disallows electrolyis and electric boilers, the two hourly flexible
load technology options
Higher capex for bioconversion to H2 with carbon capture(from 2700 to 4050 $/kW in 2050)
Lower capex for bioconversion to H2 with carbon capture (from2700 to 2160 $/kW in 2050)
Higher capex for ATR and SMR (both w/CCS) (from 814 to 1221$/kW for ATR in 2050 and 826 to 1239 $/kW for SMR)
Lower capex for ATR and SMR (both with CCS) (ATR: 814 -->651 $/kW in 2050; SMR: 826 --> 660 $/kW)

Higherenergyefficiency

Higherbiomass
supplyAlt. CO2
emissions

Higherdiscounting

Higher FTS/SNG capex (2050 SNG changes from 1155 to 1732$/kW, FTS changes from 952 to 1428 $/kW)
Lower FTS/SNG capex (2050 SNG changes from 1155 to 924$/kW, FTS changes from 952 to 761 $/kW)
Higher biomass FT w/ccs capex (2050 capex changes from3962 $/kW to 5948 $/kW)
Lower biomass FT w/ccs capex (2050 capex changes from 3962$/kW to 3172 $/kW)

29 E+ DAC-

Lower DAC capex (from $2,164 to $694 per tCO2/year, 2016$)

30 E+ DAC eff+

Higher DAC electric efficiency (1 instead of 2 MWh/tCO2)

31 E+ DAC- eff+

Lower DAC capex and higher efficiency (combines 26 and 27)

32 E+ VMT-

15% lower VMT for light duty vehicles (cars/trucks) by 2050

33 E+ Ieff+
34 E+ Beff+
35 E+ EEF+

No newbiomass

Allow up to 100% H2-firing of GTs starting 2035.

36 E+ B37 E+ RE- B-

3% per year increase in output ($) per unit energy input(instead of 1.9% per year)
1% per year building heating and cooling energy reduction due
to shell efficiency improvements
Combination of the three above EE measures (results in 2050
final energy demand ~25% below E+ level)
E+ but no additional lignocellulosic biomass beyond today’s
level
E+ RE- but no additional lignocellulosic biomass beyond
today’s level

38 E+ RE+ B+

E+ RE+ with high biomass supply

39 E+ RE- B+

E+ RE- with high biomass supply

40 E- RE- B+

E- RE- with high biomass supply

41 E+ slow start
42 E+ reverse S

Energy/industry CO2 trajectory to 2030 follows 2005-2020
rate and then linearly to -0.17 Gt in 2050.
Follows slow start emissions rate to 2030, then falls more
rapidly to 2040, and then slows to reach -0.17 Gt in 2050.

43 E+ 7%

Social discounting @7% instead of 2%

44 E- B+ 7%

Social discounting @7% instead of 2%

Note: Unit capital costs for fuels production technologies are given here on a perunit of output, higher heating value basis.

High-level modeling results for net-zero pathways
Summary of this section••

33

In all five cost-minimized energy-supply pathways, with a linear decline to net-zero emissions by 2050,
coal use is essentially eliminated completely by 2030.
In the pathways with aggressive electrification (E+, E+RE-, and E+RE+) use of petroleum-derived
liquid fuels declines more rapidly than in the less-aggressive electrification cases (E-, E-B+). Natural
gas use also declines, but least rapidly in the E+RE- case, where more CO2 is captured and stored tolimit emissions.

•Overall, fossil fuels in the primary energy mix decline by 62% to 100% from 2020 to 2050 acrossscenarios. Oil and gas decline 56% to 100%.

•

The fossil contribution in 2050 is largest in E+ RE-, where fossil, nuclear, and renewables each accountfor about one-third of primary energy. Except for a small contribution from nuclear, renewables
account for the majority (or all, in E+RE+) of primary energy in the other four scenarios.

•

A significant redirection of capital investment is needed starting in the 2020s on net-zero pathways,
but cumulative amortized energy spending to pay back the capital during the 2020s is less than 3%
more than in the REF scenario for any of the five net-zero pathways, and annual energy spending
across the full 30-year transition as a fraction of GDP is similar to historical spending levels.

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Energy and industrial CO2 emissions are net negative by 2050 todeliver net-zero emissions for the full economy
Fossil fuel use declines
significantly in all netzero pathways; coal use
all but disappearing by
2030.

Net energy& industry
emissionsindustrial process

geologic
sequestration

Carbon storage in long-lived
products is included in themodeling, but is not shown
explicitly here.

34

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uranium
coal

gas

oil

35

wind

sun assmbi oPrimary Energy Supply, EJ (HHV basis)Primary energy mix in 2050 is ≤38% fossil in net-zero pathways.
Coal use all but disappears by 2030. Oil & gas down 56-100%

76%
reductionin oil andgas use,2020 to
2050

64%

67%

56%

100%

RETURN TO
TABLE OFCONTENTSModeled annual energy-system costs as % of GDP are comparable
to (or less than) recent energy-system costs, but higher than REF
Oil price shocks
Societal NPV (2%) of allenergy system costs
2020 2030

2020 2050

REF

9.4

22

E+

9.7

26

E-

9.7

28

E- B+

9.7

27

E+ RE-

9.7

26

E+ RE+

9.7

28

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36

Energy System Cost (% of GDP)

Trillion 2018 $Global financial crisis

Energy System Cost(% of GDP)
Notes

E+ RE+
EE- B+
E+
E+ REREF

E+ RE+
EE- B+
E+
E+ REREF• Significant reduction in exposure to oil price shocks in net-zero scenarios.
• REF assumes low oil & gas prices. If AEO2019 Reference case oil/gas prices
are used, NPV (2020-2050) for REF increases to 29 T$ from 22 T$.

Pillar 1: Improve end-use energy productivity – efficiency andelectrification
Summary of this section• End-use efficiency improvements and electrification across all sectors are critical for reducing:• the required build out of the energy-supply system to deliver the energy needed to meet the given
level of energy service demands.
• the demand for liquid or gaseous fuels, which are generally more difficult/costly to decarbonize
than electricity, as suggested by the significantly increasing marginal prices for fuels across thedifferent scenarios.
• Electrification itself provides large reductions in final energy needed for transportation and heatingbuildings because electric drive trains for vehicles and electric heat pumps for heating are intrinsicallymore efficient than using fuels for these purposes.
• While there is significant electrification of transport and buildings, equipment replacements in ourmodeling are assumed to occur only at economic end-of-life, which reduces asset replacement costs.
More aggressive replacement rates are possible, but would leave some assets stranded and increasetransition costs.
• Summaries of the evolution of transportation, residential, commercial, and industrial sector final
energy demands are provided in later slides in this section.

37

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Increasing marginal prices for fuels in net-zero pathways imply
growing motivation for users to improve efficiencies and electrify.

• Values for 2020 are
fossil fuel prices
projected for 2020 in
AEO2019.
• In later years, values
reflect the cost of
producing one moreunit of zero-carbon fuel;for fossil fuels, values
reflect the cost of bothsupplying one unit offuel and negativeemissions to offset
carbon from burning aunit of fossil fuel.
38$/gallon gasolineequivalent$5/ggeMarginal fuel prices ($/GJHHV, 2016$)• Marginal prices reflect
the modeled cost of
supplying one moreincrement of fuel.

$4/gge$/kg H2equivalent$3/gge$3/kg$2/gge
$2/kg

$1/kg

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End-use energy productivity improves via same-fuel efficiency gains
and via electrification; energy used for oil refining declines.
32% savings in total
8 EJ (efficiency)
13 EJ (electrification)
4 EJ (oil refining)

36 EJ less HCs
68% reduction

23% savings in total
8 EJ (efficiency)
7 EJ (electrification)
3 EJ (oil refining)

23 EJ less HCs
43% reduction

U.S. final-energy
intensity (MJ/$GDP)
falls, 2020 to 2050:• 1.7%/y in REF• 3.0 %/y in E+• 2.6 %/y in EEfficiency gains in• Most of industry• Buildings non-heating• Aviation
Electrification reduces
fuel use and provides
efficiency gains in• Road transport• Heating of buildings• Some industry,
especially iron and steel.
Oil refining energy use
falls from 5.4 EJ in 2020
to 0 to 2.3 EJ in 2050 in
net-zero scenarios.

39

Note: All fuel values reported in this slide pack are on HHV basis.

EVs and heat pumps deliver double benefit: fuel switching to clean
electricity and reduced final energy use due to greater efficiencies

Charging
equipment
Battery charge
efficiency
Inversion
DC/ACElectric motor
efficiency% energy
delivered towheelsElectric Vehicle

Hydrogen Fuel Cell
VehicleGasoline Internal
Combustion Engine

100 units of final energy(electricity)

100 units of final energy(hydrogen)100 units of final energy(gasoline)

5%
energy losses

5%

H2 to electricity
fuel cell
efficiency

46%
energy losses

energy losses

5%energy losses

5%energy losses

81%

Inversion
DC/ACElectric motor
efficiency

5%70%energylossesenergy losses

5%energy losses

49%

Adapted from original in Transport and Environment, “Electrofuels? Yes, we can … if we’re efficient,” December 2020.

40

Internal
combustion
engineefficiency

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30%

Final-energy demands for transportation decrease dramatically.
Other sectors see more modest reductions by 2050.

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TABLE OFCONTENTS

41

Note: All fuel values reported in this slide pack are on HHV basis.

Efficiency improvements at least cost capitalize on timing
equipment/vehicle replacements at end of life.
Bulbs
Other appliances
Air conditioners & Heaters
VehiclesIndustrial boilers
2020

2030

2040

Image credit: Ryan Jones, Evolved Energy Research

42

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2050

Transportation sector
Summary of this section• Final transportation energy demand in 2050 in the net-zero pathways is one-third to one-half the 2020
level, with reductions in energy use for every mode of transport except aviation, for which 1.5%/yassumed efficiency improvements offset growing passenger travel demands• Energy use by light-duty vehicles (LDV) fall most significantly due to electrification. With aggressive
electrification (E+), 17% of the LDVs are electric by 2030 and 96% are electric by 2050. With lessaggressive electrification (E-), the 2030 and 2050 electric shares are 6% and 61%.
• Electric LDV costs have been falling in recent years due largely to battery cost reductions, and the model
assumes costs reductions will continue, with cost parity with conventional LDVs reached around 2030.
The extra upfront costs for electric vs. conventional LDVs in the 2020s cumulatively is $185 billion in
the E+ scenario.
• An additional $7 billion of investment would be needed in public charging infrastructure to support the
EV fleet.
• Medium and heavy-duty truck fleets transition by 2050 to almost entirely electric or hydrogen fuel-cell
power. Cost premiums for these vehicles slowly decline over time, but remain relatively high still in the2030s compared with electric LDV premiums.

43

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Energy use in all transportation modes falls as a result of efficiency
gains (e.g., aviation) and/or electrification (e.g., cars and trucks)

44

Note: All fuel values reported in this slide pack are on HHV basis.

Electricity, jet fuel, and H2 are predominant transportation fuels in
E+ by 2050. Liquid fuels in 2050 are still significant in E-.

45

Note: All fuel values reported in this slide pack are on HHV basis.

In the 2040s, light duty vehicles sales are 60%-100% EV. Medium& heavy truck sales are 50%-100% electric drivetrain (EV + H2FCV)
100%

97%

90%

67%

62%

23%

17%
100%

7%
94%

85%

53%
32%
2%

2%

8%

100%
90%

85%

49%
32%
2%

7%

7%
100%

95%

85%

54%
32%
7%

46

8%

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2%

In E+, the stock of EVs grows to 17% of all light-duty vehicles by2030 and 96% by 2050.
2020

2030

# of EVs: 5.2 million% of LDVs:
2%

2040

49 million
17%

2050

204 million
64%47

328 million
96%
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In E-, the stock of EVs grows to 6% of all light-duty vehicles by2030 and 61% by 2050.
2020

2030

# of EVs: 4.0 million% of LDVs:
1%

2040

17 million
6%

2050

77 million
24%
48

210 million
61%
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A few states have announced targets for EV registrations in 2025
and/or 2030 that approach E+ levels and generally exceed E- levels.
Green states
have announced
targets thatexceed E- levels.

49

California, 2025
California, 2030
Colorado, 2025
Colorado, 2030
Connecticut, 2025
Maine, 2025
Maryland, 2025
Massachusetts, 2025
New Jersey, 2025
New York, 2025
New York, 2030
North Carolina, 2025
Rhode Island, 2025
Vermont, 2025

State targets
E+
EBattery-EVs in the light-duty vehicle fleet (millions)
1.5
4.9
2.7
5.0
7.3
3.4
0.055
0.542
0.212
0.94
0.97
0.34
0.15
0.27
0.10
0.007
0.10
0.032
0.3
0.41
0.15
0.3
0.49
0.18
0.33
0.59
0.22
0.85
1.09
0.39
2
2.02
0.67
0.08
0.73
0.25
0.043
0.077
0.025
0.06
0.06
0.023

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Upfront cost premiums between electric and gasoline light duty
vehicles fall through 2020s, reaching close to parity by 2030
Per vehicle upfront cost difference (2016$)
Electric vs. Reference Gasoline Vehicle
Light Duty Auto (Electric)

30

Light Duty Truck (Electric)

25.5

25
21.6

(1,000 USD)

20

18.2
17.0
15.2

14.4

15

12.5

12.1
10.0

10

9.8
8.2

7.9
6.3

6.3
5.0

5

3.8

4.7
2.8

3.4
1.8

2.2
1.0

0
2020

50

2021

2022

2023

2024

2025

2026

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2027

2028

2029

2030

Incremental first costs for light-duty vehicles (E+ vs. REF) is $185B
in the 2020s; for E- vs. REF, the increment is $9B.
E+

Added capital for light-duty vehicle purchases: net-zero pathway vs. REF (billion $)Total: 185 B$

E-

Total: 9 B$

538 B$

2020s

689 B$

2030s

77 B$

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2040s

456 B$

The number of public charging plugs needed to support EV fleets
are still modest in 2030 in most states, but grow rapidly after.
Number of public EV charging plugs in operation

Total: 2.4 M

2030

9.9 M

2040

15.9 M

2050

Decadal investments in public EV charging plugs

Total: 7.2 B$

52

2020’s

25 B$

E+ scenario

2030’s

20 B$

2040’s

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The number of public charging plugs needed to support EV fleets
are still modest in 2030 in most states, but grow rapidly after.
Number of public EV charging plugs in operation

Total: 0.8 M

2030

3.7 M

2040

10.2 M

2050

Decadal investments in public EV charging plugs

Total: 2.1 B$

53

2020’s

9.8 B$

E- scenario

2030’s

22 B$

2040’s

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Upfront cost premium for medium and heavy duty electric trucks
and transit buses remains significant
Per vehicle upfront cost difference (2016$)
Electric vs. Reference Diesel Vehicle
Medium Duty Truck
350
321

327

322

Heavy Duty Short Haul Truck

317

312

307

295

300

Heavy Duty Long Haul Truck

301

Transit Bus

296

291

286

281

269

276

242

250
(1,000 USD)

216

200

189
175

174

161

160

147

145

150

133

131

118

117
103

100
63

60

57

54

50

51

48

95

46

87

44

79
42

71
40

62
39

0
2020

54

2021

2022

2023

2024

2025

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2026

2027

2028

2029

2030

Medium and heavy duty fuel cell vehicles have much lower upfront
cost premium than electric but higher fueling costs
Per vehicle upfront cost difference (2016$)
Fuel Cell vs. Reference Diesel Vehicle
120

Medium Duty Truck

Heavy Duty Truck

105

100

96
88
79

80
(1,000 USD)

70
62

60

56
51
45

40

40
33

30

34
27

24

20

21

18

16

15

13

11

10

2028

2029

2030

0
2020

55

2021

2022

2023

2024

2025

2026

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2027

Buildings sector
Summary of this section• In residential buildings:• The use of natural gas for space and water heating and cooking is nearly fully replaced by electricity
by 2050 across the net-zero transitions, and final energy use is dramatically lower as a result ofheating (and air conditioning) using heat pumps.
• The market penetration of heat pumps for heating/cooling is highest in warmer climate regions.
They are also adopted in colder regions, although they operate somewhat less efficiently.
• The first-cost premium for space and water heating in the net-zero pathways is $60 to $70 billion
in aggregate for the country in the 2020s compared with REF, or 12% to 13% more. The increase ismodest because heat pumps heat and cool using the same device, unlike gas-fired heaters.
• Commercial sector final energy use also declines, but not as significantly as for the residential sector:• Electricity replaces natural gas in space conditioning, with growing contributions from heat pumps,
but also growth in electric resistance heat for which efficiency gains are not as significant as forheat pumps. Electric cooking also grows.
• The first-cost premium for space and water heating and ventilation in the net-zero pathways is
about $110 billion in aggregate for the country from 2021-2030 compared with REF, an increase ofabout 5%.
56

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Residential sector final energy use declines, and by 2050 electricity
accounts for 85% in E+ and 70% in E-.

57

Note: All fuel values reported in this slide pack are on HHV basis.

Consumer investment choices shift rapidly to electricity forresidential space heating, water heating, and cooking.
• By 2050, space heating,water heating, and cooking
are nearly all electric in E+
and 80-90% electric in E• In space heating, air-source
heat pumps grow todominate.
• In water heating, growth inheat pumps displaces gasfired units; resistanceheating is generally
retained in colder climates.
• Induction cook stoves are
100% of new sales by 2035
in E+ and 2050 in E-.

58

RETURN TO TABLE OF CONTENTSElectric home heating grows significantly, with the fraction
adopting heat pumps varying significantly by climate zone.
Percent of residential
E+
EE+
heating unit type byclimate zone
2020

2030

2040

2050

59

IECC Climate Zones

E-

Residential heat pumps grow from ~10% of the space heating stockin 2020 up to 80% (E+) or 54% (E-) by 2050.
E+

31M units(23% of stock)2030

81M units(58% of stock)

2040

119M units(80% of stock)

2050

2030

41M units(29% of stock)2040

81M units(54% of stock)

2050

E-

21M units(16% of stock)
60

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Number of homes using heat-pump heatingby state:

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Residential electric resistance units decline from ~25% of the spaceheating stock in 2020 to 11% (E+) or 18% (E-) by 2050.
E+

30M units(23% of stock)2030

23M units(17% of stock)2040

16M units(11% of stock)

2050

2030

34M units(24% of stock)

2040

27M units(18% of stock)

2050

E-

33M units(25% of stock)61

Number of homes using electric resistance heat by state:

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Capital expenditures from 2021-2030 for residential space andwater heating are $60B to $70B higher than REF.
E+

U.S. total: 64 B$
Incremental capital vs. REF

U.S. average: 13%% increase vs. REF

E-

U.S. total: 59 B$
62

U.S. average: 12%2021 - 2030

RETURN TO
TABLE OFCONTENTSCommercial buildings’ final energy use declines, and by 2050
electricity accounts for 90% in E+ and 70% in E-.

Note: All fuel values reported in this slide pack are on HHV basis.

63

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In the commercial sector (as in residential), investment choices
shift rapidly to electricity for all energy services.

64

RETURN TO
TABLE OFCONTENTSCapital expenditures from 2021-2030 for commercial HVAC andwater heating are ~$100B to $110B (5%) higher than REF.
E+

U.S. total: 105 B$
Incremental capital vs. REF

U.S. average: 5%% increase vs. REF

E-

U.S. total: 100 B$
65

U.S. average: 5%2021 - 2030

RETURN TO
TABLE OFCONTENTSElectricity distribution system
Summary of this section•••

Even with flexible demand,* distribution networks will likely need to accommodate ~5-10% increase inpeak demand by 2030 and ~40-60% increase by 2050•

Approximately $370b in total distribution network investment is needed in the 2020s in E+ scenario,
an increase of $15-20b vs REF.

•

Investments total ~$700b per decade in the 2030s and 2040s, for a cumulative incremental capital
investment of $215b by 2050.
Due to improvements in energy efficiency (vs REF) and a slower electrification rate (vs E+), peakdemand growth in the E- case is just 2% through 2030 and remains below the REF case.
E- requires ~$300b in total distribution network investment through 2030, ~$50b less than REF.

•
•
*

66

Electrification of vehicles and space and water heating will increase electricity demand and require
upgrades to electricity distribution networks
Flexible demand, including smart charging of EVs and automation of heat pump systems, can reduce
coincident peak demand and stress on distribution networks, minimizing costly upgrades

Our analysis of required distribution reinforcements assumes 50% of electric vehicle loads and 20% of heat pump water heating loads can be shifted to
avoid contributing to peak loading of distribution assets

RETURN TO TABLE OF CONTENTSElectricity distribution investments are $370-700B per decade.
Incremental capital (vs. REF) is ~$20B in 2020s & $215B by 2050.
E+ scenario

2020sTotal investment
2021-2030 = 370 B$

Cumulative incremental capital (E+ vs.
REF) is ~$15-20B in 2020s, increasing
to $215b by 2050.

2030s
67

Total investment
2031-2040 = 700 B$

2040s(2018 $)

Total investment
2041-2050 = 640 B$

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TABLE OFCONTENTS

Industrial sector
Summary of this section
•

•

68

Industrial energy use is roughly constant during the transition in all net-zero scenarios due to:•Energy intensity (energy use per $ of industrial output) decreasing at twice rate in the REF scenario,
but more slowly than the fastest recorded historical 30-yr average rate.*•

Declines in petroleum use across the economy, which reduce needs for petroleum refining, which isa significant energy using sector today.

•

A shift over time toward electric arc furnace steel making and direct-reduced iron production usinghydrogen increases the electricity and hydrogen use in industry, but these are offset by reductions
in fossil fuel use for iron and steel making.

•Energy use for cement production increases over time as this industry is decarbonized through useof CO2 capture applied as a tailpipe measure on otherwise conventional cement production.

During the 2020s, the capital investments in industry for the for net-zero pathways include,
approximately•

250 B$ for energy intensity reductions (assuming 10 to 15 $/GJ of fuel saved)•

60 B$ for new cement plants with carbon capture•

8 B$ for new direct-reduced iron facilities that operate using hydrogen for both fuel and reductant.
RETURN TO TABLE OF CONTENTSU.S. industrial energy intensity continues its declining trend of past
two decades; electrification has less impact than in other sectors.
• Same-fuel energy
productivity improves atdouble the rate in REF.
• Relatively modest fuel àelectricity switching, except
for iron and steel, where
electric arc furnaces grow to
100% of steel-making by
2050. Scrap feedstocks aresupplemented with directreduced iron made using H2.

MJ per $ Gross Industrial Output (2012$)

4.0

3.0

Highest historical average 30-yr
decline rate: 3%/y (1979 to 2009).

2.5
2.0

REF (AEO 2019)(-0.9%/y)

1.5
1.0

E+ and E- pathways(-1.9%/y)

0.5
0.0
1950

69

Historical

3.5

1970

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1990

2010

2030

2050

Industrial final energy in 2050 is 15-20% below REF. Roles forelectricity and H2 grow; use of liquids and other gases decline.

Note: All fuel values reported inthis slide pack are on HHV basis.

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TABLE OFCONTENTS70

Bulk chemicals remains the largest industrial energy user. Petroleum
refining energy use falls. Cement and lime energy use grows.

71

Notes:• Hydrocarbon feedstocks converted to longlived carbon-containing products are ~2% of
the final energy demand shown here.
• Energy used for petroleum refining in othernet-zero scenarios (E-B+, E+RE-, E+RE+)
vary from those shown here for E+ and Edue to varying levels of refined petroleum
products used.
Note: All fuel values reported in this slide pack are on HHV basis.

Energy use in cement/lime making grows due to growth in cement
demand and use of CO2 capture to decarbonize

For net-zero, industry consolidates:- 92 plants retire when > 35 yrs old.
- 35 world-scale plants with CO2
capture are built on brownfieldsites by 2050, starting in 2020’s.
Each world-scale plant:- Costs ~$3.5 billion to build.
- Captures ~2.5 million tCO2/y
124 million tCO2 from cement arecaptured in 2050 (90% capture rate).
72

Clinker Production Capacity, Million metric tonnes

Cement plants, 2017
Plant startup year

# of new plants with CCS*

2026 – 2030

52031 – 2040

16 [4 retrofits]

2041 – 2050

11

Capacity without
CO2 capture

RETURN TO TABLE OF CONTENTS

CementdemandClinkerdemandCapacity with
CO2 capture

U.S. iron and steel production (~90 million t/y) accounts for 106
million tCO2e/y of emissions today (1.8% of total U.S. emissions).
• Current US steel production is:• 32% via integrated iron & steel mills (withblast furnace/basic oxygen furnaces, BF/BOF)
accounting for 69% of I&S CO2 emissions.
• 68% via electric arc furnaces (EAF) using
recycle scrap and some pig iron from BF/BOF,
accounting for 31% of I&S CO2 emissions.
• Distribution of mill types:• All nine operating integrated mills are in the
Eastern US.
• Two direct-reduced iron (DRI) facilities are on
the Gulf Coast.
• Approximately 100 electric arc furnace (EAF)
steel mills are widely dispersed.

73

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Steel industry evolves to 100% electric arc furnaces (EAF) by 2050;
scrap is supplemented by direct-reduced iron (DRI) made using H2.
• US domestic steel production holds steadyat ~90 million t/y to 2050 (AEO2019).

Million metric tonnes

U.S. raw steel production• EAF production grows, producing 100% of
domestic steel by 2050.
• Scrap supply for EAF grows to 59 MMT/yby 2030 and plateaus there.
• Scrap is supplemented by raw steel fromdirect reduction of iron (DRI) using H2 asfuel and reductant.
• Average of 1.5 MMT/y of DRI capacity
comes on line annually from 2030 to 2050
and an equivalent amount of BF/BOF (andassociated coke production) retire. All
BF/BOF are retired by 2050.

New EAF
Existing EAF capacity (assumed replaced at end of life by equivalent capacity)

Blast furnace/Basic oxygen furnace
capacity at integrated mills• DRI plants are geospatially distributed inproportion to current installed EAF
capacity, except none in Northeast.
74

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Economy-wide electricity demand and demand-supply balancing
Summary of this section• Total electricity demand more than doubles by 2050 across all pathways to net-zero:• E+RE-: +115%; E-B+: +125%; E+: +145%; E-: +170%; and E+RE+: +300%.
• End-use demand for electricity grows ~50% in E- scenarios and ~90% in E+ scenarios through 2050,
driven by the pace of electrification of transportation and heating.
• Large volumes of additional electricity are consumption by several ‘intermediate’ demands—
electrolysis, electric boilers (installed in parallel with gas boilers) for industrial process heat, and direct
air capture—all of which can flexibly consume low-cost, carbon-free electricity (e.g. from wind and solar
power) when available and stop consumption when electricity supply is limited.
• If biomass supplies are constrained, falling shorter on electrification of end uses can actually result ingreater electricity consumption (see E- vs E+). Even more electricity must be devoted to intermediateloads to produce hydrogen and power direct air capture devices to supply or offset greater demand for
liquid and gaseous fuels in transportation and heating. Alternatively, biomass use can expand to supply
liquid and gaseous fuels (as in E-B+), with significant land use implications.
• Flexible scheduling of EV charging and electric water heating, large intermediate flexible loads,
batteries, and firm generation technologies all help compensate for variability in wind and solar powerand ensure electricity supply and demand are always balanced.
75

RETURN TO TABLE OF CONTENTSElectricity load grows 2x – 4x by 2050, including flexible
intermediate loads that absorb variable wind and solar generation.

Intermediate demands• Electrolysis making
H2 from water(hourly flexibility).
• Electric boilers inparallel with gas-fired
units in industry(hourly flexibility).
• Direct air capture(daily flexibility).

Final demand

Load (TWh)Intermediate demands
are flexible loads:

76

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TABLE OFCONTENTS

Fueling vehicles with hydrogen or liquids made from electricity
requires much more electricity than using it directly in EVs.
Electricity-to-wheels
efficiency of various zerocarbon vehicle pathways

Adapted, with permission, from Transportand Environment, “Electrofuels? Yes, we
can … if we’re efficient,” December 2020.

77

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Hourly average grid operations: Short-duration batteries play
relatively small roles. Large role for electrolysis in RE+ and E-.
Note: “Other load shifting”
represents up to 50% of EV
charging load and up to
20% of residential &commercial water heatingload that are shifted in time
relative to typical consumer
patterns. In the RIO model,
EV charging can be delayed
by up 5 hours and water
heating can be advanced ordelayed by up to 2 hours.
When EV and water heatingloads are higher than withtypical behavior, they are
shown here as load. Whenthey are lower than withtypical behavior they are
shown as generation.
Meanwhile, “bulk load”
includes EV and water
heating loads under typicalconsumer behavior. Thus,
the “other load shifting”
seen here reflects load
shifting from early evening
to late evening.
If the option of shifting
EV and water heating loads
were removed, the amountof required energy storage
approximately doubles.

78

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Hourly generation and load profiles in 2050 for each of 41 sample
days used to model grid operations, E+ scenario.
day 1

day 2

Generation (GW)

day 0

Load (GW)

Generation

Sample day with lowest net-demand

Load (GW)

Generation (GW)

day 2079

day 21

day 22

Sample day with highest net demand
Load

RETURN TO
TABLE OFCONTENTSElectrolysis capacity grows primarily in the 2040s in all scenarios,
most significantly in RE+.
• Capacity factors(utilization rates) are in
the range of 40-60%• Plants run frequently,
requiring substantial
additional wind and solar
capacity that primarily
supplies electrolysis.
• In other words:
electrolysis doesn’t
just run on ‘excess’ or‘free’ wind and solarthat would otherwise
be curtailed.

80

RETURN TO
TABLE OFCONTENTSElectric boilers are deployed alongside gas boilers for industrial
process heat.

• Allows variable windand solar generation
when available todisplace fossil gas while
maintaining 100%
availability of heat.
• Electric boiler capacity
and utilization growsteadily from 2025 to2050 except in RE-.

81

RETURN TO
TABLE OFCONTENTSDirect air capture of CO2 is significant in E- and RE+ scenarios• With lower electrificationof transportation (andbiomass fully utilized) in
E-, DAC allows for
greater use of liquid andgaseous fossil fuels.
• In RE+ CO2 from DAC isused as carbon source forsynthetic liquid andgaseous fuels.
• Given capital-intensity of
DAC, utilization rates arehigh (50-85%).

82

RETURN TO
TABLE OFCONTENTSLower capital cost and/or higher electricity efficiency of direct air
capture increases its use slightly in E+ and decreases electrolysis
The role of direct air capture (DAC) in futuredecarbonized energy systems is of significant
interest. Relative to E+:•

Lowering DAC capital cost to ~1/3 of E+(E+ DAC-) leads to only a small increasein DAC load because DAC is still morecostly for CO2 removal than other options.
Electrolysis is slightly less utilized.

•

Halving assumed DAC electricity use per
tonne of CO2 captured (E+ Eff+) leads toan even smaller increase in DAC load,with little change in electrolysis use.

•

Combining lower cost and higher
efficiency for DAC (E+ DAC- Eff+)
reduces electrolysis load and total load
more appreciably.

•

NPV of total energy-supply system costs(2020 – 2050) is nearly the same for allcases shown.

Input assumptions that vary between cases
Capital cost, $/(tCO2/y), 2016$

83

Electricity use, MWh/tCO2 captured

E+

E+ DAC-E+ DAC eff+

E+ DEC- eff+

2,164

694

2,164

694

2

2

1

1

DAC cost and efficiency in E+ based on
Socolow, et al., 2011.
DAC cost in DAC- based on Keith, et al, 2018.

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84

Average duration (hours)

Installed Capacity, GW

Grid battery capacity grows (mostly after 2030) to handle intra-day
flexibility needs (5 to 7 hours storage duration)

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Annual build rates for grid batteries are relatively modest throughthe 2030s, increasing thereafter.

2020-25

31-35

26-30

85

41-45

36-40

46-50

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In a sensitivity case without large flexible loads, battery capacity
increases, but other impacts are more significant- Deployment of battery storage is relatively modest in E+, and increases by about 50% by 2050 if flexible electrolysis
and industrial electric boilers are not available.
- When the flexible loads are disallowed, wind and solar generation are reduced and generation from gas with CO2
capture increases.
- Direct air capture is deployed in the final time step (2046-2050) to offset emissions from greater use of natural gas
combined cycle and combustion turbine power plants without CO2 capture and gas use in other sectors.

86

Load (GW)

Average duration, hours

Battery capacity, GW

E+

E+ without
electrolysis or e-boilers

E+

E+ without
electrolysis ore-boilers

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Pillar 2: Clean electricity
Summary of this section

87•

Expanding the supply of clean electricity is a linchpin in all net-zero paths. The share of electricity from carbon-freesources roughly doubles from ~37% today to 70-85% by 2030 and reaches 98-100% by 2050.

•

Wind and solar power have dominant roles in all pathways:• Generation grows more than 4-fold by 2030 to supply about ½ of U.S. electricity in all cases except E+RE-; in thatcase, growth is constrained, but still triples by 2030 to supply one-third of U.S. electricity.
• By 2050, they generate ~7,400-9,900 TWh of electricity in E+, E-, and E-B+ (~85-90% of generation).
In E+RE-, ~3,700 TWh (44%); in E+RE+, 15,600 TWh (98%). (For context, all 2020 U.S. generation ~4,000 TWh)
• Wind and solar capacity deployment rates set new records year after year (unless constrained in E+RE-), withextensive deployment across the United States (with corresponding visual, land use, and employment impacts).

•

Nearly all coal-fired capacity retires by 2030 in all cases, reducing U.S. emissions by roughly 1 GtCO2/year.

•

Nuclear power plants are assumed to operate through 80 years whenever safe to do so.

•

Natural gas generation declines, except in E+RE-, by 2-30% by 2030, while installed capacities are +10% of the 2020
level. In E+RE-, gas-fired generation grows through 2035 (up 30% from 2020) before declining to just 7% of 2020 levels
by 2050, even as total installed capacity grows to be 1/3 higher than in 2020.

•

To ensure reliability, all cases maintain 700-1,100 GW of firm generating capacity through all years (compared to ~1,000
GW today); the model favors gas plants burning an increasing blend of hydrogen and with declining utilization rates
through 2050. If wind and solar expansion is constrained, natural gas plants w/CO2 capture and nuclear expand to pickup the slack.
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Solar and wind generated electricity have dominant roles in all
net-zero pathways• Share of electricity
from carbon-freesources roughly
doubles from ~37%
today to 70-85% by2030 and reaches 98100% by 2050.
• Wind + solar grows>4x by 2030 to supply~½ of U.S. electricity
in all cases except
E+RE-; in that case,growth is constrained,
but still triples by2030 to supply ⅓ ofelectricity.
• By 2050, wind andsolar supply ~85-90%
of generation in E+,
E-, and E-B+. In
E+RE-, 44%; in
E+RE+, 98%.
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Carbon-intensity of electricity drops rapidly in all cases, reachingnet-zero by 2035 in E- and negative values by 2050, except in RE+.

89

RETURN TO
TABLE OFCONTENTSBy 2050 installed solar capacity is 9 to 39 times larger than today,
and installed wind capacity is 6 to 28 times larger.

90

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Regional evolution in electricity mix for E+ and E- scenarios.

91

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Regional evolution in electricity mix for RE- and RE+ scenarios.

92

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Solar and wind electricity generation in E+ would be reduced withfurther end-use efficiency improvements, especially in industry
E+ incorporates significant measures for end-use
energy efficiency in all sectors, but moreaggressive efficiency improvements were tested:
Further efficiency gains in light-duty vehicles(or equivalent reduction in vehicle miles
travelled, E+ VMT-) or building spaceconditioning (E+ Beff-) don’t reduce electricity
generation needs significantly, because theefficiencies for these electrified activities are
already high.

•However, if industrial productivity
improvement is higher (3%/year, the highest
historically observed multi-decade rate,
E+ Ieff+), wind and solar generation in 2050
would be reduced by over 10% relative to E+
and gas w/CC generation also falls; NPV of
total energy-supply system cost declines ~5%.

E+ VMT-

E+ Beff-

E+ Ieff+

TWh

•

E+

Input assumptions that vary between cases

93

E+

E+ VMT-

E+ Beff-

E+ Ieff+

E+ EFF+

Light duty vehicle-miles traveled in 2050, thousand VMT per vehicle

12.9

10.97 (-15%)

12.9

12.9

10.97 (-15%)

Buildings’ heating/cooling final-energy demand reduction rate, %/yr

1.9

1.9

2.9

1.9

2.9

Industrial energy productivity ($ shipments/MJ) increase rate (vs. REF), %/y

1.9

1.9

1.9

3.0

3.0

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E+ EFF+Power generation from natural gas with CO2 capture plays a largerrole if gas prices are lower
Natural gas prices in E+ are as projected in AEO2019“High Oil and Gas Resource and Technology” scenario.
With alternative gas price trajectories:
With lower gas prices (E+ Gas-), electricity
generation by NGCC w/CC increases at the expenseof wind/solar and some nuclear. NPV of totalenergy-supply system cost from 2020 – 2050 (notshown here) is reduced by 2% relative to E+.

•

With higher gas prices (E+ Gas+) gas w/CC
generation is eliminated and replaced at greaterthan 1-to-1 by wind and solar due to greater
electricity demands from flexible loads (e.g.,
electrolysis) to balance the added variablegeneration. NPV of total energy-supply system cost(2020 – 2050) increases ~2% relative to E+.

E+ Gas+E+ Gas-

TWh

•

E+

Input assumptions that vary between cases
2016 $/GJHHVNatural gas price projection source
Natural gas price in 2020, 25, 30, 35, 40, 45, 50 (*)

E+

E+ Gas+E+ Gas-

AEO2019 Hi oil/gas tech & resource

AEO2020 Lo oil&gas supply

AEO2020 Hi oil&gas supply

2.5, 2.8, 3.0, 3.1, 3.1, 3.1, 3.3

2.5, 3.5, 4.4, 4.9, 5.2, 5.6, 6.2

2.3, 2.3, 2.5, 2.5, 2.5, 2.4, 2.4* Natural gas price inputs vary between regions. The prices shown here are for the Texas region in the RIO model.

94

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Higher or lower capital costs for solar and wind mostly impact thebalance between NGCC w/CC and solar/wind generation
Future capital costs for power sector technologies are
uncertain. E+ was tested with higher and lower power-sector
capital cost assumptions:
Changes in solar/wind capital costs have the largest impacts
due to the large installed capacity:•

Lower costs lead to more wind/solar and less NGCC
w/CC. NPV of total energy-supply system (2020 –2050) is ~2% lower than for E+.

•

Higher costs drive more NGCC w/CC into thegenerating mix.

•

Higher transmission costs have a similar impact as higher
solar/wind costs.

•

Lower or higher costs for natural gas w/CC or for nuclear
have little impact because firm capacity needs remain
consistent and gas w/CC retains advantage over nuclear at
all of these cost combinations (given low natural gas prices).

TWh

•

E+

E+ NGCCE+ NucE+ SWE+ Trans+
E+ NGCC+
E+ Nuc+E+ SW+

Input assumptions that vary between cases

95$/kW in 2050

E+

E+ SW -/+

E+ NGCC -/+E+ Nuc -/+E+ Trans+

NGCC w/CC (+50% / -20%)

1,725

1,725

1,380 / 2,589

1,725

1,725

Nuclear (+50% / -20%)

5,530

5,530

5,530

4,423 / 8,295

5,530

Solar/wind (TRG1 NJ, e.g.)*

PV: 869 / Wind: 1,723

PV: 453; 1,144 / Wind: 1,433; 2,280

PV: 869 / Wind: 1,723

PV: 869 / Wind: 1,723

PV: 869 / Wind: 1,723

Trans. (Mid-Atl à NY, e.g.)

2,821

2,821

2,821

2,821

5,642

* E+ uses NREL Annual Technology Baseline (ATB2019) mid-range cost projections. For SW- and SW+, ATB2019 low-cost and average of mid- and constant-cost projections are used, respectively.

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Constrained nuclear deployment rate in E+ RE- will significantly
increase the use of gas w CC, but has small impact on E+ scenario
Siting or supply chain constraints may slow the rate ofplant and infrastructure deployment. We tested
constraints on cumulative wind and transmission
capacity and the rate of new nuclear capacity build:E+•

For E+, limiting inter-regional transmission capacity
to a maximum of 2x current capacity (E+ TrRate-)
leads to slightly more gas w/CC and less wind•

Limiting total wind capacity (E+ Wind-) results inmore solar and gas w/CC and also spurs deployment of
new nuclear capacity in the 2040s.

•

For E+RE-, limiting the rate of nuclear capacity
expansion (E+ RE- NuRate-) leads to about 40% less
new nuclear capacity built over the 30-year period andalso delays the need for significant gas w/CC capacity
until the 2040s. The NPV of the total energy-supply
system (2020 – 2050) is not significantly affected.

E+ Wind-

E+ TrRate-

E+ RE-

E+ RE- NuRate-

Input assumptions that vary between cases

96

E+

E+ Wind-

E+ TrRate-

E+ RE-

E+ RE- NuRate-

Wind total capacity limit (% of E+ capacity)

None

Onshore 50%; Offshore: 100%(except Mid-Atlantic: 70%)

None

None

None

Nuclear build-rate cap

None

10 GW/y

None

None

10 GW/yTransmission cumulative build cap

10x
current

10x current

2x current

10x current

10x current

RETURN TO
TABLE OFCONTENTSHigher discount rate dramatically reduces the NPV of total energysystem costs, but has no substantial impact on the generating mix•

Only a small increase in
deployment of capital-intensive
generators (NGCC w/CC or
biopower w/CC) late in themodeling period.

•

NPV of total energy-supply
system cost (2020 – 2050)
being reduced by roughly half
due to higher discounting of
future costs.

TWh

Use of 7% social discount rateinstead of 2% results in:

Input assumptions that vary between cases
Social discount rate

97

E+

E+ 7%

E- B+

E- B+ 7%

2%/y

7%/y

2%/y

7%/y

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TABLE OFCONTENTS

Availability of electrolysis and electric boilers supports larger build
out of solar and wind generation•

For E+ without an electrolysis
option, the electricity system thatminimizes overall energy system costhas less solar and wind generation,
but slightly more gas with CC by
2050. NPV of total energy-supply
system cost (2020 – 2050) does notchange appreciably from E+.

•

With neither electrolysis nor electricboiler options available, solar andwind generation decrease further,and gas with CC increases further.
NPV of total energy-supply systemincreases by a small amount.

TWhElectrolysis and electric boilers areimportant flexible loads:

Input assumptions that vary between cases

98

E+

E+ No Electrolysis

E+ No Electrolysis No E-boiler

Electrolysis technology available?

Yes

No

No

E-Boiler technology available?

Yes

Yes

No

RETURN TO
TABLE OFCONTENTSEvolution of solar and wind generating capacity
Summary of this section• Wind and solar capacity additions accelerate, setting new record deployment rates year after year.
• The only exception is E+RE- where capacity additions are limited by the scenario design tohistorical maximum rates (~35 GW/year)• Deployment rates in the 2021-2025 period are close to U.S. record maximums (~40 GW/year average);
this rate nearly doubles to 70-75 GW/year average from 2026-2030.
• A total of ~250-280 GW of new wind (~2.5-3x current capacity) and ~285-300 GW of new utilityscale solar (~4x current capacity) is installed from 2021-2030 in E+, E- and E-B+ pathways.
• E+ RE+ deploys 290 GW of wind and 360 GW of solar; E+RE- installs 150 GW of wind and 185 GW
of solar from 2021-2030.
• By the 2030s, most cases are deploying more wind and solar than the world record for a single nation(set by China).
• E- and E+ RE+ eventually reach annual deployment rates in the late 2040s exceeding the total global
wind and solar capacity added in 2019 (>180 GW/year).

99

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30

54

19
15

2020-25

31-35

26-30

100

41-45

36-40

46-50

RETURN TO TABLE OF CONTENTSWorld total (record) solar + wind
deployed in single year (2019)

China record 1-year expansions:
PV (2017) and wind (2015).

RE build limited
to historical US
maximum rate

U.S. projected (pre-Covid-19) additions in 2020

Annual wind and solar capacity additions are sustained overmultiple decades at historically-unprecedented rates

179

Downscaling methodology for solar and wind and transmission
siting in net-zero pathways
Summary of this section• Wind and solar capacity is deployed extensively across the United States in all cases.
• Finding sites suitable to develop projects presents a potential bottleneck to wind and solar deployment.
• To assess availability of lands for wind and solar development, we conduct a high resolution (4km x 4km)
evaluation of the entire continental U.S. (and offshore wind development areas) using ~50 total geospatial
screens to exclude areas with potentially conflicting land uses, including high population density areas,
protected lands (e.g. parks, wilderness), the most productive farm lands, or areas with high environmental
conservation value, as well as areas unsuitable for construction (e.g. wetlands, mountain slopes).
• To visualize the extent of wind and solar deployment and supporting transmission expansion over time, we
downscale RIO’s coarse-resolution model results (14-regions for continental U.S.)• Individual “candidate project areas” that pass the land use screening process are selected to supply sufficient
capacity in each model region and to minimize the total cost of project sites (including grid connection).
• We also visualize a notional expansion of transmission capacity required to connect wind and solar projectsites to demand centers (e.g. major metropolitan areas).
• These downscaling results represent one of many possible configurations of wind, solar, and transmission
siting decisions, guided by a least-cost siting algorithm; other configurations may minimize land use conflict
and/or maximize local benefits.

101

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SolarOnshore Wind

NREL capacity factor map resolution, km
102
Candidate solar and
Average power density (MW/km )45
2.7Land areas excluded from siting of wind / solar projects
onshore wind project
> 17%
> 34%
sites mapped for “Base” Slope
Intactness: Theobald Human Modification index*
HMI < 0.082 for CONSTRAINED only
> 100 people/km excluded; density of solar/windand “Constrained” land Population density
projects in other areas is restricted in inverse
proportion to population density
availability.
Urban areas + buffer, km
0.5
1
2

2

Methodology similar to Wu, et al.,Power of Place: Land
Conservation and Clean Energy
Pathways for California, The
Nature Conservancy, 2019.
* Exclusion categories that distinguish Base from
Constrained land availability are shown in red.
Constrained scenarios are designed to limit
development on intact landscapes. Theobald’s HMI
is used to quantify intactness. HMI is derived fromanalysis of North America at 0.09 km2 resolution,with each cell assigned a value from 0 to 1 based on
multiple metrics. HMI values < 0.082 identify highly
intact landscapes.
Constrained scenarios also restrict onshore winddevelopment on prime farmlands (this is permittedin Base).
102

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Water bodies + buffer, km

0.25

0.25

Military installations + buffer, km

1

3

Active mines + buffer, km

1

1

Airports and runways + buffer, km

1

3

0.25

0.25

Not allowed

Allowed in BASE.
Not allowed in
CONSTRAINED

Railways + buffer, km
Prime soils (prime farmland)
FEMA 1% annual flood hazard areas

Not allowed

Areas of critical environmental concern

Not allowed

National forests (except for wind on ridgecrests), parks,
wilderness, recreation, and other federal protected areas

Not allowed

State parks, forests, wilderness & other protected areas

Not allowed

Wetlands and watershed protected areas

Not allowed

Private conservation & forest stewardship areas

Not allowed, except for wind on ridge crests

Native American areas

Not allowed

BLM High and Moderate sensitivity areas

Not allowed~50 total environmental, cultural, and economic exclusions. See full list hereCurrent land uses limit where solar and wind projects can be built.
Base siting options

Constrained siting options
Shadedregions are
excluded fromdevelopment.

Onshore Wind

103

Solar

Unshadedregions are
suitable forsiting projects(candidate
project areas)

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TABLE OFCONTENTS

Onshore Wind

Solar

Offshore wind exclusion areas and capacity siting process
Exclusion areas- Shipping lanes- Marine protected areas- Gap status 1 for West, Gulf, and East coasts; Gap status 2 for West and Gulf coasts only (gap status relates
to level of sensitivity/administrative protection)- Military installations + 3 km buffer- Military danger zones + 3 km buffer- Outside BOEM-designated zones, candidate area further reduced by 40% (at random) to account for
uncertainty about additional exclusions not explicitly geo-specified- Areas closer than 30 km to shore or greater than 100 km from shore (similar to current BOEM lease zones)

Wind farm technical characteristics- Power density: West coast, 8 MW/km2 (floating turbines, seafloor depth > 50 m); East & Gulf coasts: 5
MW/km2 (fixed turbines, most areas have depth < 50m).
- Capacity factors at 13-km spatial resolution from Vibrant Clean Energy

Sites selected for farms by lowest approximate LCOE until total supply fulfilled- Turbine capex (avg for 2021-2050 used for ordinal ranking): $3,105/kW (sea depth < 50m); $4,519/kW (>50 m) (NREL, ATB2019 mid)
- Sub-sea transmission: $20,500/MW-km (< 50m); $28,300/MW-km (> 50m) (ATB2019 mid)
104

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Offshore-wind candidate project areas and selected sites for E+,
with base siting constraints
New Englandcandidate areas,
base

selected areas,
2050 E+ baseCalifornia

105

New York

candidate areas,
base

selected areas,
2050 E+ bas

Texas, Louisiana

Selected sites
Candidate project areas

Mid-Atlantic

candidate areas,
base

selected areas,
2050 E+Southeast

Mapping solar and wind generators and transmission for the E+
pathway with Base land availability
Summary of this section• In E+, about 300 GW of wind and 300 GW of solar are built across the U.S. by 2030; ~1.5 TW each ofwind and solar capacity are deployed by 2050;• Following a least-cost siting method subject to the Base land availability screen:• The top 10 states for wind capacity by 2050 are: Texas, Missouri, Iowa, Illinois, Nebraska,
Minnesota, New Mexico, Montana, Oklahoma, and Arkansas• The top 10 states for solar capacity by 2050 are: California, Texas, Florida, Georgia, Pennsylvania,
South Carolina, Virginia, Alabama, Missouri, Nebraska• About $700 billion is invested in wind and solar capacity through 2030 and $3.2 trillion by 2050.
• Onshore wind and solar farms span a total area of nearly 600,000 km2; wind farms make up ~93% of
total land area and may have extensive visual impact on nearby communities.
• Lands directly impacted by wind and solar farms (e.g. with roads, turbine pads, solar arrays, inverters,
and substations) are only a fraction of the total site area: about 40,000 km2, with solar farms
accounting for about 85% of this.
• High voltage transmission capacity expands ~60% by 2030 and triples through 2050 to connect windand solar facilities to demand; total capital invested in transmission is $360 billion through 2030 and$2.4 trillion by 2050.
106

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Evolution of wind and utility-scale solar projects, E+ Base
BASE site availability

As of end 2020
(modeled year)
Wind Solar
Capacity installed (TW)
0.15
0.07
2
Land used (1000 km )
Total
58
1.08
Direct
0.6
0.97

107

2020
Wind projects
Note: Site capacity factors are reflected incolor intensity (highest CF = darkest color).

Solar projects

RETURN TO
TABLE OFCONTENTSEvolution of wind and utility-scale solar projects, E+ Base
BASE site availability

2020 - 2025
(cumulative)
Wind Solar
Capacity installed (TW)
0.21
0.15
2
Land used (1000 km )
Total
82
3.3
Direct0.8
3.0
Capital invested (2018$)
Trillion $
0.10
0.10
108

2025
Wind projects
Note: Site capacity factors are reflected incolor intensity (highest CF = darkest color).

Solar projects

RETURN TO
TABLE OFCONTENTSEvolution of wind and utility-scale solar projects, E+ Base
BASE site availability

2020 - 2030
(cumulative)
Wind Solar
Capacity installed (TW)
0.41
0.32
2
Land used (1000 km )
Total
157
7.8
Direct1.6
7.0
Capital invested (2018$)
Trillion $
0.37
0.30
109

2030
Wind projects
Note: Site capacity factors are reflected incolor intensity (highest CF = darkest color).

Solar projects

RETURN TO
TABLE OFCONTENTSEvolution of wind and utility-scale solar projects, E+ Base
BASE site availability

2020 - 2035
(cumulative)
Wind Solar
Capacity installed (TW)
0.65
0.59
2
Land used (km )
Total
245
14.7
Direct2.5
13.2
Capital invested (2018$)
Trillion $
0.69
0.58
110

2035
Wind projects
Note: Site capacity factors are reflected incolor intensity (highest CF = darkest color).

Solar projects

RETURN TO
TABLE OFCONTENTSEvolution of wind and utility-scale solar projects, E+ Base
BASE site availability

2020 - 2040
(cumulative)
Wind Solar
Capacity installed (TW)
0.95
0.85
2
Land used (1000 km )
Total
355
21.5
Direct3.6
19.4
Capital invested (2018$)
Trillion $
1.07
0.84
111

2040
Wind projects
Note: Site capacity factors are reflected incolor intensity (highest CF = darkest color).

Solar projects

RETURN TO
TABLE OFCONTENTSEvolution of wind and utility-scale solar projects, E+ Base
BASE site availability

2020 - 2045
(cumulative)
Wind Solar
Capacity installed (TW)
1.20
1.16
2
Land used (1000 km )
Total
446
29.4
Direct4.5
26.4
Capital invested (2018$)
Trillion $
1.44
1.13
112

2045
Wind projects
Note: Site capacity factors are reflected incolor intensity (highest CF = darkest color).

Solar projects

RETURN TO
TABLE OFCONTENTSEvolution of wind and utility-scale solar projects, E+ Base
BASE site availability

2020 - 2050
(cumulative)
Wind Solar
Capacity installed (TW)
1.48
1.45
2
Land used (1000 km )
Total
550
38.3
Direct5.5
34.5
Capital invested (2018$)
Trillion $
1.84
1.39
113

2050
Wind projects
Note: Site capacity factors are reflected incolor intensity (highest CF = darkest color).

Solar projects

RETURN TO
TABLE OFCONTENTSInstalled solar and wind capacity, top-ranked states,
E+ Base2020
California
Texas
Arizona
NevadaFloridaVirginia
Louisiana
North Carolina
New YorkSouth Carolina
Georgia
New Mexico
OregonMarylandNew Jersey

Texas
Oklahoma
Iowa
Kansas
New Mexico
California
Illinois
Wyoming
Missouri
Minnesota
Colorado
North Dakota
Oregon
New York
Washington

Solar

0

20

40

60

80

100

120

140

160

180

200

Wind

0

Capacity (GW)

114

20

40

60

80

100

120

Capacity (GW)

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140

160

180

200

Installed solar and wind capacity, top-ranked states,
E+ Base2025
California
Texas
Virginia
FloridaMissouriLouisiana
New Mexico
New York
Arizona
NevadaMarylandNorth Carolina
Illinois
New Jersey
Nebraska

Texas
Missouri
New Mexico
Iowa
Illinois
Minnesota
OklahomaKansasCalifornia
Wyoming
Colorado
North Dakota
Oregon
New York
Nebraska

Solar

0

20

40

60

80

100

120

140

160

180

200

Wind

0

Capacity (GW)

115

20

40

60

80

100

120

Capacity (GW)

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140

160

180

200

Installed solar and wind capacity, top-ranked states,
E+ Base2030
Texas
California
FloridaSouth Carolina
Virginia
Missouri
New Mexico
New York
North Carolina
Indiana
Nebraska
Louisiana
Alabama
Georgia
Arizona

Texas
Missouri
Illinois
New Mexico
Indiana
Iowa
Minnesota
OklahomaWyoming
Idaho
Nebraska
Michigan
Arkansas
KansasCalifornia

Solar

0

20

40

60

80

100

120

140

160

180

200

Wind

0

Capacity (GW)

116

20

40

60

80

100

120

Capacity (GW)

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140

160

180

200

Installed solar and wind capacity, top-ranked states,
E+ Base2035
Florida
Texas
California
South Carolina
Virginia
Missouri
Indiana
Georgia
New Mexico
North Carolina
Nebraska
Alabama
New York
NevadaPennsylvania

Texas
Missouri
Illinois
New Mexico
Indiana
Iowa
Oklahoma
Nebraska
Minnesota
Wyoming
Idaho
Montana
Arkansas
Michigan
New York

Solar

0

20

40

60

80

100

120

140

160

180

200

Wind

0

Capacity (GW)

117

20

40

60

80

100

120

Capacity (GW)

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140

160

180

200

Installed solar and wind capacity, top-ranked states,
E+ Base
2040
Texas
FloridaCalifornia
South Carolina
Missouri
Virginia
Georgia
Indiana
North Carolina
Pennsylvania
New Mexico
Nebraska
AlabamaOhio
New York

Texas
Missouri
Illinois
Iowa
New Mexico
Nebraska
IndianaOklahoma
Minnesota
Montana
Ohio
Wyoming
Arkansas
West Virginia
Michigan

Solar

0

20

40

60

80

100

120

140

160

180

200

Wind

0

Capacity (GW)

118

20

40

60

80

100

120

Capacity (GW)

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140

160

180

200

Installed solar and wind capacity, top-ranked states,
E+ Base2045
Texas
California
FloridaGeorgiaSouth Carolina
Virginia
MissouriPennsylvania
Alabama
North Carolina
Indiana
New York
Ohio
New Mexico
Nebraska

Texas
Missouri
Illinois
Iowa
Nebraska
New Mexico
Montana
Minnesota
Oklahoma
Indiana
Arkansas
Ohio
New York
New Jersey
Idaho

Solar

0

20

40

60

80

100

120

140

160

180

200

Wind

0

Capacity (GW)

119

20

40

60

80

100

120

Capacity (GW)

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140

160

180

200

Installed solar and wind capacity, top-ranked states,
E+ Base2050
California
Texas
FloridaGeorgia
Pennsylvania
South Carolina
Virginia
Alabama
MissouriNebraska
North Carolina
New York
Indiana
Ohio
Mississippi

Texas
Missouri
Iowa
Illinois
Nebraska
Minnesota
New Mexico
MontanaOklahoma
Arkansas
Indiana
New York
New Jersey
OhioSouth Dakota

Solar

0

20

40

60

80

100

120

140

160

180

200

Wind

0

Capacity (GW)

120

20

40

60

80

100

120

Capacity (GW)

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140

160

180

200

Capital investment in solar and wind generating projects,
top-ranked states
E+ (Base siting)cumulative (2021-2050), by project type

E+ (Base siting)cumulative (wind & solar), by decade

National totals *TW 2018$ (T)Solar 1.4
1.4
Onshore wind 1.3

1.52030s 1.1

1.2

Offshore wind 0.2

0.3

2040s 1.3

1.3

Total 2.9

3.2

Total 2.9

3.2

* National total TW are cumulative capacity built from 2021 – 2050. This differs from capacity in placein 2050 by the amount already in place in 2020, for which no additional investment is required.

121

National totals *TW 2018$ (T)2020s 0.5
0.7

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National totals *TW 2018$ (T)Solar 1.4
1.4
Onshore wind 1.3

1.52030s 1.1

1.2

Offshore wind 0.2

0.3

2040s 1.3

1.3

Total 2.9

3.2

Total 2.9

3.2

E+ (Base siting)
Cumulative capital invested ingeneration (2021-2050), by project type122

National totals *TW 2018$ (T)2020s 0.5
0.7

E+ (Base siting)
Cumulative capital invested bydecade in solar + wind generation* National total TW are cumulative capacity built from 2021 – 2050. This differs from capacity in placein 2050 by the amount already in place in 2020, for which no additional investment is required.

Example area detail: St. Louis, MO
2050 E+ wind and solar farms (Base site availability)(dots indicate approximate turbine footprint)

500 MW solar facility(generic future facility)

80 MW wind facility(generic future facility)

123

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Example area detail: Columbus, OH
2050 E+ wind and solar farms (Base site availability)(dots indicate approximate turbine footprint)

Buckeye Wind
99 MW proposed facility
Scheduled online date = 2021
Population density = 14 people / km2

124

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Example area detail: Dallas – Fort Worth, TX
2050 E+ wind and solar farms (Base site availability)(dots indicate approximate turbine footprint)

Keechi Wind
110 MW existing facility
Online date = 2015
Population density = 0 people / km2[Town of Jacksboro (7 km away) has
population density > 100 p/km2]

125

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Example area detail: Bakersfield, CA
2050 E+ wind and solar farms (Base site availability)(dots indicate approximate turbine footprint)

Catalina Solar
110 MW existing facility
Online date = 2014
Population density = 4 people / km2

126

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Example area detail: Minneapolis, MN
2050 E+ wind and solar farms (Base site availability)(dots indicate approximate turbine footprint)

Note siting of new
wind farm adjacent
existing facilities

127

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Example area detail: Rochester, NY
2050 E+ wind and solar farms (Base site availability)(dots indicate approximate turbine footprint)

Alabama Ledge Wind
80 MW proposed facility
Scheduled online date = 2021
Existing wind facilities

128

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Example area detail: Orlando, FL
2050 E+ wind and solar farms (Base site availability)(dots indicate approximate turbine footprint)

Peace Creek Solar
57 MW proposed facility
Scheduled online date = 2020

129

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Transmission system in 2020 (> 345 kV lines shown)
Total transmission capacity:~320,000 GW-km*

2020

Transmission
Capacity (GW)130

* Homeland Infrastructure Foundation-Level Data (HIFLD), 2008, as cited in
National Renewable Energy Laboratory, Renewable Electricity Futures Study, 2012.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Base siting availability, 2025
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2025

Cumulative- build: 98,500 GW-km(31% increase from 2020)- capital in service: 150 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)

131

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Base siting availability, 2030
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2030

Cumulative- build: 196,000 GW-km(61% increase from 2020)- capital in service: 360 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)

132

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Base siting availability, 2035
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2035

Cumulative- build: 331,500 GW-km(104% increase from 2020)- capital in service: 670 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)

133

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Base siting availability, 2040
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2040

Cumulative- build: 448,500 GW-km(140% increase from 2020)- capital in service: 1,090 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)

134

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Base siting availability, 2045
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2045

Cumulative- build: 667,200 GW-km(209% increase from 2020)- capital in service: 1,630 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)

135

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Base siting availability, 2050
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2050

Cumulative- build: 691,700 GW-km(216% increase from 2020)- capital in service: 2,360 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)

136

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTo support wind and solar generation in E+ scenario with Basesiting availability, total transmission capacity more than triples.
Transmission & generators.
Note: Capacity factors at generator sites arereflected in color intensity, with highest CF= darkest color.

2050

2020 transmission capacity:~320,000 GW-km
2050 transmission capacity:~1,012,000 GW-km (3.2x)

Transmission
Capacity (GW)

137

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSCapital investment in transmission, top-ranked states
E+ (Base siting)cumulative (2020-2050), by project type

National total
2018$ (B)
Solar

138

Onshore wind

178

Offshore wind129

Bulk transmission

863

Total

1,308

E+ (Base siting)cumulative (wind & solar), by decade

National total
2018$ (B)
2020s

172

2030s

417

2040s

719

Total

1,308

Note: These capital estimates are for transmission expansions. The values labeled solar, onshore wind, and offshore wind are spur lines from solar or wind projects tonearest substations. Sustaining capital invested for end-of-life line replacements is not included in the totals here, but is included in transmission capital investment
estimates in the capital mobilization section of this report.

138

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National total
2018$ (B)
Solar

138

Onshore wind

178

Offshore wind129

Bulk transmission

863

Total

1,308

E+ (Base siting)
Cumulative capital invested in spur andinter-region transmission lines (20202050), by project type

National total
2018$ (B)
2020s

172

2030s

417

2040s

719

Total

1,308

E+ (Base siting)
Cumulative capital invested bydecade in spur and inter-regiontransmission lines for solar + wind

Note: These capital estimates are for transmission expansions. The values labeled solar, onshore wind, and offshore wind are spur lines from solar or wind projects to nearest substations. Sustaining capital

139 invested for end-of-life line replacements is not included in the totals here, but is included in transmission capital investment estimates in the capital mobilization section of this report.

Mapping solar and wind generators and transmission for the E+
pathway with Constrained land availability
Summary of this section• In the Constrained land availability scenario, wind farms cannot be deployed on prime farmlands andneither wind nor solar can be sited in relatively intact landscapes (in addition to all land use screensapplied in the Base scenario).
• These additional constraints, particularly the prime farmlands exclusion for wind power, requires a moredispersed deployment of wind across the Great Plains states, shifting capacity from Iowa, Minnesota andOklahoma to North Dakota, South Dakota and Texas.
• The ranking of top 10 solar states are unaffected relative to Base land availability.
• About $3.4 trillion is invested in ~3.0 TW of wind and solar capacity by 2050.
• Total onshore wind and solar farm area (~600,000 km2) and directly impacted land area (~40,000 km2)
are similar to the Base land availability scenario.
• The footprint of wind and to a lesser extent solar, is significant and will require sensitive engagement with
communities to assure ongoing support. Downscaling offers useful resources to plan local engagement.
• Constrained land availability requires greater transmission expansion than Base availability, as wind farms
push into more remote areas of the Great Plains states. Transmission capacity expands ~75% by 2030 and
3.5x through 2050.
• Total capital invested in transmission is ~$530b through 2030 and $2.5 trillion by 2050.
140

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Constrained land availability scenario leads to more dispersed windand solar development across U.S. — 2050 E+ Constrained siting
CONSTRAINED site availability

2020 - 2050
(cumulative)
Wind Solar
Capacity installed (TW)
1.61
1.45
2
Land used (1000 km )
Total
564
37.8
Direct5.6
34.0
Capital invested (2018$)
Trillion $
1.94
1.45
141

2050
Wind projects
Note: Site capacity factors are reflected incolor intensity (highest CF = darkest color).

Solar projects

RETURN TO
TABLE OFCONTENTSInstalled solar and wind capacity, top-ranked states,
E+ Constrained
2050
Texas

Texas
California
FloridaPennsylvania
GeorgiaSouth Carolina
AlabamaVirginia
Missouri
Indiana
Nebraska
Ohio
North Carolina
New York
Mississippi

MissouriNorth Dakota
Nebraska
South Dakota
Illinois
Arkansas
New Mexico
Montana
Iowa
OklahomaWest Virginia
Pennsylvania

Solar

Wind

New York
Wisconsin
0

20

40

60

80

100

120

140

160

180

200

0

40

60

80

100

120

140

Capacity (GW)

Capacity (GW)

142

20

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160

180

200

Capital investment in solar and wind generating projects, topranked states
E+ (Constrained siting)cumulative (2021-2050), by project type

E+ (Constrained siting)cumulative (wind & solar), by decade

National totals*
TW 2018$ (T)Solar 1.4
1.4
Onshore wind 1.4

1.72030s 1.1

1.3

Offshore wind 0.15

0.232040s 1.3

1.3

Total 3.0

3.4

Total 3.0

3.4

* National total TW are cumulative capacity built from 2021 – 2050. This differs from capacity in placein 2050 by the amount already in place in 2020, for which no additional investment is required.

143

National totals*
TW 2018$ (T)2020s 0.6
0.8

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National totals*
TW 2018$ (T)Solar 1.4
1.4
Onshore wind 1.4

1.72030s 1.1

1.3

Offshore wind 0.15

0.232040s 1.3

1.3

Total 3.0

3.4

Total 3.0

3.4

E+ (Constrained siting)
Cumulative capital invested ingeneration (2021-2050), by project type

144

National totals*
TW 2018$ (T)2020s 0.6
0.8

E+ (Constrained siting)
Cumulative capital invested bydecade in solar + wind generation* National total TW are cumulative capacity built from 2021 – 2050. This differs from capacity in placein 2050 by the amount already in place in 2020, for which no additional investment is required.

Transmission system in 2020 (> 345 kV lines shown)
Total transmission capacity:~320,000 GW-km*

2020

Transmission
Capacity (GW)145

* Homeland Infrastructure Foundation-Level Data (HIFLD), 2008, as cited in
National Renewable Energy Laboratory, Renewable Electricity Futures Study, 2012.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Constrained siting availability, 2025
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2025

Cumulative- build: 125,600 GW-km(39% increase from 2020)- capital in service: 240 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)146

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Constrained siting availability, 2030
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2030

Cumulative- build: 244,500 GW-km(76% increase from 2020)- capital in service: 530 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)

147

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Constrained siting availability, 2035
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2035

Cumulative- build: 396,800 GW-km(124% increase from 2020)- capital in service: 910 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)

148

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Constrained siting availability, 2040
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2040

Cumulative- build: 555,900 GW-km(174% increase from 2020)- capital in service: 1,370 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)149

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TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Constrained siting availability, 2045
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2045

Cumulative- build: 769,600 GW-km(241% increase from 2020)- capital in service: 2,040 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)

150

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ scenario with Constrained siting availability, 2050
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2050

Cumulative- build: 795,200 GW-km(249% increase from 2020)- capital in service: 2,540 B$
Note: Capital in service includes both capitalfor transmission expansions and “sustaining
capital” (for end-of-life line replacements.)

Transmission
Capacity (GW)

151

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTS

E+ with Constrained site availability requires more transmission;
total transmission capacity in 2050 is 3.5x current capacity.
Transmission & generators.
Note: Capacity factors at generator sites arereflected in color intensity, with highest CF= darkest color.

2050

2020 transmission capacity:~320,000 GW-km
2050 transmission capacity:~1,115,000 GW-km (3.5x)

Transmission
Capacity (GW)

152

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSCapital investment in transmission, top-ranked states
E+ (Constrained siting)cumulative (2020-2050), by project type

National total
2018$ (B)
Solar

135

Onshore wind

190

Offshore wind130

Bulk transmission

951

Total

1,407

E+ (Constrained siting)cumulative (wind & solar), by decade

National total
2018$ (B)
2020s

211

2030s

448

2040s

748

Total

1,407

Note: These capital estimates are for transmission expansions. The values labeled solar, onshore wind, and offshore wind are spur lines from solar or wind projects tonearest substations. Sustaining capital invested for end-of-life line replacements is not included here, but is included in transmission capital investment estimates in
the capital mobilization section of this report.

153

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National total
2018$ (B)
Solar

135

Onshore wind

190

Offshore wind130

Bulk transmission

951

Total

1,407

E+ (Constrained siting)
Cumulative capital invested in transmission(2020-2050), by project type

National total
2018$ (B)
2020s

211

2030s

448

2040s

748

Total

1,407

E+ (Constrained siting)
Cumulative capital invested intransmission (2020-2050), by decadeNote: These capital estimates are for transmission expansions. The values labeled solar, onshore wind, and offshore wind are spur lines from solar or wind projects to nearest substations. Sustaining capital

154 invested for end-of-life line replacements is not included in the totals here, but is included in transmission capital investment estimates in the capital mobilization section of this report.

Mapping solar and wind generators and transmission for the
E+ RE+ pathway
Summary of this section• The E+ RE+ case relies exclusively on renewable energy by 2050, and requires 5.7 TW of wind and solar
capacity to meet economy-wide demands (nearly double the capacity in the E+ case). This represents $6.2
trillion of investment.
• The ranking of top 10 solar states are unaffected relative to Base land availability.
• Wind and solar farms span a total area of more than 1 million km2; wind farms account for 94% of this andmay have extensive visual impact on nearby communities.
• Offshore wind farms span another 64,000 km2 and are built extensively along the entire Atlantic Coast, as
well as some areas in the Gulf of Mexico and floating turbines on the Pacific coast.
• Lands directly impacted by onshore wind and solar farms (e.g. with roads, turbine pads, solar arrays,
inverters, and substations) totals ~70,000 km2.
• Transmission capacity expands ~78% by 2030 and 5.3x through 2050 (over 1.7 million GW-km, or ~70%
more transmission expansion than the E+ case).
• Total capital invested in transmission is ~$390b through 2030 and $3.7 trillion by 2050.
• The footprint of wind and solar in RE+ are extensive and will require broad-based and sustained support
from communities across much of the nation.
• A more restrictive permitting regime which constrains the available sites for development leads to moredispersed wind and solar development and increased transmission requirements, and significant regional
shortfalls in both offshore and onshore wind sites.
155

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2050 build out of wind and solar projects, RE+ Base
BASE land area exclusions

2020 - 2050
(cumulative)
Wind Solar
Capacity installed (TW)
3.0
2.7
2
Land used (1000 km )
1009
66
Total
Direct10.1
59
Capital invested (2018$)
Trillion $
3.8
2.2
156

2050
Wind projects
Note: Site capacity factors are reflected incolor intensity (highest CF = darkest color).

Solar projects

RETURN TO
TABLE OFCONTENTS

2050 build out of wind and solar projects, RE+ Constrained*
CONSTRAINED land area exclusions* With Constrained site
availability, there wereinsufficient candidate
project sites for wind (onand off-shore) in someregions. Additional sites
were allowed to be selectedfrom Base site-availability
areas in those cases. There
were also insufficient solar
candidate project sites insome regions, and a similar
allowance was made.

2050
Wind projects

157

Note: Site capacity factors are reflected incolor intensity (highest CF = darkest color).

Solar projects

RETURN TO
TABLE OFCONTENTSInstalled solar and wind capacity, top-ranked states,
E+ RE+ Base
2020
California
Texas
FloridaGeorgia
Pennsylvania
South Carolina
Virginia
Alabama
MissouriNebraska
North Carolina
New York
Indiana
Ohio
Mississippi

Texas
Oklahoma
Iowa
KansasCalifornia
Illinois
New Mexico
Missouri
Minnesota
Colorado
North Dakota
Oregon
New York
Washington
Indiana

Solar

0

40

80

120

160

200

240

280

320

Wind

0

Capacity (GW)

158

50

100

150

200

Capacity (GW)

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250

300

350

Installed solar and wind capacity, top-ranked states,
E+ RE+ Base
2050
California
Texas
FloridaGeorgia
Pennsylvania
South Carolina
Virginia
Alabama
MissouriNebraska
North Carolina
New York
Indiana
Ohio
Mississippi

Texas
Iowa
MissouriNebraska
Montana
Illinois
Oklahoma
Minnesota
New Mexico
ArkansasSouth Dakota
KansasPennsylvania
New York
North Carolina

Solar

0

40

80

120

160

200

240

280

320

Wind

0

Capacity (GW)

159

50

100

150

200

Capacity (GW)

RETURN TO TABLE OF CONTENTS

250

300

350

Capital investment in solar and wind generating projects,
top-ranked states
E+ RE+ (Base siting)cumulative (2021-2050), by project type

E+ RE+ (Base siting)cumulative (wind & solar), by decade

National totals*
TW 2018$ (T)Solar 2.7
2.6
Onshore wind 2.6

3.0

2030s 1.8

2.1

Offshore wind 0.4

0.6

2040s 3.2

3.3

Total 5.6

6.2

Total 5.6

6.2

* National total TW are cumulative capacity built from 2021 – 2050. This differs from capacity in placein 2050 by the amount already in place in 2020, for which no additional investment is required.

160

National totals *TW 2018$ (T)2020s 0.7
0.8

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National totals*
TW 2018$ (T)Solar 2.7
2.6
Onshore wind 2.6

3.0

2030s 1.8

2.1

Offshore wind 0.4

0.6

2040s 3.2

3.3

Total 5.6

6.2

Total 5.6

6.2

E+ RE+ (Base siting)
Cumulative capital invested ingeneration (2021-2050), by project type161

National totals *TW 2018$ (T)2020s 0.7
0.8

E+ RE+ (Base siting)
Cumulative capital invested bydecade in solar + wind generation* National total TW are cumulative capacity built from 2021 – 2050. This differs from capacity in placein 2050 by the amount already in place in 2020, for which no additional investment is required.

Transmission system in 2020 (> 345 kV lines shown)
Total transmission capacity:~320,000 GW-km*

2020

Transmission
Capacity (GW)162

* Homeland Infrastructure Foundation-Level Data (HIFLD), 2008, as cited in
National Renewable Energy Laboratory, Renewable Electricity Futures Study, 2012.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ RE+ scenario with Base siting availability, 2025
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2025

Cumulative- build: 99,700 GW-km(31% increase from 2020)- capital invested: 160 B$

Transmission
Capacity (GW)

163

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ RE+ scenario with Base siting availability, 2030
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2030

Cumulative- build: 250,200 GW-km(78% increase from 2020)- capital invested: 390 B$

Transmission
Capacity (GW)

164

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ RE+ scenario with Base siting availability, 2035
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2035

Cumulative- build: 482,200 GW-km(151% increase from 2020)- capital invested: 780 B$

Transmission
Capacity (GW)

165

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ RE+ scenario with Base siting availability, 2040
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2040

Cumulative- build: 805,700 GW-km(252% increase from 2020)- capital invested: 1,370 B$

Transmission
Capacity (GW)166

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ RE+ scenario with Base siting availability, 2045
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2045

Cumulative- build: 1,304,300 GW-km(408% increase over 2020)- capital invested: 2,270 B$

Transmission
Capacity (GW)

167

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTransmission expansions to support wind and solar generation in
E+ RE+ scenario with Base siting availability, 2050
Spur lines from solar andwind projects to substations
are not shown, but areincluded in investment and
GW-km build totals:

2050

Cumulative- build: 1,382,100 GW-km(432% increase from 2020)- capital invested: 3,710 B$

Transmission
Capacity (GW)

168

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSTo support wind and solar generation in E+RE+ scenario with Basesiting availability, total U.S. transmission capacity increases 5.3x.
Transmission & generators.
Note: Capacity factors at generator sites arereflected in color intensity, with highest CF= darkest color.

2050

2020 transmission capacity:~320,000 GW-km
2050 transmission capacity:~1,702,000 GW-km (5.3x)

Transmission
Capacity (GW)

169

Note: Transmission expansion is visualized along existing rights of way (>160 kV); paths are indicative not definitive.

RETURN TO
TABLE OFCONTENTSCapital investment in transmission, top-ranked states
E+ RE+ (Base siting)cumulative (2020-2050), by project type

National total
2018$ (B)
Solar

298

Onshore wind

370

Offshore wind

267

Bulk transmission

1,592

Total

2,527

E+ RE+ (Base siting)cumulative (wind & solar), by decade

National total
2018$ (B)
2020s

183

2030s

715

2040s

1,630

Total

2,527

Note: These capital estimates are for transmission expansions. The values labeled solar, onshore wind, and offshore wind are spur lines from solar or wind projects tonearest substations. Sustaining capital invested for end-of-life line replacements is not included here, but is included in transmission capital investment estimates in
the capital mobilization section of this report.

170

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National total
2018$ (B)
Solar

298

Onshore wind

370

Offshore wind

267

Bulk transmission

1,592

Total

2,527

E+ RE+ (Base siting)
Cumulative capital invested in transmission(2020-2050), by project type171

National total
2018$ (B)
2020s

183

2030s

715

2040s

1,630

Total

2,527

E+ RE+ (Base siting)
Cumulative capital invested intransmission (2020-2050), by decadeNote: These capital estimates are for transmission expansions. The values labeled solar, onshore wind, and offshore wind are spur lines from solar or wind projects to nearest substations. Sustaining capital
invested for end-of-life line replacements is not included in the totals here, but is included in transmission capital investment estimates in the capital mobilization section of this report.

Cumulative land use impacts of wind and solar deployment
Summary of this section

172• Cumulative land use impacts of wind and solar deployment in the E+ case (2021-2050):• Total area spanned by onshore wind and solar farms is ~590,000 sq-km, an area roughly equal to thesize of IL, IN, OH, KY, TN, MA, CT and RI put together. Offshore wind farms span 33,000 sq-km.
• Wind projects drive total farm area, which is concentrated in the Great Plains and Midwest andprimarily on crop, pasture, and forested lands.
• Wind farms have large spatial extent and significant visual impact, but directly impact only 1% of totalsite area and can co-exist with farming and grazing.
• Conversely, directly impacted land area is dominated by solar and greatest in the Northeast andSoutheast; forested lands make up the largest directly impacted land cover type.
• Solar farms are more compact but also more intensive, directly impacting ~90% of their area.
• Wind and solar present different land use impacts, with particular advantages and challenges.
• Cumulative total wind and solar farm area in E+ RE+ by 2050 is ~1 million km2, or roughly an area the sizeof AK, IA, KS, MO, NE, OK, and WV combined (with an additional 64,000 km2 of offshore wind); directly
impacted lands total 70,000 km2, an area larger than WV.
• Only 3% of Constrained solar candidate project areas are selected in E+ and 5% in E+ RE+, indicating
potential to substantially reconfigure solar siting to minimize conflict.
• Wind farms use 57% and >100% of Constrained candidate project areas in E+ and E+ RE+, respectively,
and face shortfalls in some regions, indicating greater potential for wind to be constrained by siting
challenges.
RETURN TO TABLE OF CONTENTS

2030 solar and wind siting summary for E+ and E+ RE+ cases
2030 E+2030 E+ RE+

SolarOnshoreWind

Offshore
wind

Solar

OnshoreWind

OffshorewindCapacity installed (GW) [a]

324

414

111

405

490

5

Solar and wind farm area (km2)

7,800

156,700

1,000

10,400185,900

1,000

Directly impacted (km2) [b]

7,000

1,600

10

9,500

1,900

10

Percent of total candidate project areas used
Base site availability

0%

5%

0%

1%

17%

8%

Constrained site availability

1%

16%

4%

2%

46%

62%

[a] With Base site availability. [b] Equipment, roads, infrastructure.

173

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2050 solar and wind siting summary for E+ and E+ RE+ cases
2050 E+

2050 E+ RE+

SolarOnshoreWind

Offshore
wind

Solar

OnshoreWind

OffshorewindCapacity installed (GW) [a]

1,500

1,500

200

2,800

2,700

400

Solar and wind farm area (km2)

38,000551,000

33,00066,0001,009,000

64,000

Directly impacted (km2) [b]34,0005,000

300

60,10010,000600

Percent of total candidate project areas used [with regional shortfalls as noted]
Base site availability

1%

18%

14%

3%

34%

27% [c]Constrained site availability

3%

57% [d]137% [e]5%104% [d]248% [f][a] With Base site availability. [b] Equipment, roads, infrastructure. [c – f] Insufficient available sites in someregions result in shortfalls in regional supply of wind energy in: insufficient sites in [c] Mid-Atlantic/Great Lakes, [d]Mid-Atlantic/Great Lakes, Louisiana/Ozarks, Desert SW, [e] Mid-Atlantic/Great Lakes, New York, New England, [f]all regions except California.

174

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Total wind and solar farm areas are de minimis in most states, withthe exception of the Great Plains and Midwest.
Total wind and solar farm area
(1,000 km2)

Total wind and solar farm area as percent ofstate land area (%)

The area impacted by total wind and solar farm boundaries
by mid-century ranges from ~10 km2 in Delaware to~68,000 km2 in Texas.

The share of state land area encompassed by wind and solar
farms by mid-century ranges from <1% in Kentucky to~37% in Iowa.

Land cover type

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Direct land impacts are greatest in states with high amounts of solar
deployed, including in the Northeast and Southeast.
Land area directly impacted by solar andwind development (1,000 km2)

Percentage of state land area directly impacted
by solar and wind development (%)

The directly impacted land area by mid-century ranges
from ~4 km2 in Kentucky to ~4,400 km2 in Texas.

The share of state land area directly impacted by mid-century
ranges from <<1% in Kentucky to ~3% in Florida.

Land cover type

RETURN TO TABLE OF CONTENTS

Clean firm resources and thermal plant retirements
Summary of this section

177• Installed capacity of “firm” generation sources — technologies that can produce power on demand, any time of year,
for as long as required — remains similar to current levels in all scenarios, with ~500-1,000 GW (vs. 875 GW today).
• Coal fired capacity is completely retired by 2030 across all NZA scenarios with decline rates similar across all
regions at higher than the historical peak of 21 GW/y in 2015. No new coal fired capacity is added in any scenario.
• About 50% of existing nuclear capacity retires by 2050 in all NZA scenarios; the E+RE+ scenario phases out nuclear
by 2050 with 15 GW retired by 2030.
• New advanced nuclear generation capacity is added in all scenarios except in E+RE+; expansion is modest in E+, Eand E+RE- with ~10-20 GW deployed in the 2030s and 2040s. The E+RE- scenario expands new nuclear capacity
rapidly from 2025-2050, deploying ~260 GW by 2050, requiring historically unprecedented build rates in the2040s.
• Natural gas retirements vary across NZA scenarios, with the E+RE+ scenario seeing the most (224 GW) and the
E+RE+ scenario seeing the least capacity retired (175 GW). By 2050, cumulative retirements are consistent acrossmost NZA scenarios (450 GW) except for the E+RE- scenario (506 GW).
• New natural gas fired capacity is added in all scenarios except E+RE+. The most new capacity is added in E+REwhich sees ~580 GW of new gas capacity (around 230 GW with CO2 capture) by 2050.
• To meet firm capacity needs in the 100% renewable E+RE+ scenario, ~590 GW of new combustion turbine andcombined cycle power plants are deployed and by 2050 are fired entirely with zero-carbon synthetic gas.
• Siting studies indicated that most of the new thermal generation capacity can be sited at existing coal, natural gas
and nuclear plant sites with few new sites to be developed, but many existing sites would fail on at least one current
safety or environmental criteria applied to new greenfield projects.
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Installed capacity (GW)

Firm capacity stays comparable to today; high H2 fuel blends forgas turbines have important role; nuclear & gas w/CCS key in RE-

Firm
resources

Note:
To reduce the carbon
intensity of CCGT and CT
generation, H2 is blended
as an increasing fractionof fuel to these units, up to
an exogenously specified
cap of 60% (HHV basis).
In sensitivities with
100% H2 firing allowed,
the model prefers 100%
blend which modestly
reduces total energy
system costs.

Firm capacity(across all years)~500-1000 GW

178

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2020-25

179

31-35

26-30

41-45

36-40

46-50

Combustion
turbines burnzero-carbon
synthetic gas
in RE+ case

Record 1-year nuclear expansion (USA)Combustion turbines and CCGTs burn up
to 60% H2 (100% in sensitivities) in
E+, E-, E-B+ and E+RE-

Record 1-year NGCC Expansion (USA, 2002)

GW per year, averages over 5-year periods

E+ RE- requires historically-unprecedented growth rates for gas
plants w/CCS and nuclear, sustained for multiple decades

60

10
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TABLE OFCONTENTSNew England, New York, California, Florida, Southeast and MidAtlantic/ Great Lakes regions see largest growth
E+ RE-

180

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Modeling conversion and retirement of coal, gas, and nuclear plants
and sites considers operating costs and site suitability criteria.
Site suitability assessment

Site conversion simulation

Evaluate potential sites based onsuitability and exclusion criteria

Conversion of existing thermal sites to
new natural gas or nuclear sites

SafetyEnvironmental/ cultural

Water intake

Site size

CO2
infrastructure

Environmental
justice

Retirement simulation

Site conversions prioritized byextent of siting constraints foreach technology

Retirement ofexisting plants

Regional &temporalincremental
capacity
constraints

Site suitability
constraints

Redevelopment
temporal lag
constraints

Timing and location by plant type

Regional &temporalretiredcapacity
constraints

181

Prioritize
based onoperatingcosts

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Due to age, 45% of nuclear and 80% of gas capacity assumed toretire by 2050; repowering or low-carbon site conversions possible.
Nuclear

182

Natural gas

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Most new gas and nuclear capacity can be accommodated atexisting thermal plant sites, if no new siting restrictions are applied.
New capacity by site type
cumulative 2020 - 2050
NuclearSite conversions by site type by 2050

Gas

E+
Plant count: 8144
Generator count: 22,709
8% of capacity on former coal sites, 90% ng

Plant count: 78
Generator count: 95
15% of capacity on former coal sites, 35% ng, 38% nuclear

E+ REPlant count: 8123
Generator count: 23,366
15% of capacity on former coal sites, 71% ng

183

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Plant count: 521
Generator count: 1260
46% of capacity on former coal sites, 15% ng, 30% nuclear

But most existing locations would fail to meet one or more safety
or environmental suitability criteria for ‘greenfield’ projects today.
Number of current generator locations thatwould fail to meet site suitability criteria
0

2,985

Number of environmental or safety criteria not met

Meets all criteria

184

8,000

6,947
6,107

Number of generators

All environmental & safety criteria
All safety criteria
All environmental criteria

4,000

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Examples of safety, environmental and cultural, water, andcarbon-storage proximity siting criteria.
SafetyExclusions include
urban areas, floodzones, earthquake
regions, etc.

Environmental
and cultural
35 exclusion types(wetlands, nationalparks, landscapeintactness, etc.)

Unsuitable area
Suitable area

Cooling water
sources

185

CO2 sinks
Natural gas combined
cycles with CO2
capture must be sitednear storage basins or
CO2 pipeline
infrastructure.

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Evolution of coal, natural gas, and nuclear generators in E+
with no new siting-criteria filters applied, 2020
2020

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

186

5-yr capital investment
in new capacity:$11B

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Evolution of coal, natural gas, and nuclear generators in E+
with no new siting-criteria filters applied, 2025
2025

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

187

5-yr capital investment
in new capacity:$70B

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Evolution of coal, natural gas, and nuclear generators in E+
with no new siting-criteria filters applied, 2030
2030

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

188

5-yr capital investment
in new capacity:$46B

RETURN TO TABLE OF CONTENTS

Evolution of coal, natural gas, and nuclear generators in E+
with no new siting-criteria filters applied, 2035
2035

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

189

5-yr capital investment
in new capacity:$66B

RETURN TO TABLE OF CONTENTS

Evolution of coal, natural gas, and nuclear generators in E+
with no new siting-criteria filters applied, 2040
2040

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

190

5-yr capital investment
in new capacity:$90B

RETURN TO TABLE OF CONTENTS

Evolution of coal, natural gas, and nuclear generators in E+
with no new siting-criteria filters applied, 2045
2045

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

191

5-yr capital investment
in new capacity:$54B

RETURN TO TABLE OF CONTENTS

Evolution of coal, natural gas, and nuclear generators in E+
with no new siting-criteria filters applied, 2050
2050

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

192

5-yr capital investment
in new capacity:$123B

RETURN TO TABLE OF CONTENTS

Evolution of coal, natural gas, and nuclear generators in E+ REwith no new siting-criteria filters applied, 2020
2020

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

193

5-yr capital investment
in new capacity:$12B

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Evolution of coal, natural gas, and nuclear generators in E+ REwith no new siting-criteria filters applied, 2025
2025

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

194

5-yr capital investment
in new capacity:$83B

RETURN TO TABLE OF CONTENTS

Evolution of coal, natural gas, and nuclear generators in E+ REwith no new siting-criteria filters applied, 2030
2030

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

195

5-yr capital investment
in new capacity:$129B

RETURN TO TABLE OF CONTENTS

Evolution of coal, natural gas, and nuclear generators in E+ REwith no new siting-criteria filters applied, 2035
2035

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant196

5-yr capital investment
in new capacity:$184B

RETURN TO TABLE OF CONTENTS

Evolution of coal, natural gas, and nuclear generators in E+ REwith no new siting-criteria filters applied, 2040
2040

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant197

5-yr capital investment
in new capacity:$382B

RETURN TO TABLE OF CONTENTS

Evolution of coal, natural gas, and nuclear generators in E+ REwith no new siting-criteria filters applied, 2045
2045

Existing coal
Existing natural gas
Existing nuclear
New gas combined cycle power plant
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

198

5-yr capital investment
in new capacity:$583B

RETURN TO TABLE OF CONTENTS

Evolution of coal, natural gas, and nuclear generators in E+ REwith no new siting-criteria filters applied, 2050
2050

Existing coal
Existing natural gas
Existing nuclear
Nuclear
New gas combined
cycle
power plant
Nuclear
New gas combustion turbine power plant
New gas combined cycle with ccu
New advanced nuclear plant

199

5-yr capital investment
in new capacity:$833B

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Pillar 3: Bioenergy and other zero-carbon fuels and feedstocks
Summary of this section• The modeling includes ways to realize carbon-neutral or carbon-negative fuels in net-zero scenarios
starting from fossil fuels, from biomass, and/or from clean electricity. Hydrogen is a key carbon-freeintermediate or final fuel.
• Biomass plays an especially important role because i) it removes CO2 from the atmosphere as it grows andso combustion of hydrocarbon fuels made with biomass carbon results in no net CO2 emissions to theatmosphere, ii) it can be converted into H2 while capturing and permanently sequestering its carbon,
resulting in a net negative-emissions fuel, and iii) it can similarly be used to make negative-emissions
electricity.
• The biomass supply in 4 of the 5 net-zero scenarios consists of agricultural and forest residues, plustransitioning land area growing corn for ethanol to growing perennial grasses or equivalent for energy.*
This supply scenario thus includes no conversion of land currently used for food or feed production.
• The high biomass supply case (E- B+ scenario) assumes all biomass identified in the US Department ofEnergy’s “Billion Ton Study” is available for energy; this involves some food agricultural land being
converted to energy crops.
• Starting in the 2030s, H2 from biomass with capture of CO2 that is permanently sequestered is a highly
cost-competitive technology option because of the high value of the associated negative emissions;
negative-emissions bio-electricity is less valued because of abundant low cost of solar and wind electricity.
200* The average rain-fed harvestable yield (t/ha/y, dry basis) of perennial energy grasses on former corn-growing land assumed in the modelinghere is about ¾ of today’s U.S. average whole-plant yield for corn. Conceptually, therefore, the biomass assumed to be supplied from converted
corn-growing lands could equivalently be whole-corn-plant biomass with ¼ of the material left on the field for soil maintenance purposes.

RETURN TO
TABLE OFCONTENTSKey zero-carbon fuels and feedstocks
1. Fossil-derived fuels withnegative emissions offsets

3. Drop-in liquid &gaseous fuels madefrom biomass orsynthesized fromH2 + captured CO2

201

Zero-carbon &negative-carbon
fuel & feedstock
options

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2. Hydrogen made frombiomass, NG w/CCS, orelectrolysis and useddirectly or as hythane(blend of H2 + CH4)

Use of fuels decreases substantially in all scenarios, and by 2050
zero-carbon fuels and feedstocks come from a diversity of sources
Zero-carbon fueloptions include
1. Fossil fuels plus
negative emission
offsets
2. Hydrogen madefrom biomass, NG
w/CCS, orelectrolysis
3. Synthesized fuels(from biomass or
H2 + captured CO2)

Note: All fuelvalues reported inthis slide pack are
on HHV basis.

202

Mix of fuels and feedstocks by sourceEssentially all available biomass is used in 2050. Rapid growth
after 2030. H2 from biomass with CO2 capture is a key technology.
Biomass use by technology, EJ

Biomass-energy
conversion technologies

Maximum biomass
available in the scenario

BECCS-H2 is favored by:- High marginal CO2 emissions
prices ($300 - $400/t by 2050).
- Higher value of biofuel vs.
biopower.
- Highest energy delivered perunit CO2 captured among all
biofuel options.

203

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Note: All fuel values reported in this slide pack are on HHV basis.

High marginal CO2 emission prices benefit negative emissions
technologies & explain preference for biomass use in BECCS-H2

E+RE+

204

Notes:
1) These prices represent overall supply-side system costs
Efor reducing CO2 emissions by one additional tonne.
They do not take into consideration demand-side costs
E+REsuch as added costs for transport electrification in E+
compared with E-. As such, these prices should be
E-B+
interpreted as lower bound estimates of economy-wide
carbon emission prices.
2) For E+RE-, the main factors contributing to the nonmonotonic behavior from 2025-2035 are: (i) theE+
exogenously imposed linear net-emissions reduction
trajectory requires significant reductions by 2030, (ii)the limit on solar and wind power generation build
rates means more nuclear and NG-CCS need to beinstalled; and what can be built of these by 2030 iscostly, (iii) post-2030, things get easier because more
nuclear and CCS can be built at lower cost, and theelectrification of vehicles and buildings that started
slowly in the 2020s (limited by stock turnover rates)
begins to more significantly reduce fuel demands.
3) For E+RE+, no value is shown for 2050, because theconstraint prohibiting fossil fuel use in 2050 is morebinding than the annual emissions constraint, implyingthat the carbon price would (unrealistically) be zero in
2050.

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Higher biomass supply potential results in more biomass use forelectricity and hydrogen generation
Biomass is a key resource in most scenarios.
•

With the lower biomass supply potential,
all available biomass is utilized in all 5
scenarios shown here, including E-RE(run as a sensitivity to E+RE-).

•With the high biomass supply potential :•all available biomass is used in EB+ and E-RE-B+ cases, which
underlines the importance ofelectrification in reducing relianceon biomass in net-zero pathways.

•

Most of the additional biomass in
E+RE-B+, E+RE+B+, and E-RE-B+
is used to produce additional
negative emissions via power
generation or H2 production.

Input assumptions that vary between cases

Biomass potential (by 2050)

205

E+, E-, E+RE-, E+RE+

E+B+, E-B+, E+RE-B+, E+RE+B+

0.7 Gt/y (13 EJ)

1.3 Gt/y (24 EJ)

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If no new biomass use is allowed, more oil and gas are used anddirect air capture and sequestration of CO2 increase to compensate
HydrogenUses

For the E+ case with no new biomass (E+ B-, upper panel)• electrolysis and natural gas reforming with CO2 capture offset
the loss of H2 production from biomass.
• DAC use increases dramatically to offset the added emissions
from greater natural gas use and negative emissions from
BECCS. Stored CO2 increases.
• 30-yr NPV of energy-supply system costs increase ~5%.

Input assumptions that vary between cases

206 Biomass potential (increase from today to 2050)

E+

E+ B-

E+ RE-

E+ RE-B-

0.7Gt/y0 Gt/y0.7Gt/y0 Gt/y

E+B-

E+

E+B-

E+

E+B-

E+RE-

E+RE-B-

E+RE-

E+RE-B-

E+RE-

E+RE-B-

Production

2050

E+

Uses

For E+RE- with no new biomass (E+RE- B-, lower panel)• More hydrogen is produced and all by natural gas reformingwith CO2 capture. More H2 is used for power generation andindustrial steam generation; less for liquid fuels synthesis.
• DAC deployments starts in the early 2030s and ramps up
dramatically by 2050, along with CO2 capture from gas-fired
power plants.
• CO2 storage nearly doubles relative to E+ RE-.
• 30-yr NPV of energy-supply system cost increases by ~25%.

Biomass

Production

Not allowing new biomass removes a key pathway for making
net-zero or net-negative emission fuels and leaves only direct
air capture (DAC) as an option for achieving negative emissions:Captured CO2

Higher capital costs for biomass conversion to hydrogen drives
more biomass use for electricity, but not for bio-derived liquid fuels• Neither higher nor lower biomass-FT costs
impacted results, because other routes to liquid
fuels are less costly for meeting liquid fueldemands within carbon emission constraints.

EJ

Gasification-based integrated biomass conversion
to Fischer-Tropsch fuels or H2 with CO2 capture
are pre-commercial technologies, with inherently
uncertain capital costs for future commercialscale plants. Sensitivity runs tested the impact of
50% higher and 20% lower assumed capital costs
for these technologies:• A similar result is observed with lower capitalcosts for biomass-H2 with CO2 capture.
• But with higher costs for biomass-H2, biomass
use shifts away from H2 production to electricity
generation with CO2 capture. Notably, biomassFT technology is still not deployed even in thiscase.
Input assumptions that vary between cases• The 30-yr NPV of energy-supply system costs
are similar for all cases shown here
207$/kWout,HHV in 2050

E+

E+ BioFT+

E+ BioFT-

E+ BioH2+

E+ BioH2-

BECCS-H2 capital cost

2700

2700

2700

4050

2160

Biomass FT capital cost

3962

5984

3172

3962

3962

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Spatial downscaling and analysis of bioenergy production and use in
the E+ pathway
Summary of this section• For the E+ pathway, the geographic distribution of agricultural and forestry residues used for energy isbased on county-level projections from the “Billion Ton Study”. Land transitioned from growing corn forethanol to growing perennial grasses or equivalent for energy is assumed to be distributed among counties
in proportion to their corn production level in 2018.*• Transporting biomass long distances to conversion facilities is costly, so our downscaling approach uses thecounty-level biomass supply estimates to establish 100 mile x 100 mile cells, within each of which all
available biomass is assumed to be used in conversion facilities located in that cell. Each bioconversion
facility, regardless of technology, is assumed to have an input capacity of 0.7 million t(dry)/y of biomass.
• Bioconversion capacity within a given RIO modeling region is deployed first in cells within that region thathave the highest biomass supply density (as a surrogate for lowest biomass feedstock cost), and facilities
that capture CO2 are sited near CO2 storage reservoirs or pipelines (see CO2 pipeline maps later).
• Bioconversion facilities are sited primarily in states in the upper Midwest and secondarily in the Southeast.
• The cumulative investment in bioconversion capacity to 2050 is about 750 B$ nationwide, and farmer
revenues from sale of biomass for energy are more than double today’s revenues for corn sold into ethanol
production.

208* The average rain-fed harvestable yield (t/ha/y, dry basis) of perennial energy grasses on former corn-growing land assumed in the modeling here
is about ¾ of today’s U.S. average whole-plant yield for corn. Conceptually, therefore, the biomass assumed to be supplied from converted corngrowing lands could equivalently be whole-corn-plant biomass with ¼ of the material left on the field for soil maintenance purposes.

RETURN TO
TABLE OFCONTENTSE+ Scenario: Biomass supply with no increase in land use forenergy. Midwest and Southeast are largest sources.
CRP -> energy grasses

2050 biomass availability, 100 x 100 mi cells(based on county-level projections)2050 supply
by resource(13 EJ total)

ForestResidues

Note: All fuel values reported inthis slide pack are on HHV basis.

209

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Wastes2050 biomass cost-supply
woody residues
herbaceous
wastes($100 per tonne = $5 per GJ)

Energy grasses (orequivalent) grown on
former ethanol-corn land

Supply (106 metric t/yr)

CRP land

Delivered cost, 2016 USD/t

Crops
Residues

Ethanol-cornland -> energy
grasses (orequivalent)Evolution of the bioconversion industry, E+ scenario
2025

Total annual nonfood biomass use:
- 44 million t- 0.9 EJ*
210

* Other includes a collectively small level of biomass converted to diesel and synthetic methane(with or without CO2 capture) and/or electricity (without CO2 capture).

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TABLE OFCONTENTSEvolution of the bioconversion industry, E+ scenario
2030

Total annual nonfood biomass use:
- 79 million t- 1.6 EJ*
211

* Other includes a collectively small level of biomass converted to diesel and synthetic methane(with or without CO2 capture) and/or electricity (without CO2 capture).

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TABLE OFCONTENTSEvolution of the bioconversion industry, E+ scenario
2035

Total annual nonfood biomass use:
- 145 million t- 2.9 EJ*
212

* Other includes a collectively small level of biomass converted to diesel and synthetic methane(with or without CO2 capture) and/or electricity (without CO2 capture).

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TABLE OFCONTENTSEvolution of the bioconversion industry, E+ scenario
2040

Total annual nonfood biomass use:
- 223 million t- 4.4 EJ*
213

* Other includes a collectively small level of biomass converted to diesel and synthetic methane(with or without CO2 capture) and/or electricity (without CO2 capture).

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TABLE OFCONTENTSEvolution of the bioconversion industry, E+ scenario
2045

Total annual nonfood biomass use:
- 375 million t- 7.4 EJ*214

* Other includes a collectively small level of biomass converted to diesel and synthetic methane(with or without CO2 capture) and/or electricity (without CO2 capture).

RETURN TO
TABLE OFCONTENTSEvolution of the bioconversion industry, E+ scenario
2050

Total annual nonfood biomass use:
- 618 million t- 12.2 EJ# of plants (1020 total)
600

563

500
400
300
200

171

161
95

100

31

*
215

* Other includes a collectively small level of biomass converted to diesel and synthetic methane(with or without CO2 capture) and/or electricity (without CO2 capture).

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750 B$ capital invested in bioconversion by 2050, largely in Midwest
and Southeast. Biomass purchases grow, displacing corn for ethanol.
Capital invested (B$)*

Biomass purchases (B$/y)

Corn (for eth.) purchases (B$/y)
2030

2020s

22 B$

2.4 B$/y

19 B$/y

2040

2030s

182 B$

13 B$/y

10 B$/y

2050

2040s
216

* In plants coming online in indicated decade.

542 B$

42 B$/y

0 B$/yE+

Spatial downscaling and analysis of bioenergy production and use in
the E- B+ pathway
Summary of this section• For the E- B+ pathway, the geographic distribution of biomass supplies, including dedicated energy crops
grown on converted food-agriculture land, is based on county-level projections from the “Billion Ton Study”.
Additionally, production of dedicated energy grasses on lands converted from growing corn for ethanol isassumed to be distributed among counties in proportion to their corn production level in 2018.
• Transporting biomass long distances to conversion facilities is costly, so our downscaling approach uses thecounty-level biomass supply estimates to establish 100 mile x 100 mile cells, within each of which all
available biomass is assumed to be used in conversion facilities located in that cell. Each bioconversion
facility, regardless of technology, is assumed to have an input capacity of 0.7 million t(dry)/y of biomass.
• Bioconversion capacity within a given RIO modeling region is deployed first in cells within that region thathave the highest biomass supply density (as a surrogate for lowest biomass feedstock cost), and facilities
that capture CO2 are sited near CO2 storage reservoirs or pipelines (see CO2 pipeline maps later).
• Bioconversion facilities are sited primarily in states in the upper Midwest and secondarily in the Southeast.
• The cumulative investment in bioconversion capacity to 2050 is 1.4 T$ nationwide, and farmer revenues
from sale of biomass for energy are more than quintuple today’s revenues for corn sold into ethanol
production.

217

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E- B+ Scenario: Biomass supply is nearly doubled via conversionof some pasture and cropland to energy crops.
Pasture -> woody
energy crops

2050 biomass availability, 100 x 100 mi cells(based on county-level projections)

Cropland-> woody
energycrops

2050 supply
by resource(24 EJ total)

Pasture ->energygrasses

CRP ->
energygrassesEthanolcorn land-> energy
grasses (orequiv.)
Wastes

Cropland ->energy grasses

Crops
Residues

Note: All fuel values reported inthis slide pack are on HHV basis.

218

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Delivered cost, 2016 USD/t

ForestResidues

2050 biomass cost-supply($100 per tonne = $5 per GJ)

woody residues
herbaceous
wastesSupply (106 metric t/yr)

Bioconversion industry, E- B+ scenario
2050

Total annual nonfood biomass use:
- 1,153 million t- 22.8 EJ# of plants (1,760 total)
1000
900

858

800
700
600
500

413

400
300
200

178

154

119

100

*
219

* Other includes a collectively small level of biomass converted to diesel and synthetic methane(with or without CO2 capture) and/or electricity (without CO2 capture).

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1.4 T$ capital invested in bioconversion by 2050, largely in Midwest
and Southeast. Biomass purchases grow, displacing corn for ethanol.
Capital invested (B$)*

Biomass purchases (B$/y)

Corn (for eth.) purchases (B$/y)
2030

2020s

64 B$

7.0 B$/y

19 B$/y

2040

2030s

601 B$

58 B$/y

10 B$/y

2050

2040s
220

* In plants coming online in indicated decade.

707 B$

116 B$/y

0 B$/yE- B+

Hydrogen production and use
Summary of this section• In the net-zero models, H2 can be made by reforming natural gas (without or with CO2 capture), gasifying
biomass (with CO2 capture), or electrolysis of water. E+, E-, and E- B+ all favor H2 from a mix of biomass
and electrolysis. H2 from natural gas is prominent in E+ RE-, because electrolysis is less cost effective. In E+
RE+, electrolysis dominates by 2050 because fossil fuel use is disallowed and most biomass is converted
into pyrolysis oils used for petrochemicals production.
• As a final energy, H2 is used in fuel cell trucks and for producing ammonia and other chemicals, direct
reduction of iron, and industrial heating. As an intermediate energy, H2 is an input to synthesis ofhydrocarbon fuels, and a small amount supplements natural gas use in gas turbine power generation.
• High-resolution design and mapping of future H2 systems was not done (except for biomass H2, as above),but coarse (14-region) analysis for E+ gives an indicative 2050 snapshot of possible future geographic
distribution of this industry: H2 systems begin expanding substantially only starting in the mid-2030s,
reaching total H2 volumes in 2050 more than six times H2 flows in the U.S. today. In E+ RE+, H2 flows are
more than twice as large, with most H2 used with captured CO2 to synthesize hydrocarbon fuels.
• Many industrial H2 users would likely produce H2 onsite, as happens today. Distributed users might beserved by regional pipeline networks and/or truck delivery, as is also the case in some regions today.
Vignettes of notional future industry-serving regional H2 pipelines are sketched to illustrate.
221

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8 to 19 EJ of H2 are produced in 2050, with volume flows of
0.8x to 2.2x today’s U.S. natural gas use (35 EJ) at pipeline pressure
H2 sources
ATR = autothermal reforming of natural gas with CO2
capture.
BECCS = biomass gasification to H2 with CO2 capture(negative net emissions).
Electrolysis = water splitting using electricity.

H2 uses
Electricity = H2 burned in gas turbines in high “hythane”
blend with CH4 (60% limit by energy).
Pipeline gas = H2 used for “hythane” blend in CH4
pipelines (7% limit by energy).
H2 boiler = industrial steam generation.
Synthetic gas = CH4 synthesis from H2 and CO2.
Synthetic liquids = Fischer Tropsch fuels from H2 + CO2.
Demand side = H2 used in transport and for productionof chemicals, direct-reduced iron, and process heat invarious industries.
222

Note: All fuel values reported in this slide pack are on HHV basis.

Model outputs are impacted by cost/availability assumed for H2
production and related fuels-synthesis technologies.
Compared with E+:• If electrolysis is disallowed, total H2 produced
is 35% lower, while H2 from natural gas(ATR-CCS) doubles. Synthetic liquids
production is much lower. Direct air capture
is deployed to offset residual emissions fromgreater ATR and use of more petroleum fuels.
• Higher bio-H2 drives biomass use from H2production to electricity generation with CO2
capture. More gas is used for H2 production,ands synthetic liquids output falls modestly.
• Results are relatively insensitive to different
ATR costs.
• Higher FT synthesis cost reduces output ofH2 and synthetic liquids by ~25%. Lower FT
synthesis cost increases H2 from biomass andvia electrolysis.
• NPV of total energyInput assumptions that vary between cases, installed capital cost in 2050 (2016$)
supply system costs
E+
E+ No Electrolysis
E+ BioH2+
E+ BioH2$/kWH2 (HHV)(2020-2050) are
2700
2700
4050
2160
BECCS-H2
about the same for ATR-CCS (H2 from nat. gas) 814
814
814
814
all cases shown.
FT (Fischer-Tropsch) synth.
1155
1155
1155
1155
223

Electrolysis

420

not allowed

420

420

2050

E+ ATR+

E+ ATR-

E+ Synfuel+

E+ Synfuel-

2700

2700

2700

2700

1221

651

814

814

1155

1155

1732

924

420

420

420

420

By 2050, H2 production in E+ scenario reaches 8 EJ, or
61 billion scf/day (~6x today’s level).
Majority of hydrogen users would be co-located with production, but distributed users would beserved by regional pipeline networks or truck delivery.
Hydrogen Sources
8

H2 Production, EJ

7
69Electrolysis

8

Biomass with ccus
Autothermal reforming with ccus

H2 Utilization, EJ

9Hydrogen Uses

Steam methane reforming

5

Other industry
Direct reduction of iron7

As pipeline gas (< 7% H2 by energy)

6

Gas turbine fuel (< 60% H2 by energy)

5Industrial boilers
Bulk chemicals

4

Medium & heavy vehicles

3

3

Liquid fuel synthesis

2

2

1

1

4

0

0

2020

2025

2030

2035

2040

2045

2050

2020

2025

Note: All fuel values reported in this slide pack are on HHV basis.

224

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2030

2035

2040

2045

2050

Large H2-using synfuels industry operating in 2050, primarily inUpper Midwest, but also New York/New England (E+ scenario)

Note: All fuel values reported in this slide pack are on HHV basis.

225

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Industrial H2-using clusters operate today in U.S. and elsewhere.
Here, Air Products & Chemicals Gulf Coast H2 infrastructure.
• A total of about 2,500 km of H2 pipelines are in service in the US today• The most significant H2-using clusters today are on the Gulf Coast

Source: Air Products & Chemicals, 2012.

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Notional view of H2 production and use on the Gulf Coast, 2050
Large industrial
facilities (2017)

Texas

Louisiana

H2 production, 2050 E+
Biomass with CO2 capture
Natural gas with CO2 capture

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Notional view of H2 production and use on the Gulf Coast, 2050
Texas

228

Louisiana

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Notional view of H2 production and use on the Gulf Coast, 2050
Large industrial
facilities (2017)

Texas

Louisiana

H2 production, 2050 E+
Biomass with CO2 capture
Natural gas with CO2 capture

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Notional view of other potential H2 production and use clusters
2050 H2 supply system (E+)
H2 production from biomass with CO2 capture
H2 production from natural gas with CO2 capture
H2 trunk pipeline
H2 spur pipeline
Large industrial
facilities(2017)

North
Carolina
South
Carolina

Atlantic
Ocean

Lake Michigan

Ohio
Pennsylvania

Illinois

230

West Virginia

Indiana

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Pillar 4: CO2 capture, transport, usage, and geologic storage
Summary of this section

231•

CO2 capture and utilization is deployed at large scale in all NZA scenarios. Capture, utilization, and storage (CCUS) is
deployed at large scale in all NZA scenarios, except RE+.

•

CCUS is deployed on cement production, gas- and biomass-fired power generation, natural gas reforming, biomass
derived fuels production, and in some cases from direct atmospheric air capture.

•

Geological sequestration rates range from almost 1 to 1.7 billion tonnes of CO2 per annum, servicing more than athousand capture facilities distributed across the nation by 2050.

•

The majority of geologic sequestration takes place in the Texas gulf coast but other basins host sequestration of 10’s tomore than 100 million tonnes of CO2 per year.

•

An investment of 13 B$ is estimated for stakeholder engagement and characterization, appraisal and permitting acrossmultiple storage basins and sites before 2035 to enable rapid expansion thereafter.

•

The CCUS industry is enabled by around 110,000 km of new CO2 pipeline infrastructure with an estimated capital costof $170 to $230 billion.

•

Estimated unit costs for CO2 transport and storage average $17 to $23 per tonne stored depending on the ultimate scaleof deployment.

•

The scale of CO2 transport and storage in these scenarios ranges from 1.3 to 2.4 times current US oil production on a
volume equivalent basis.

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CO2 capture at multiple facility types and some CO2 utilization in all
pathways; significant CO2 storage in all but one pathway
By 2050
CO2 sources• 0.7 to 1.8 Gt/y CO2 captured.
• 0.9 to 1.7 Gt/y CO2 sequestered.
• 0.1 to 0.7 Gt/y CO2 converted to fuels.

CO2 sources
Direct air capture
Natural gas hydrogen (autothermal reforming)
BECCS electricity (gasifier-Allam cycle)
Natural gas electricity (Allam cycle)
BECCS hydrogen (gasifier/water gas shift)
BECCS pyrolysis (hydrocatalytic)
Cement via 90% capture (post-combustion).

CO2 uses
CO2 uses
Synthetic liquids = synthesis of fuels from H2 + CO2.
Synthetic gas = methane synthesis from H2 + CO2.
Sequestration = geological storage

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Volumetric Production & Injection Rates*(billion cubic meters / year)

CO2 injection rates grow from small today to 27% of 2018 oil & gas
extraction rates in 2050 (at notional in situ reservoir conditions)* At notional in situ reservoir
conditions (2,000 m depth)

Years (1994-2019 for oil & gas; 2025-2050 in E+ scenario for CO2)
Oil & gas production data from BP Statistical review of Energy

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CO2 transportation network combines state-of-art understanding ofstorage basins and geospatial downscaling of CO2 point sources.
1.

The most prospective CO2 storage basins chosen based on practicable storage capacity (accessible,
sustainable annual injection rates) estimates after Teletzke et al. (2018).
2. Notional supply-cost curve for CO2 transport and storage established using expert judgement andindustry consultation (BP, ExxonMobil, Occidental), assuming shared transport infrastructure.
3. Rio Model chooses CCS to mitigate emissions from power sector, fuels production and industry sectors
across 14 regions, where economically competitive for scenarios that allow CCS.
4. Point sources for each sector downscaled temporally and geospatially to state/county level.
5. Notional CO2 trunk line network drawn ‘by eye’ to pick up major clusters of point sources, with build
program to deliver CO2 transport infrastructure in advance of CCS requirement.
6. Point source downscaling repeated to locate all point sources within 200 km of trunk lines.
7. Spur lines connect point sources to trunk lines using minimum distance and following existing ROWs.*
8. Trunk lines sized and costed using FE/NETL CO2 Transport Cost Model, and build-out programmed tomeet expansion of CO2 point sources for all trunk line catchment areas. Spur lines costed using asimple Cost = f(tpa, km) equation derived from the FE/NETL CO2 Transport Cost Model.
9. Levelized cost of CO2 transport established based on capital cost estimates, build schedules, and CO2
expansion using discounted cash flow model.
10. Cost-supply curves calculated for different potential capacity charge arrangements.
* Existing ROWs include natural gas, NH3 and CO2 pipelines, railways, interstate highways, and > 220kV electricity transmission lines, as mapped in Edwards
and Celia, “Infrastructure to enable deployment of carbon capture, utilization, and storage in the United States,” PNAS, 115(38): E8815-E8824, 2018.

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Notional CO2 storage capacity appraised, permitted and developedin 2050 is 1.8 billion t/y, mostly in Gulf CoastC - 100 Mtpa
0.5MTPA / well

Transport& storage($/tCO2)

F - 140 Mtpa
0.4 MTPA / well

Existing CO2
pipelines shownB - 40 Mtpa
0.5 MTPA / wellD - 80 Mtpa
0.25 MTPA / well

A2 - 1,100 Mtpa
1 MTPA / well
A1 - 140 Mtpa
2 MTPA / wellE - 60 Mtpa
0.2 MTPA / well

Gulf Coast provides 75% of annual storage capacity
EOR
million tonnes per year
235

(Selected for practicable storage capacities,
based on Teletzke et al., 2018.)

$13 Billion investment in stakeholder engagement, characterization,
appraisal and permitting activities before 2035 to enable rapid expansion
2021-25
Investment(Million $)2026-30
Investment(Million $)2031-35
Investment(Million $)Notional Capacity
Appraised(MMtpa)

1,500

1,500

Area B

0
0
0

700
4,000
100

400
2,700
100

110
670
20

Area C

0

200

300

50

Area D
Area E

0
0

200
100

200
200

40
30

Area F
Totals

0
1,500

300
7,100

500
4,400

80
1,000

Item
CO2 Basin-wide Assessments*
CO2 Site Appraisal and Permitting**
Area A1
Area A2* Estimated to be $500 million per basin (basins A – F identified in prior slide).
** See previous slide for basin labels.

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Existing CO2 pipeline network2020• ~ 80 million tCO2/yrtransported• ~ 8,500 km of pipelines• Servicing enhanced oil
recovery operations• Majority in Permian
Basin (West Texas andsoutheast New Mexico)

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Trunk line construction begins before 2025 with connection between
Permian Basin and Gulf Coast
E+ scenario
2021 - 2025
no CO2 flow in this period
700 km pipelines
Capital in-service: $70B

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Trunk line build out continues and initial CO2 capture plants comeonline, with spur lines connecting to trunk network
E+ scenario
2026 - 2030
65 million tCO2/y
19,000 km pipelines
Capital in-service: $70B

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Trunk network routes complete; some sections add parallel lines as
more capture projects are built and connect
E+ scenario
2031 - 2035
246 million tCO2/y
41,000 km pipelines
Capital in service: $115B

240

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More individual trunk line duplications as number of capture
projects continues to growE+ scenario2036 - 2040
435 million tCO2/y
51,000 km pipelines
Capital in service: $125B

241

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CO2 capture plants connected to trunk lines grow rapidly
E+ scenario

2041 - 2045

687 million tCO2/y
70,000 km pipelines
Capital in service: $135B

242

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2050 totals: 21,000 km trunk lines + 85,000 km spur lines(equivalent to ~22% of US natural gas transmission pipeline total)
E+ scenario
2046 - 2050
929 million tCO2/y
106,000 km pipelines
Capital in service: $170B

Note: On a volume basis (at reservoirpressure), CO2 flow in 2050 is 1.3x current
U.S. oil production and ¼ of current oil +gas production.
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E- B+ utilizes the same trunk network, but with some additional
parallel pipes in some corridors
E- B+ scenario
2046 - 2050
1,361 million tCO2/y
111,000 km pipelines
Capital in service: $220B

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Capital for national CO2 collection and transport network is $170 to$230 billion, or ~ $11 to $16/tCO2 when amortized across all users
Costs (2020$)*

E+

E- B+

21,10025,400Total installed capital cost, billion 2020$

101

135

National network-access charge, $/tCO2 delivered

11.3

7.6

Center-East network-access charge, $/tCO2 delivered

11.3

7.4

West network-access charge, $/tCO2 delivered

11.6

10.4

85,80085,700Total installed capital cost, billion 2020$

69

88

National network-access charge, $/tCO2 delivered

4.6

3.0

15.9

10.6

Trunk lines
Total length, km

Spur lines
Total length, km

Total trunk + spur lines
National network-access charge, $/tCO2 delivered* Costs, including pipelines and compressors, were estimated using the DOE/NETL CO2 Transport Cost Model (version 2b),.

245

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Higher charge for West than forCenter-East trunk network

Amortizing investments across all users avoids prohibitively highcosts of small-capacity point sources financing their own spur lines.

CO2 Transport Cost ($/tonne)

Rapidly rising transport costs for smaller
point sources with longer spur lines
CO2 transport costs(E+)

CO2 transport costs(E- B+)

CO2 Transported (Mtpa)

CO2 Transported (Mtpa)

Trunk + spur line network-access charge. (All point sources charged equally, regardless of scale, location, or on-stream date.)
Trunk line network-access charge. (All point sources charged equally, regardless of scale, location, or on-stream date.)
Cost-supply curve assuming trunk line network-access charge + spur line investment by individual point sources.

246

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Storage adds $7/tCO2 (DOE low-end estimate) and EOR provides
credit of $19/tCO2 (for $50/bbl oil*).

CO2 Transport & Storage Cost, $/t

E+

CO2 transport and storage costs
calculated from the downscaling analysis
are somewhat lower than the costs
assumed in the original modeling of E+
pathway.

Transport and storage cost assumed for 2050 inoriginal modelling of E+ pathway
Calculated trunk + spur line network-accesscharge. (All point sources charged equally,
regardless of scale, location, or on-stream date.)
Calculated assuming trunk line national networkaccess charge + spur line investment by individual
point sources.

0
CO2 Stored (Mtpa)* Rubin, et al. (2015) wrote that “conventional wisdom suggests that the price that EOR
projects can afford to pay for CO2 (in $/1000 standard ft3) is 2% of the oil price in $/bbl.”

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Pillar 5: Reduced non-CO2 emissions
Summary of this section• In a net-zero future, non-CO2 greenhouse gas emissions each year must be compensated by removal of anequivalent amount of CO2 from the atmosphere. In the modeling here, negative emissions can be achievedby permanent storage underground (or in long-lived plastics or similar products) of CO2 derived frombiomass or directly captured from the air, or (as discussed later below) by uptake in soils and trees.
• Sources of methane and nitrous oxides, which are the majority of non-CO2 emissions today, are widelydispersed, making mitigation more challenging, and non-CO2 emissions are projected to grow in the future
under business-as-usual.
• The Net-Zero America study team did not conduct original analysis assessing mitigation options, but
assumed as an input to the modeling a level of mitigation from 2020 to 2050 consistent with recent analysis
from the U.S. Environmental Protection Agency (EPA).
• We also note that EPA’s mitigation estimates assume future levels of oil and gas use that are closer to thoseof a “business-as-usual” future than a net-zero emissions future. In the latter, fossil fuel use is at least 70%
to 80% lower today by 2050. The EPA projections assume some mitigation of non-CO2 emissions associatedwith producing and transporting fossil fuels. Under a net-zero scenario, these emissions would besignificantly lower due to the reduced fossil fuel use.

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Non-CO2 emissions today are 1.25 GtCO2e/year

U.S. Non-CO2 Greenhouse Gas Emissions,2018(Million
metric tons CO
U.S. Non-CO
Gas2e)Emissions, 2018
2 Greenhouse(Million metric tons CO2e)Natural Gas &Oil Systems
CH4 (183)

Other
N2O
(97)

Soil
Management
N2O (338)

Enteric
Fermentation
CH4 (178)
Landfill
CH4 (111)

Other
FluorinatedGases (11)HFCs (170)

Other CH4 (43)Coal Mining
CH4 (59)
Manure Managemet
CH4 (62)

Source: EPA, 2020 GHG Inventory

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Methane emissions follow energy and agricultural production
patterns and population densities
Agriculturalemissions are
dominated bylivestock anddairy
production

Oil and gas
upstream
emissionsalign withproduction &processing;
downstream
with pop.

Waste
emissions arealigned withpopulation
density

Coal
upstream
emissions are
dominated by
Appalachiansubsurface
mining.

Source: EPA

250

2012 emissions (tCH4/km2)(All emissions in the National GHG Inventory)

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N2O emissions occur mostly outside of the energy sector and instates with significant agricultural production.
N2O emissions from agriculture plus production of adipic and nitric acids (2018)

N2O emissions(2018)
Agricultural soil management

251

MilliontCO2e
338

Manure management

19

Adipic & nitric acid production

20

Stationary & mobile combustion

44

Other

15

Total

436

shown
on mapNote: 10.4 mmtco2e inFlorida in 2018 (> 80% of
Florida’s N2O emissions)were attributed to one acidproduction facility.

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Without mitigation efforts, non-CO2 emissions grow gradually to
1.45 GtCO2e by 2050, with CH4 and N2O contributing most
1500
1400
1300
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
1990

projected

F-gases

Nitrous oxides

Methane

2000

2010

2020

2030

2040

2050

1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050

Non-CO2 Emissions(million metric tCO2e)

Historical and projected non-CO2 emissions by gas type under business as usual (BAU)

Source: EPA, Global Non-CO2 Greenhouse Gas Emission Projections & Mitigation, Oct. 2019.

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Without mitigation, non-CO2 emissions grow gradually to 1.45
GtCO2e by 2050, with agriculture and energy remaining dominant
1500
1400
1300
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
1990

projected

Waste
Industrial processes
EnergyAgriculture

2000

2010

2020

2030

2040

2050

19
90
19
92
19
94
19
96
19
98
20
00
20
02
20
04
20
06
20
08
20
10
20
12
20
14
20
16
20
18
20
20
20
22
20
24
20
26
20
28
20
30
20
32
20
34
20
36
20
38
20
40
20
42
20
44
20
46
20
48
20
50

Non-CO2 emissions(million metric tCO2e)

Historical and projected non-CO2 emissions by sector under business as usual (BAU)

Source: EPA, Global Non-CO2 Greenhouse Gas Emission Projections & Mitigation, Oct. 2019.

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Mitigation can reduce non-CO2 emissions substantially by 2030
2030 Non-CO2 Emissions (MtCO2e)

By 2030, EPA projects:

1,400• Under EPA BAU (no mitigation), nonCO2 emissions reach 1.35 GtCO2e/yMillion metric tCO2e/y

1,200• Under E+ BAU (energy mitigation but
no non-CO2 mitigation), non-CO2
emissions fall to 1.28 GtCO2e/y as
nearly all coal production ceases andoil/gas output drops ~10%

1,000
800
600

• Very low-cost mitigation yields 1.18
GtCO2e/y while measures costing<$100/tCO2e yield 0.97 GtCO2e/y

400• Further research needed to identify
additional reductions

200
EPA BAU
Agriculture

E+ BAU
EnergyE+ & <$0/ton
Industrial Processes

E+ & <$100/ton

Waste

Source: EPA, Global Non-CO2 Greenhouse Gas Emission Projections & Mitigation, Oct. 2019, with adjustments for E+ scenario.

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Mitigation can reduce emissions to ~1 Gt per year by 2050, but
beyond that the path to deeper reductions remains uncharted
2050 Non-CO2 Emissions (MtCO2e)

By 2050, EPA projects:

1,400• Under EPA BAU (no mitigation), nonCO2 emissions reach 1.45 GtCO2e/yMillion metric tCO2e/y

1,200• Under E+ BAU (energy mitigation but
no non-CO2 mitigation), non-CO2
emissions fall to 1.22 GtCO2e/y as
nearly all coal production ceases andoil/gas output drops ~75%

1,000
800
600

• Very low-cost mitigation yields 1.11
GtCO2e/y while measures costing<$100/tCO2e yield 0.90 GtCO2e/y

400• E+ scenario assumes non-CO2abatement efforts yield~1 GtCO2e/y by 2050

200
EPA BAU
Agriculture

E+ BAU
EnergyE+ & <$0/ton
Industrial Processes

E+ & <$100/ton
Waste

Source: EPA, Global Non-CO2 Greenhouse Gas Emission Projections & Mitigation, Oct. 2019, with adjustments for E+ scenario.

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Non-CO2 emissions are reduced to 1 GtCO2e by 2050, or ~20%
below 2020 and ~30% below BAU 2050 forecast from EPA.
Estimated abatement potential by 2050 @ < $100/tCO2e avoided
2050 Abatement(106 tCO2e/y)

SourceAgriculture

EnergyIndustrial

Waste

Croplands/Rice11

Livestock

49

Coal

5

Oil and gas

48

Nitric & Adipic Acid Production (N2O)

36

Refrigerants/AC (F-gases)

146

Other

9.0

Landfill

13
Total

Non-CO2 Abatement Potential:• Mitigation measures costing<$100/tCO2e can drive non-CO2
emissions from 1.45 to 0.90
GtCO2e/y by 2050
• F-gases account for nearly half of
this mitigation potential

316

Source: EPA, Global Non-CO2 Greenhouse Gas Emission Projections & Mitigation, Oct. 2019, but with coal and oil and gas adjustments to reflect E+ scenario:
coal abatement is limited to mitigation of abandoned mines and oil/gas abatement is reduced by ~75% to account for lower oil production under E+.

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Pillar 6: Enhanced land sinks
Summary of this section• Land carbon sinks, i.e., annual removal of carbon from the air and permanent storage in soil or trees, arecritical for net-zero emission scenarios, because they offset positive greenhouse gas emissions from
elsewhere in the economy.
• In the cost-minimized net-zero scenarios developed in this study, the last unit of CO2 emission avoided fromthe energy/industrial system is the most expensive one to avoid. Thus, land sinks avoid using the most
costly measures for CO2 emissions reductions in the energy/industrial system.
• There is uncertainty about what the magnitude of the U.S. land since is today, but 0.7 GtCO2eq/y is thought
to be a reasonable estimate, and there is an expectation that the natural land sink will weaken in the future
to as low as 0.3 Gt/y by 2050 due to maturing of forest regrowth in the U.S.
• Geographically-resolved analysis by Net-Zero America researchers estimates a technical potential forenhanced land sinks by 2050 of up to 0.2 GtCO2eq/y in agriculture and from 0.5 to 1.5 GtCO2eq/y in forestry.
• The net-zero modeling in this study assumes the land sink grows to 0.85 GtCO2eq/y by 2050, which implies aconcerted effort to deploy agricultural and/or forestry land sink enhancement measures.

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Extent of carbon uptake in soils and trees impacts thedecarbonization challenge for the energy/industrial system

Million metric tCO2eq

US Land Use/Land-Use Change & Forestry (LULUCF) Emissions

100
0
-100
-200
-300
-400
-500
-600
-700
-800
-900
1990

• The current natural land sink is uncertain, butestimates are in the range of -0.7 GtCO2e/y.

LULUCF Emissions
Net LULUCF change
LULUCF Carbon stock change

2000

2010

• Without efforts to enhance the natural land sink,
it is projected to decline to -0.3 GtCO2e/y by2050.
• Significant modification of agricultural andforestry practices, if widely adopted, can help
maintain/enhance the land sink.

2020(EPA, 2020 GHG Emissions Inventory)

2050

258

E+ (and other scenarios)

Land sink, GtCO2e/y (assumed)- 0.85

Non-CO2 emissions, GtCO2e/y (assumed)

1.02

Energy/industry emissions, GtCO2/y- 0.17

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Non-CO2 emissions and land carbon sinks impact the costs andemissions reduction efforts needed in the energy/industrial system
To reach net-zero emissions economy wide in 2050, emissions“allowed” by the energy/industrial system in 2050 depend on the
net emissions occurring outside of energy/industry, i.e., land sinks
and non-CO2 emissions. The degree of net land sinks + non-CO2
emissions that will be achieved is uncertain. Compared with E+:•

If the net outside emissions are higher (E+ Land-), electricity
generation is much higher by 2050, with most of the increase
being solar and wind. Electrolytic H2 production is also higher,
deployment of direct air capture is significant, and about 60%
more CO2 sequestration is required. NPV of the total energysupply system (2020 – 2050) increases by 3%.

•

If the net outside emissions by 2050 are lower E+ Land+), lesstotal electricity is needed in 2050, and a greater fraction comesfrom NGCC without CC. There is also less H2 demand because
more petroleum-derived fuels can be used. NPV of the totalenergy-supply system (2020 – 2050) decreases by 2%.
Input assumptions that vary between cases

259

Billion metric tCO2e in 2050

E+

E+ Land+

E+ Land-

Land sink- 0.85- 1.30- 0.30Non-CO2 emissions

1.02

1.02

1.02

Net emissions outside of energy/industry system

0.17- 0.270.73

Allowed energy/industrial CO2 emissions in 2050

- 0.170.27- 0.73

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Agricultural measures can yield > 200 million tCO2e/y ofadditional carbon storage in soils by 2050*
With 100% adoption of conservation measures

E- B+

E+
106 ha106 tCO2e/y

106 ha106 tCO2e/y

Ethanol-corn land à perennial energy grasses

11

23

11

23

CRP area converted to perennial energy grasses

12

0

12

0

perennial energy grasses

0

0

10

16

woody energy crops

0

0

1

no estimate

permanent herbaceous cover

13

7

12

7

Pasture converted to perennial energy crops

0

0

15

no estimate

Other croplands remaining as cropland

136

204

127

189

Pasture remaining as pasture155

no estimate

140

no estimate

Totals

327

234

327

233

Other croplands converted to* See Swan, et al. (Annex Q).

260

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Maximum annual carbon uptake potential on agricultural lands bycounty; Midwestern states account for >80% of the potential.
Carbon storage across all
agricultural lands (160 million ha)

Carbon storage on ethanol-corn land
converted to energy grasses (11 Mha)

1000 tCO2e/y1000 tCO2e/y

Total U.S. potential: 230 million tCO2e

Total U.S. potential: 23 million tCO2e

See Swan, et al. (Annex Q).
261

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Top 20 states account for > 85% of the carbon storage potential
on agricultural lands in 2050 (E+ scenario)
Most of the potential is in measures applied to cropland, with carbon storage per acre averaging
1.5 tCO2e/ha); ethanol-corn land conversion to energy grasses is highest (2.1 tCO2e/ha).
Annual C Storage & GHG Emission Reductions

National Totals

262

RETURN TO TABLE OF CONTENTSLand area impacted

National Totals

Technical potential for carbon uptake by forest measures is
estimated to be 0.5 to 1.5 GtCO2e/y.*High
Low
Estimate Land area affected
Estimate
Activity(million ha)(GtCO2e/y) (GtCO2e/y)
Reforestation of agricultural lands (a)
0.141
0.506
9 – 34
Croplands
0.121
.242
8 – 16
Pasture0.020.264
1.3 – 17.5
Improved forest management
0.250
0.644
112 – 297
Accelerate regeneration
0.025
0.049
4–8
Restore productivity of degraded forests
0.060
0.178
36 – 154
Extend rotation lengths
0.116
0.302
59 – 154
Improve productivity of plantations
0.029
0.057
11 – 21
Increase stocking of trees outside forests
0.021
0.060
3–6
Increased C retention in harvested wood
0.100
0.300
n/a
Reduced deforestation
0.014
0.084
11
Total potential
0.500
1.53
132 – 342(a) Agricultural lands that are assumed to otherwise be enrolled as Conservation Reserve Program acreage.

* See Birdsey, 2020 (Annex P).
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1 GtCO2e/y technical potential for enhanced carbon storage on
forest lands (mid-range of estimates)% of state area impacted by measures to achieve technical potential*

25 states shown in the bar graph have
80% of total US technical potential264(mid-range of technical potential)* > 130 Mha, or more than ½ of all forest area, are impacted.

Six-pillars’ summary: Rapid expansion for 3 decades, such thatby 2050…
1. Efficiency & Electrification
Consumer energy investment
and use behaviors change• 300 million personal EVs• 130 million residences with heatpump heating
Industrial efficiency gains• Rapid productivity gain
• EAF/DRI steel making

4. CO2 capture & storage
Geologic storage of 0.9 – 1.7
GtCO2/y• Capture at ~1,000+ facilities• 21,000 to 25,000 km interstate
CO2 trunk pipeline network• 85,000 km of spur pipelines
delivering CO2 to trunk lines• Thousands of injection wells
265

2. Clean Electricity

3. Zero-Carbon Fuels

Wind and solar• Rapidly site 10s-100s of GW peryear, sustain for decades• 3x to 5x today’s transmission
Nuclear• In RE- scenario site up to 250 new
1-GW reactors (or 3,800 SMRs).
• Spent fuel disposal.
NGCC-CCS• In RE-, 300+ plants (@750 MW)
Flexible resources• Combustion turbines w/high H2• Large flexible loads: electrolysis,electric boilers, direct air capture• 50 - 180 GW of 6-hour batteries

Major bioenergy industry• 100s of new conversion facilities• 620 million t/y biomass feedstock
production (1.2 Bt/y in E- B+)
H2 and synfuels industries• 8-19 EJ H2 from biomass with CCS(BECCS), electrolysis, and/or
methane reforming• Largest H2 use is for fuels synthesis
in most scenarios

5. Non-CO2 Emissions
Methane, N2O, Fluorocarbons• 20% below 2020 emissions (CO2e)by 2050 (30% below 2050 REF).
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6. Enhanced land sinks
Forest management• Potential sink of 0.5 to 1 GtCO2e/y,
impacting ½ or more of all US
forest area (> 130 Mha).
Agricultural practices• Potential sink ~0.20 GtCO2e/y ifconservation measures adopted
across 1 – 2 million farms.

Implications of net-zero transitions
Summary of this section• Significant implications of transitions to net-zero emissions are illustrated quantitatively here for land use,
capital mobilization, fossil fuel industries, employment, and air pollution-related health impacts.

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Land use
Summary of this section•

267

The direct land use for wind turbine construction in net-zero scenarios is small, but the (visual) footprintof wind farms is significant. In 2050, total wind farm area is•

Smallest for the E+ RE- scenario: ~¼ million km2, or the equivalent of the combined land areas of
Illinois and Indiana.

•

Largest for the E+RE+ scenario: 1 million km2, or the equivalent of the combined land areas of
Arkansas, Iowa, Kansas, Missouri, Nebraska, and Oklahoma.

•

Direct land use for solar farms in 2050 is much smaller than the visual footprint of wind farms, ranging
from an area equivalent to the area of Connecticut for E+ RE- to that of Virginia for E+ RE+.

•The only scenario for which there is significant land-use change associated with biomass use is in theE- B+ scenario, where land area equivalent to the combined areas of Alabama and Mississippi (> ¼
million km2) is converted from food agricultural uses to dedicated cultivation of perennial energy crops.

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Total land area/visual footprint in 2050 for solar, wind, andbiomass across scenarios is 0.25 to 1.1 million km2.
[million km2]
[0.55]

U.S. land use today, Lower-48(7.7 Million km2)
Forest
2.2 Mkm2 (28%)

1.6 Mkm2 (21%)

Pasture2.6 Mkm2 (35%)

*
Urban

CroplandEquivalent land area for0.28 Mkm2 (4%)

Note: Directly impacted land area for wind farms(equipment footprint) is indicated by . For
solar and biomass, directly impacted areas are
92% and 100% of shaded area shown.

E+

Other
0.28 Mkm2 (4%)[1.0]

[0.24][0.07]

Special Use
0.68 Mkm2 (9%)

E+ RE+

E+ RE-

Note: In these maps, the sum of land
areas of colored states is roughly thesame as the area nationally of theindicated uses.

[0.26]

E268[0.47][0.70]

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E- B+* On lands converted from food production.

Capital mobilization
Summary of this section

269•

All net-zero scenarios are more capital intensive than REF scenario, and so critically depend on timely mobilization of large
sums of capital. Capital investments are long-lived, so timing of investments and divestments are critical.

•

E+ requires mobilization of about 2.6 T$ of energy supply-side risk-capital before 2030, and 10 T$ trillion by 2050 [andadditional demand-side capital investments].

•‘Risk-capital’ refers to capital committed prior to Commercial Operation Date (COD) which is exposed to various development, market,
construction and technology performance risks which could impact project cashflows and hence project valuation. These risks may limit theavailability, and increase the cost, of investment capital.

•

NZA models assume a rational and efficient market that sees investors respond instantly to incentives to mobilize capital overnight; but inreality, capital is mobilized through a sequence of decisions and activities which require considerable lead times and resources.

•

E+ requires on the order of 190 B$ of pre-FID development costs before 2030 and 600 B$ by 2050, typically spent 1-5 years inadvance of committing above multi-trillion dollar investments. These costs are fully at-risk, since as there is no guarantee that a given
project will proceed past a final investment decision (FID) to generate value, and therefore subject to availability of developer equity.

•

Net-zero scenarios are characterized by a high degree of foresight and seamless integration between sectors; but investors face deep
uncertainty around future technology costs and performance, policy priorities of future governments, investment preferences among peers,customers and competitors, and public acceptance of certain technologies.

•

Gaps between our modeling and the real world of investment decisions obscure a number of potential challenges to mobilizing risk-capitalfor project development and construction that must be mitigated through policy mechanisms to meet the 2050 net-zero target.

•

Such mechanisms include investment during the 2020’s to create real options for technologies needed post 2030, including: multiple fullscale ‘first-N-of-a-kind’ projects to de-risk and reduce the cost of less mature technologies; and investment in critical enabling
infrastructure (e.g. electricity transmission and CO2 pipelines) to serve various future supply-side investments.
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To avoid lock-in and reduce cost of transition, net-zero pathways
capitalize on timing of stock turnover for long-lived assets
Bulbs
Other appliances
Air conditioners & Heaters
VehiclesIndustrial boilers
Conventional power plants
Pipelines
2020

2030

2040

Image credit: Ryan Jones, Evolved Energy Research

270

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2050

Capital dominates energy system costs in net-zero pathways:
annualized payments on capital by 2050 are 2 to 4 times REF.
• Capital-investment decision
processes typically involve
greater pre-investment
capital-at-risk and corporate
scrutiny than operating-costdecisions.

*• The sheer number of capitaldecisions implied in thesepathways represents achallenge for the transitionschedule.
• Policy environment will be a
key determinant ofpace/scale of capital
investment.

271* Includes payments on capitalplus fixed O&M charges

Capital investments will follow risk-managed project development,
requiring time (for studies) and spending of ‘risk capital’
Project decision-gated sequence, where stages feature increasing investment to reduce risk
and uncertainty, implies that substantial sums of risk capital will need to be mobilized:
DG

FID

Decision Gate

COD

(Final Investment Decision) (Commercial Operation Date)

ClosurePermitting

DG

DG

DG

Developer equity

272

DG

Developer/Investor Equity + Debt Mix

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DG

Investor
EquityAn extensive set of activities must happen before final investment
decision (FID)• Stage-gate decisions are informed by activities, the scopes of which include, but aren’t limited to:
•
•
•
•
•

Engineering, logistics and cost estimating;
Resource characterization;
Site evaluation and selection;
Environmental and social impact assessments;
Stakeholder engagement;

•
•
•
•
•

Land access agreements
Market analysis and offtake agreements;
Technology license agreement;
EPC contract negotiations;
Permitting & licensing.

• Pre-FID activities are generally equity funded and entirely ‘at-risk’; not all proposed projects will achieve
FID, so estimation of study costs must allow for a percentage of ‘failure cases’.
• Post-FID, the majority of projects will be project financed using a mix of debt and equity; debt finance will
be subject to finance fees that must be paid before first drawdown (i.e., at FID).
• Historical experience is that depending on the risk profile, debt funds and some classes of equity
investment funds may be attracted to invest only after commercial operations have commenced (COD).
• Pre-FID investment costs, lead-times and success rates (move from FID to COD), along with construction
times for each technology were estimated on the basis of the NZA team’s industrial experience, and expert
judgement.

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Estimated project development times and pre-FID costs(Power Sector)
POWER SECTOR
Generation
Technology
biomass w cc
CCGT
CCGT w CC
CT
geothermal
nuclearoffshore windonshore windsolar pv
storage li-ion

Pre-FID Study
Time (years)
2.5
1
2.5
1
2
5
2.5
1.5
1
1

PreFID Cost1(% of TIC)
9.0%
4.5%
9.0%
4.5%
9.0%
24.1%
10.0%
5.5%
5.5%
4.5%

Financing Cost2 Total Pre-FID Financial Close(% of TIC)
Cost (% of TIC)
(years)
1.5%
10.5%
0.5
1.0%
5.5%
0.5
1.5%
10.5%
0.5
1.0%
5.5%
0.5
1.0%
10.0%
0.5
3.0%
27.1%
1
1.5%
11.5%
0.5
1.0%
6.5%
0.5
1.0%
6.5%
0.5
1.0%
5.5%
0.5

Construction
Time (years)
FID to COD
4
2
4
1
2
5
3
2
1
1

Overall Dev
Time (years)
Concept to COD
7
3.5
7
2.5
4.5
11
6
4
2.5
2.5

Construction
Time (years)
FID to COD

Overall Dev
Time (years)
Concept to COD

4

7Transmission
2

Technology
Transmission Assets(average)

Pre-FID Study Pre-FID Study Financing Cost
Time (years) Cost1 (% of TIC)(% of TIC)
2.5

5.7%

1.0%

Total Pre-FID Financial Close
Cost (% of TIC)
(years)6.7%

0.5

Distribution Networks
Technology
Distribution Assets

274

Construction
Overall Dev
Time (years)
Pre-FID Study PreFID Study Financing Cost2 Total Pre-FID Financial Close Time (years)
Time (years) Cost1 (% of TIC)(% of TIC)
Cost (% of TIC)
(years)
FID to COD Concept to COD
1
2.5%
0.5%
3.0%
0.5
1
2.5

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Estimated project development times and Pre-FID costs(Fuels, CO2 Infrastructure, and Industry)
FUELS CONVERSIONTechnology

Pre-FID Time
(years)

Pre-FID Cost1(% of TIC)

Financing Cost2(%of TIC)

Total Pre-FID
Cost (% of TIC)ATR Hydrogen
ATR Hydrogen with CCU
BECCS Hydrogen
Biomass to Syngas
Biomass to Syngas with CCU
Biomass FT to Diesel
Biomass FT to Diesel with CCU
Biomass Pyrolysis
Biomass Pyrolysis with CCU
Electrolysis
DAC for SynfuelsElectric Boiler
Hydrogen Blend
Industrial Hydrogen Boiler
Industrial Pipeline Gas Boiler
Power to Liquids
Power to Gas

2
2
2
2
2
2
2
2
2
2
2
2
1
2
2
2
2

4.5%
9.0%
9.0%
9.0%
9.0%
9.0%
9.0%
4.5%
9.0%
4.5%
9.0%
9.0%
4.5%
4.5%
4.5%
9.0%
9.0%

1.0%
1.5%
1.0%
1.5%
1.0%
1.0%
3.0%
1.5%
1.0%
1.0%
1.0%
1.0%
1.0%
1.0%
1.0%
1.0%
1.0%

5.5%
10.5%
10.0%
10.5%
10.0%
10.0%
12.0%
6.0%
10.0%
5.5%
10.0%
10.0%
5.5%
5.5%
5.5%
10.0%
10.0%

1
2
2
2
2
2
2
2
2
1
1
2
1
1
1
1.5
1.5

2
3
4
3
4
3
4
3
4
2
2
1
1
2
1
3
3

5
7
8
7
8
7
8
7
8
5
5
5
3
5
4
6.5
6.5

5
2.5
1

13.0%
4.2%
5.0%

1.5%
1.0%
0.0%

14.5%
5.2%
5.0%

1
0.5
0

5
3
1

11
6
2

2.5
2.5

4.2%
4.2%

1.0%
1.0%

5.2%
5.2%

0.5
0.5

4
3

7
6

Financial Close Construction Time Overall Dev Time (y)(years)(y) FID to COD
Concept to COD

CO2 TRANSPORT & STORAGE
Inter-Regional Trunk Lines
Spur Lines
E&A, Wells & Facilities

INDUSTRY
Cement
Steel

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The 2020s is the decade to invest in maturing and improving a
range of technologies that improve options for the longer term.
• Several technologies will require multiple full-scale ‘first-N-of-a-kind’ (FOAK) projects to reduce costs andtechnology risks.
• Assumed investment premium is estimated at 150% over and above reference costs across pre-FID,
design, construction and commissioning.
FOAK Project
unit Capacity
Power
Advanced Nuclear
CCGT with CC
CCGT with CC (Oxy)Bio-gasifier GT with CC
High-H2 GT
Advanced Geothermal
Fuels
ATR Hydrogen with CC
Bio-gasifier H2 with CC
Biomass Pyrolysis
Electrolysis
Direct Air Capture
Industry
Cement with CC
H2-Direct Reduced Iron
Total
276

300 MW
300 MW
300 MW
300 MW
100 MW
100 MW
300 MW
300 MW
100 MW
100 MW
100 ktpa
2.8 Mtpa
2.25 Mtpa

No. of
Projects
27
4
5
5
5
5
3
30
5
5
5
10
5
10
5
5
67

Mature cost*(used in RIO model)

FOAK cost multiplieron mature cost**

6,465 $/kW
2,176 $/kW
1,924 $/kW
6,338 $/ kW
520 $/kW
5,472 $/kW

2.5
2.5
2.5
2.5
2.5
2.5

782 $/kW
2,599 $/kW
3,991 $/kW
1,790 $/kW
18,954 $/ktph CO2

2.5
2.5
2.5
2.5
2.5

3.5 B$/plant
400 M$/plant

2.5
2.5

* Overnight installed capital cost per unit output. For fuels, output is expressed on a higher heating value basis.
** Including pre-FID, based on Guidelines for First-of-a-kind Cost estimation [1.5 applies to FOAK plants already committed in 2020’s]

Total FOAK
Investment (B$)
63.3
19.4
8.2
7.2
23.8
0.7
4.1
24.8
2.9
9.7
5.0
4.5
2.7
48.8
43.8
5.0
136.9 RETURN TO
TABLE OFCONTENTSAll net-zero scenarios are capital intensive. Mobilizing risk capitalfor development and construction will be a significant challenge
Almost $10 trillion cumulative capital
E+ $600 billion at-risk Pre-FID development costs toinvestment in supply-side plant & infrastructure
Power Generation
Transmission
Distribution
Fuels Conversion
CO2 Transport & Storage

Billion 2018 $$500$10,000(incl. pre-FID and FOAK demonstration costs)
Power Generation
Transmission
Distribution
Fuels Conversion
CO2 Transport & Storage$9,000$8,000Billion 2018 $$600

support >$9 trillion in capital investment decisions

$400

$300

$200

$7,000$6,000

Cumulative Capital Committed(incl. assets under construction)$5,000

Cumulative Capital Spent(assets in service)$4,000FOAK
Projects
Pre-FID
Investment$3,000$2,000$100$1,000
$0

$0
2020

2025

2030

2035

2040

2045

2050

2020

2025

2030

2035

Note: Excludes investments in demand-side transport, buildings and industry; biomass crop establishment; and land sink enhancements.

277

2040

2045

2050
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Fossil fuel industries
Summary of this section
All fossil fuel industries see rapidly declining consumption and production throughout the transition.
Thermal coal consumption and production ceases by 2030.
•

Over 700 coal mines close and some 500 coal-fired power plants are retired.

•

The majority of coal plants retire at >30 years age, with just 8% retiring at <2o years and 50% retiring at >50 years.

Oil production declines 25% to 85% across the suite of NZA scenarios, relative to the reference scenario•

Consumption declines 60% to 100% by 2050 in net-zero scenarios.

•

Exports remain in line with AEO projections to 2050.

•

Oil production t0 2050 in net-zero scenarios exceeds current proven reserves, but is less than projected reserves based onrecent growth rates.

Natural gas production declines between 20% and 90% across the suite of NZA scenarios, relative to the reference scenario

278•

Consumption declines 50% to 100% by 2050 in net-zero scenarios.

•

Exports remain in line with AEO projections to 2050.

•

Significant declines in revenues for producers and bringing forward some $25 billion in remediation costs.

•

Gas production in to 2050 in net-zero scenarios exceeds current proven reserves, but is less than projected reserves based on
historical growth rates.

•

Significant stranded asset risks for transmission and distribution networks.

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Coal
Summary of this section
Thermal coal consumption and production ceases by 2030.
• Over 700 coal mines close and some 500 coal-fired power plants are retired.
• The majority of coal plants retire at >30 years age, with just 8% retiring at <2o years
and 50% retiring at >50 years.

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In all net-zero pathways most of the nearly 700 mines close by2030, impacting all coal-producing regions.

Note: We assume that the US continues to produce coal post-2030 to meet domestic
industrial and coking demand as well as projected exports consistent with the EIA
2020 AEO Reference case projections. We assume that coal imports are trivial. In
2030 for the E+ scenario, we assume that continued coal production to meet export
demand occurs in states that have historically produced coal for export; we use the2019 historical state origin of exports to spatially allocate future production.
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RETURN TO TABLE OF CONTENTSAll coal power plants (500+) close by 2030.
Retirement period of coal
generators in E+ scenario

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Average annual coal retirements in all net-zero scenarios is close to
the historical peak rate observed in 2015.
Historical peak

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The U.S. coal fleet is old. Half of plants retire 50+ years old in the2020’s. Less than 8% (23 GW) retire before reaching 20 years.
Average age ofcoal plants today
is 45 years.

Retirement of coal generators for E+ scenario
Generators indicated in red retire prior to the typical 50-year lifespan ofcoal generators, consistent with Grubert (2020).

50

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Oil
Summary of this section• Oil production declines 25% to 85% across the suite of NZA scenarios, relative to the reference scenario• Consumption declines 55% to 100% by 2050 in net-zero scenarios.
• Exports remain in line with AEO projections to 2050.
• Oil production t0 2050 in net-zero scenarios exceeds current proven reserves, but is less than projected
reserves based on recent growth rates.

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Oil consumption declines 55% to 100% by 2050 for net-zeroscenarios relative to REF; production declines 25% to 85%.
REF
E- B+

Change in oil consumption in E+ case relative to REF

E-

E+ REE+
E+ RE+

E- B+
E-

REF
E+ RE-

E+

E+ RE+

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Note: Production projections assume US produces at a rate consistent with or lower than the 2019 EIA
AEO Reference case and continues to export oil at rate consistent with the AEO projection. As
domestic consumption declines, an increasing share of demand is met through domestic production
and a decreasing share of oil is imported. Starting around 2035, domestic demand has fallen to thepoint that oil imports are no longer needed, and with further demand declines thereafter, US
production also declines.

Cumulative oil production through 2030 exceeds current proved
reserves, but continued additions could risk stranding assets.
U.S. Domestic Oil Reserves (106 bbl)

Cumulative Oil Production vs. Reserves• Cumulative oil production t0 2050 in REF and net-zero scenarios exceeds current proven reserves, indicating that
all current reserves can be produced in these scenarios.
• If recent annual rates of reserve addition persist, however, proved reserves could surpass projected cumulative oil
production and result in some stranded assets.
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Natural Gas
Summary of this section• Natural gas production declines between 25% and 85% across the suite of NZA scenarios, relative to thereference scenario• Consumption declines 50% to 100% by 2050 in net-zero scenarios.
• Exports remain in line with AEO projections to 2050.
• Significant declines in revenues for producers and bringing forward some $25 billion in remediation costs.
• Gas production in to 2050 in net-zero scenarios exceeds current proven reserves, but is less than projected
reserves based on historical growth rates.
• Significant stranded asset risks for transmission and distribution networks.

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Natural gas consumption declines 50% to 100% by 2050 in net-zeroscenarios relative to REF.

(projected as in AEO
2019 Reference Case)
REF

E- B+

• Over ½ million gas wells closein 2020’s; plug andabandonment costs are
estimated to be ~$25 billion.

E+ REE+E-

E+ RE+

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EIA reserves estimates.

Natural gas production through 2030 is less than current proved
reserves, but continued reserve additions could risk stranding assets.
2020-2030 Near-term production and reserves

2020-2050 Long-term production and reserves

Cumulative gas production to 2030 in E+ is less than
today’s proved reserves, even without reserve additionsat short-term historical growth rates (8%/year).

Cumulative gas production to 2050 in E+ exceeds
today’s reserves, but is less than reserves if reserves growat long-term historical rate (4%/year).

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Declines in natural gas consumption will impact gas transmission
and distribution infrastructure.
The existing gas pipeline network is vast:• 20,000 miles of gathering lines (50% >30 years old)
• 300,000 miles of transmission lines (70% >30 years old)
• 1,300,000 miles of distribution mains (50% > 30 years old)
• 70,000,000 service lines
Interstate pipelines
Intrastate pipelines
Gathering lines

The transmission network is aging, but some distribution
system replacements have accompanied the shale gas boom:
Transmission line vintages

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Distribution main vintages

As gas use falls, volumetric revenues will decline, prompting needto review rate design and network asset valuations
Decline in natural gas market revenue (E+ v. REF)
assuming volumetric rates

2020

291

2030

2040

2050

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Declining customer base over time will challenge cost recovery andraise equity concerns.
E+

E-

292

Percent reduction in number of gas-fired residential heaters from 2020

2030

2040

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2050

Employment impacts
Summary of this section

293•

A model was built to assess supply-side employment, wages, and workforce development requirements inenergy-system transitions. (Energy efficiency, vehicle and appliance related employment is not modeled in this report.)•

To support modeled net-zero transitions, the supply-side energy workforce expands by upwards of 30% in the 2020sand nearly triples by 2050. Today ~1.5% of the labor force is directly employed in supply-side energy-related jobs.
By 2050, this grows to 2-4.5% across different net-zero scenarios.

•

In the 2020s, net-zero pathways support an annual average of ~3 million supply-side energy jobs, a net increase of~0.5-1 million jobs relative to a business-as-usual scenario (REF).

•

Net job losses in fossil fuel sectors across the transition are more than offset (in aggregate) by increases in low carbon
sectors, especially solar, wind, and electric-grid sectors. Construction comprises an increasing portion and mining(i.e., oil, gas, coal upstream activities) comprises a declining portion of jobs over time.

•

Changes in labor productivity have a large influence on employment outcomes and more broadly on the energy
transition as whole. This modeling explicitly considers impacts of productivity changes on future employment.

•

An annual average of ~$180-190 billion in wages are generated in the 2020s, for a net increase of $30-40 billion over
REF. Supply-side energy sector employment generates ~2% of total U.S. wages, rising to ~2-5% by mid-century.

•

A number of modifiable sociotechnical factors influence the spatial distribution of labor. With assumptions used here,
all states see energy-related employment grow as a share of the total state labor force except for a few with very highshares of the current labor force employed in upstream fossil fuel industries (e.g., WY, ND). In some states with highresource quality (e.g., NE, MT, IA), energy industries grow to become dominant employers.

•

There will be an increasing demand for workers with a diversity of education, experience, and training backgrounds.
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Decarbonization Employment & EneRgy Systems model (DEERS)
Labor model assesses supply-side
employment, wages, and workforce
development requirements associated withenergy system transitions.
• Pairs with output of economy-wide or spatiallydownscaled macro-energy system modeling.
• Architecture largely derived based on current
data of economic accounts and energy activity.
• Models the distribution of labor impacts across
50 states, 9 economic sectors, 9 resource supply
chains, 50 industries, and 1000+ occupations.
• Includes time-variant factors, such as laborproductivity and wage inflation, relevant for
long-term planning.
• Used to evaluate policy and planning decisions,such as just transition funds, workforce
development needs, domestic manufacturing,oil and gas exports, and facility siting.

294

Employment
factors

Labor
productivity

Occupational
wages

Step 2.
Wages
Step 1.
Employment

Sector &industry
distribution

Occupation
profilesStep 3.
Workforcedevelopment

Energyactivity

Note: In this analysis, we focus on supply-side resource supply chains (i.e., biomass, CO2, coal,electric power grid, natural gas, nuclear, oil, solar, wind). We do not model employment related toenergy efficiency, electric vehicles, or consumer electronics/appliances.

Experience/education
level

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Calibration: DEERS model results using 2018 inputs match up wellwith actual 2018 employment across resource sectors.

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~3 million energy-supply jobs annually in the 2020s in net-zeroscenarios, a net increase of ~0.5 – 1 million jobs over REF.

Note: Equilibrium impact on net economy-wide employment is not modeled.

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1.5% of the U.S. labor force is directly employed in energy-supply
today; this may increase by 2050 to 2 to 4.5%.

Note: Equilibrium impact on net economy-wide employment is not modeled.

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RETURN TO TABLE OF CONTENTSNet job losses in fossil fuel sectors in near- and long-term are morethan offset (in aggregate) by increases in low carbon sectors

Total net jobs
Net jobgain

Net jobloss

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Solar and wind dominate energy-related jobs. Construction sector
share increases over time, while mining (upstream fossil) declines.
Distribution of jobs by resource sector

299

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Distribution of jobs by economic sector

Note: Mining includes upstream
coal, oil, and gas activities.

Changes in labor productivity have a large influence on employmentoutcomes and more broadly the energy transition as whole.
Historical changes in labor productivity
Short-termLong-term

No change in laborproductivity

Increasing laborproductivity

Note: Other employment modeling results shownin this report correspond to the results withincreasing labor productivity shown on this slide.
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Modifiable socio-technical factors influence spatial distribution of
employment. Below is one instantiation of the future (out of many).
Annual employment based on
downscaled E+ scenario

Modifiable sociotechnical factorsthat influence the spatial
distribution of employment:(thousand jobs)

Green, yellow, and red indicate
average annual employment ina decade is >15% above, within+ 15%, or >15% below 2021
employment, respectively.

Resource quality andavailability•

Rate of electrification•

Technology selection•

Domestic manufacturing•

Siting constraints•

Oil and gas exports•

Political and policy processes
and constraints

There are several degrees of
freedom that can reducetransition risks and be leveraged
for political bargaining.

Note: Spatial redistribution of solar and wind manufacturing facilities and increasing the domestic manufacturing share offer opportunities
to ameliorate losses in fossil fuel extraction states. For assumptions used here in siting solar and wind manufacturing jobs, see this slide.

301•

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In most states, energy-related employment grows as a share of total
employment through the transition period.
E+ scenario• In a few states with a very high share of the current labor force employed in upstream fossil fuel industries(e.g., WY and ND), energy-related employment decreases as a share of the total employment.
• In states with high renewable resource quality (e.g., NE, MT, and IA), energy industries grow to become
major employers.
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State-level distributions of employment by resource sector change
dramatically over the transition.
Distribution of employment based on
downscaled E+ scenario (%)

Note: Spatial redistribution of solar andwind manufacturing facilities andincreasing the domestic manufacturing
share offer opportunities to ameliorate
losses in fossil fuel extraction states. For
assumptions used here in siting solar andwind manufacturing jobs, see this slide.

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Oil sector today is largest resource sector, with nearly 1/3 of energy
workforce. It supports over 800,000 jobs in model year 2021.
Employment declines in both REF and net-zeroscenarios, and is influenced by the rate ofelectrification, extent of renewables deployment,
and oil imports and exports. By 2050, employment in
the REF scenario is approaching half that of 2020, and in the
net-zero scenarios it declines by 60-95%.

Spatialdistribution of
supply chain
employment
for E+ scenario

Note: all fossil energy sectors are assume to continue domestic extraction to supply
projected exports consistent with the EIA 2020 AEO Reference case projections.
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Natural gas sector is 2nd largest energy-employer, but upstreamjobs have been rapidly declining for several years.
Natural gas sector supports 600,000 jobs associated withproduction (60%), transmission & distribution (30%),
and power generation (10%) in model year 2021.

Employment in oil & gas extraction industry
has been rapidly declining for years, and has
accelerated during the COVID-19 pandemic.

Source: theint.net
Source: NPR

Natural gas extraction industry currently is a major
employer in several counties, although part of theworkforce is transient. During the peak of the shale gasboom, the natural gas industry in some rural communities
comprised upwards of 60% of combined direct, indirect,
and induced employment in one West Virginia county.
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Natural gas-related employment declines, except for gas power
generation. Impacts concentrated in Appalachia and Permian basin.
Natural gas employment decline is
influenced by the rate of electrification,
extent of renewables deployment, andnatural gas exports.

Spatialdistribution of
supply chain
employment forE+ scenario

Note: all fossil energy sectors are assume to continue domestic extraction to supply
projected exports consistent with the EIA 2020 AEO Reference case projections.
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Coal mining jobs have been declining for 3 decades. Phasing out coalhas greatest impact on resource-dependent rural labor markets.
At the national-scale, the coal sector is relatively small, representing
5% of the energy workforce in 2021. For model year 2021, supports 150,000 jobs
associated with production (40%), transport (20%), and power generation (40%).

Over past three decades, employment
in coal mining industry has declined
dramatically (62%). Average decline rate of50

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2030

2010

0
2020

5% or greater of labor force in 35
counties. This includes only jobs within
the mining industry, not indirect andinduced employment.

307

E+

1990

Coal mining industry currently
is a major employer in several
counties. The coal sector represents

100

2000

Source: power-technology.com

150(thousand jobs)

Source: Johnson Group

Coal mining employment

3%/yr (3,000 jobs/yr) and peak decline rate in2016 of 21%/yr (13,000 jobs/yr).

Coal mining jobs continue to decline at similar to recent historicalrate. Impacts are concentrated in Appalachia & Powder River Basin.
Eliminating coal by 2030 implies an annual decline rateof 14,000 jobs/yr, compared to a decline rate of 8,000
jobs/yr in the reference scenario over the first decade

Job losses concentrated in mining regions.

(6,000 jobs/yr mining/upstream, 2,000 jobs/yr transportation, 7,000
jobs/yr power generation)

Note: all fossil energy sectors are assume to continue domestic extraction to supply
projected exports consistent with the EIA 2020 AEO Reference case projections.
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350,000 solar jobs in model year 2020. By 2030, solar is 2nd largest
employer, with 80% in generation and 20% in manufacturing.
By 2050, employment in solar sector comprises a third tonearly half of energy-related jobs in net-zero scenarios.
Even in reference scenario, solar emerges as the second
largest resource sector.

Spatial distributionof employment is
influenced byresource quality,
siting constraints
and decisions,domestic
manufacturing.

Note: solar and wind related manufacturing employment estimates assumecontinuation of current domestic content shares.
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RETURN TO TABLE OF CONTENTSWind sector employs 120,000, or less than 5% of the energy
workforce in 2020.
By 2050, employment in the wind sector comprises
10 to 25% of energy-related jobs in the net-zeroscenarios, potentially surpassing the size of thecurrent natural gas sector.

Spatial distributionof employment is
influenced byresource quality,
siting constraints
and decisions,domestic
manufacturing.

Note: solar and wind related manufacturing employment estimates assumecontinuation of current domestic content shares.
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Solar and wind manufacturing offer opportunities to distribute
employment benefits across multiple states
There are degrees of freedom in siting
solar and wind manufacturing facilities
and the amount of manufacturing done
domestically. This flexibility can beleveraged to offset job losses incommunities, build coalitions, andfacilitate legislative bargaining.
• To maintain current domestic shares ofmanufacturing (77% wind, 11% solar),manufacturing capacity must increase
substantially• by 2030: 5-10X for wind, 10X for solar• by 2050: 5-45X wind, 20-120X solar
Note: Spatial redistribution of solar and wind manufacturing facilities and increasing the domestic manufacturing
share offer opportunities to ameliorate losses in fossil fuel extraction states. The estimates here assume 1)
manufacturing is sited within the logistic region (see next slide) where solar and wind generation are sited to accountfor transport between manufacturing and generation, 2) the distribution of manufacturing by state within a logistic
region is consistent with the distribution of 2018 energy-related jobs (next slide), and 3) the domestic share ofmanufacturing is consistent with the historical domestic share (i.e., 77% wind, 11% solar).

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RETURN TO TABLE OF CONTENTS• Increasing domestic content share has
minimal impact on technology costs,
while supporting additional domesticjobsAssumptions for modeling the state-wise distribution of solar andwind manufacturing jobs
The state-wise distribution of solar and wind manufacturing jobs assumes 1) manufacturing is sited within
the logistic region where solar and wind generation are sited, 2) the distribution of manufacturing by state
within a logistic region is consistent with the distribution of 2018 energy-related jobs, and 3) the domestic
share of manufacturing is consistent with the historical domestic share (i.e., 77% wind, 11% solar).
Logistic regions

312

2018 distribution of energy labor force

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Nearly 460k grid-related jobs today (17% of energy jobs). By 2050,
grid-related jobs grow and represent > 1/3 of energy workforce.
Growing employment is largely associated with the
2-4X expansion of grid and ongoing O&M of existingand expanding grid infrastructure. Employment
growth is generally correlated with renewables
deployment.

313

Spatialdistribution
generallycorrelates withexisting grid
infrastructureand new
renewables.

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Wages for energy-supply related employment increases throughnet-zero transitions
Annual wage income is 180 to 190 B$ in net-zeroscenarios in the 2020s, an increase of 30-40 B$ over REF

314

Energy-related wages represent ~2% of total wages
today and 2-5% by mid-century in net-zero scenarios

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Modifiable socio-technical factors influence spatial distribution ofwages. Below is one instantiation of the future.
Modifiable sociotechnical factorsthat influence the spatial
distribution of wages:

Annual wages based on
downscaled E+ scenario(billion 2019$)•

Resource quality andavailability•

Rate of electrification•

Technology selection•

Domestic manufacturing•

Siting constraints•

Oil and gas exports•

Political and policy processes
and constraints

There are several degrees of
freedom that can reducetransition risks and be leveraged
for political bargaining.
Note: Green, yellow, and red coloring indicate whether average annual wages within a decade is more than 15% higher, within
15%, or more than 15% lower than 2021 wages, respectively.

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In most states, energy-related wages grow as a share of total wages
through the transition period.
E+ scenario• In a few states with a very high share of the current labor force employed in upstream fossil fuel industries(e.g., WY and ND), energy-related employment wages decrease as a share of the total employment wages.
• In states with high renewable resource quality (e.g., NE, SD, MT, and IA ), wages for energy-related
employment as a share of total-employment wages grow considerably.
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Wages per job for a given resource sector are similar for REF andnet-zero scenarios, with some variations between sectors.
Energy-related jobs are largely middle
income jobs, but there is a range acrossthe income spectrum.

Probability density

E+ scenario

Median annual wage (thousand 2019$)

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Wages losses
in fossilin
fuelfossil
sectors areoffset(in aggregate)bywages paidinlow carbon sectors.
There
Wages
lossesfuelsectorsareoffset(inaggregate)byis minimal net loss in fossil fuel sectors in the first decade of the transition. By the 2040s, the net loss
added
wageshowever,in lowmuch
carbonsectors.
rises substantially,of the current
fossil fuel workforce will have aged out.

• There is minimal wage loss in fossil fuel sectors in the first decade of the transition.
• By the 2040s, the loss is substantially higher (though much of the current fossil fuelworkforce will have reached normal retirement age by that time).

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There will be an increasing demand for workers with a diversity ofeducation, experience, and training backgrounds.
Employment by required
level of education

Distribution of employment
by required level of education(results shown for E+ scenario
aggregated over 30-yr period)• 30% of the energy
workforce will require abachelor’s degree or higher• Similar distribution of
education requirements
across reference and netzero scenarios and overtime
• Heterogeneity in education
requirements acrossresource sectors

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There will be an increasing demand for workers with a diversity ofeducation, experience, and training backgrounds.
Employment by required
years of experience

Distribution of employment byrequired years of experience(results shown for E+ scenario aggregatedover 30-yr period)• 70% of the energy workforce
requires less than 4 years ofrelated work experience,suggesting minimal lead timerequired to prepareindividual workers.
• Similar distribution ofexperience requirements
across reference and net-zeroscenarios and over time.
• Minimal heterogeneity inexperience requirements
across resource sectors.

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Considerations for workforce development programs in
net-zero transitions•

The rate of decarbonization is influenced by the organization and availability of labor.

•

In established fossil fuel and emerging renewable labor markets, there is evidence of difficulty inhiring, which portends continued employment bottlenecks without countervailing policies andorganization.

•

Findings suggest that diverse workforce programs (e.g., occupational skills training, college
training, and internships) are needed to re-train workers in declining sectors, and train andeducate the future workforce.

•

Findings suggest that there is minimal lead time required to prepare individual workers.

•

Given the magnitude of future labor demand to support a decades-long transition, large-scale andsustained workforce programs and corresponding federal support will be required.
Entails substantial coordination between unions, public agencies, firms, and workers to meet theevolving needs of both workers and employers to mitigate labor supply bottlenecks.

•

321

•

Diversity of programs that account for heterogeneity of existing workforces and types of sectors
and industries that will be expanded in different regions and communities.

•

Beyond training, workforce programs can include recruitment and job placement assistance.

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Implications of findings on energy-related employment• To support a net-zero transition, the supply-side energy workforce may expand by upwards of
30% in the first decade and nearly triple by 2050.
• Net-zero transitions have the potential to significantly transform state and local economies.
• Labor pathways and the distribution of labor are influenced by several modifiable socio-technicalfactors, such as technology selection, pace of low carbon infrastructure expansion, infrastructure
siting and investment decisions, oil and natural gas exports, and domestic manufacturing.
• Modifiable factors can be leveraged to reduce transition risks and to facilitate legislative
bargaining.
• Designing policies that anticipate and leverage the skill, temporal, & locational
complementarities between workforces of declining and emerging energy sectors can aid inmoderating concentrated unemployment and mitigating labor supply bottlenecks.
• Given the magnitude of future labor demand to support a decades-long transition, large-scale,sustained, and diverse workforce programs and corresponding federal support will be required.
• Policy can mitigate the impacts of employment losses for fossil fuel workers and communities.

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Health impacts related to air quality
Summary of this section•

Historically, there have been persistent and large air quality impacts from fine particulate matter(PM2.5) exposure associated with air pollutant emissions from carbon-producing industries.

•

PM2.5 exposure disproportionately impacts lower income populations, although there is variation in theextent of the disproportionate impacts across different industries.

•

Siting decisions, technology selection, air pollutant emissions abatement, and rate of electrificationinfluence air quality outcomes.

•

With modeling assumptions used in this study
•

•
•

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About 40,000 premature deaths (~$400B damages) are avoided during the 2020s by transitioning
transportation and coal and natural gas electric power sectors to meet an economy-wide target ofnet-zero emissions by 2050.
Cumulatively (2021 – 2050), 200,000 to 300,000 premature deaths (~$2T-$3T damages) areavoided by a net-zero transition.

Air quality/health impact modeling has not yet been completed for several other important sectors,
including industry, biomass production and utilization, oil/gas/coal upstream activities, and othernatural gas end uses.

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Modeling framework for estimating air pollution and associatedhealth impacts
State-level energy
activity(NZAP)

Step 2. Spatially-resolved emissions simulation

Step 4. Receptor-resolved damage simulation

Point source or
county-level
energy activity

County-levelemissionsprojections

County-levelmortality
projections

County-level
damageprojections

Technology- or
point sourcespecific emission
factors

Air quality model

Value of statisticallife

Step 1. Spatially-resolved energy activity simulation

Pollutants included• NOx, PM2.5, SO2, VOC

Sectors covered (to date)
Step 3. Receptor-resolved air quality simulation• Transportation• Electricity generation (coal, gas)
Assumptions:• Value of statistical life (VSL): 8.9M 2019$ (base), Weibull distribution (from EPA meta-analysis)• Discount rate: 0% (base) /3%/5%/7%• Air quality reduced complexity models: AP3 (base), InMAP, APSCA• Health outcomes assessed: premature mortality• Dose-response: American Cancer Society (base), Harvard 6 Cities study
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In 2019, ~11,000 premature mortalities ($100B damages) wereassociated with emissions from the transportation sector.

Cook county, IL:~340 deaths/yr
Queens county, NY:~140 deaths/yr

LA county, CA:~2,000 deaths/yr

Premature deaths
per county (log scale)-325

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2000

Mortality associated with transportation emissions are highest in
populated areas and are effectively eliminated by 2050 in E+ paths.

REF

E-

E+

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In 2018, 11,000 premature mortalities (~$100B damages) wereassociated with emissions from 390 coal power plants.
Premature deaths per
county (logscale)
Mortality(log
scale)-

300
Coal power plantMayfield, E.N. et al. “Sequencing coalretirements based on climate andenvironmental objectives.” forthcoming.

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Over 100,000 coal-related air pollution deaths (~1 T$ in damages)
are avoided by 2050, with annual mortalities eliminated by 2030.
Net-zero

2020

2025

2030

2050

REF

Premature deaths
per county (log scale)-300

Coal power plant328~40,000 premature
mortalities avoided,2020 to 2030.

$340B in air pollution
benefits, 2020 to 2030

RETURN TO
TABLE OFCONTENTSIn 2019, ~1,800 premature mortalities ($16B damages) wereassociated with emissions from natural gas power plants.
Premature deaths
per county (log scale)-

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200

Mortality risks from natural gas power generation emissions highest
in densely populated counties and those proximate to gas basins
County mortality rate
(deaths per 100,000)

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Cumulative air quality benefits, 2020 – 2050, include 200,000 to
300,000 avoided premature deaths (2 - 3 T$ estimated damages)

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Air quality benefits in 2020s are mostly due to coal plants retiring;
benefits from transportation are significant later in the transition

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There are large cumulative air pollution-related health benefits
across most states.
E+ scenario(relative to REF)

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Temporal and spatial visualization of net-zero pathways point topotential bottlenecks deserving immediate attention and analysis.
Potential bottlenecks for a 2050 Net-Zero America:Ø Creation of the coalitions of public support and political will needed to achieve 2020’s targets.
Ø Upfront cost premiums for efficient and electric consumer durable goods (EV’s, heat pumps, etc.).
Ø Rate of mobilization of risk-capital to support project development and construction activities.
Ø Rate of divestment/new investment among incumbent supply-side and demand-side firms.
Ø Regulatory capacity to review and permit investment proposals at the required scale and pace.
Ø Building the EPC and the supply chain capacities needed to support deployment rates.
Ø Developing human / skills capacity at the pace required to support the transition.
Ø Concentrated employment losses in particular communities.
Ø Community opposition to visual and land-use impacts of wind, solar, transmission; bioenergy
industrialization; environmental impacts of CO2 sequestration; nuclear power due to safety andenvironmental concerns.
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A blueprint for action in the 2020s: key priorities
Summary of this section• This section presents a blueprint for action in the 2020s.
• Priority actions include a set of robust investments needed this decade to get on track to net-zero emissions
by 2050, regardless of which net-zero pathway the country follows in the longer term. These can be madewith confidence that they will deliver value over the long term:
•
•
•
•
•

Renewable electricity generation and transmission
Electrification of end uses, including vehicles and building heat
Industrial productivity improvement
Increase carbon uptake and storage in forests and in agricultural soils
Reduce non-CO2 greenhouse gas emissions• Actions for the 2020s also include a set of important investments in enabling infrastructure and innovativetechnologies to create real options to complete the transition to net-zero beyond 2030:• Plan and begin building:• Additional electricity transmission to enable accelerating wind and solar expansion• A nationwide CO2 transportation network and permanent underground storage basins• Invest in maturing a range of technologies to make them cheaper, scalable and ready for widespreaduse in the 2030s and beyond.
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Net-zero by 2050 would require aggressive action to start now.
Eight Key Priorities for the 2020’s:

336

1

Build societal commitment, investment environment, and delivery capabilities

2

Improve end-use energy productivity and efficiency

3

Electrify energy demand, especially transportation and buildings

4

Decarbonize and expand electricity

5

Prepare for major expansion and transformation of the bioenergy industry

6

Build infrastructures: electricity transmission and CO2 transport/storage

7

Enhance land sinks and reduce non-CO2 emissions

8

Innovate to enlarge the net-zero-carbon technology toolkit
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Priorities for the 2020’s: Behaviors, institutions, markets

1

Build societal commitment, investment environment, and delivery capabilitieso

Major stakeholder engagement campaigns to build:i.

Broad societal awareness of local, state and national benefits of net-zero energy pathways; andii.

Acceptance, management, and mitigation of impacts on landscapes and communities associated with the transition.

o

Major consumer awareness campaigns and incentives to drive low-carbon energy investment decisionsoRedesign markets and institutions for a low-carbon futurei.

Reform electricity markets to ensure electricity supply reliability as solar and wind contributions increase; and to value flexibility on
both the supply side and the demand sideii.

Improve permitting efficiency to accelerate successful project and infrastructure siting without compromising quality of environmental
and social impact assessment.

iii. De-risk spending of at-risk capital to accelerate investment decision processes in support of rapid capital expansionoDevelop workforce to support net-zero pathwaysi.

Signal state-by-state demand and future priorities to education and training institutionsii.

School outreach programs to encourage uptake of key STEM degrees, vocational training and tradesiii. Incentive programs to encourage workforce shifts both between industries and between states337oMajor stakeholder engagement campaigns and support programs to mitigate impacts on incumbent sectors and communities and organizations
impacted by transitionsoSupport for development and rapid expansion of project development capabilities and new industrial capacity and supply chains

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Priorities for the 2020’s: Demand-Side

2

3

338

Improve end-use energy productivity and efficiencyoIndustry: Achieve 2% (or greater) per year sustained improvement in industrial energy productivityoBuildings: Reduce building space conditioning (heating/cooling) energy use through improved building shells, electric heat pumps, and controlsoAppliances: Ensure adoption of most efficient end-use appliances and consumer devices, including conversion of fuel-using devices to electricityoVehicles: Increase energy productivity by shifting transportation from single occupancy light duty vehicles to multi-occupancy vehicles, transit,
cycling and walking; shift on-road trucking to rail freight; and steadily improve fuel efficiency of new ICE vehicles.

Electrify, especially transportation and buildingsoElectric vehicles: By 2030, half of all new light-duty vehicles sold are battery-electric; medium and heavy-duty trucks and bus sales are 15% batteryelectric and 10% fuel cell. By 2030, there are ~50 million electric light duty vehicles on the road and ~1M medium and heavy duty trucks and buses.
(These targets correspond to E+ scenario. Targets for E- would be lower.)oCharging infrastructure: Build-out of publically-accessible EV charging infrastructure (ahead of EV adoption rate), including 2.4 million charging
ports nationwide by 2030 for E+ scenario or 0.8 million ports by 2030 for E- scenario.

oSpace heating: Deploy electric heat pumps in ¼ of current residences by 2030 (25-30 million households) plus ~15% of commercial buildings.
Focus on new builds and end-of-life replacement of current stock in climate zones 1 through 5.

o

Hot water: Deploy electric heat pump residential water heaters as end-of-life replacements for existing units.

oAutomation: Expand automation and controls across electricity distribution networks and end-use devices to unlock flexibility of EV charging,space and water heating loads, and distributed energy resources and minimize distribution network expansion required to support electrification.

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Priorities for the 2020’s: Supply-side

4

Decarbonize and expand electricityoCarbon-free electricity: Increase total U.S. electricity generation 10-20% by 2030, and double the carbon-free share (to ~75%).

oWind and solar: Deploy about 300 GW of wind (3x existing) and 300 GW of solar (~4.5x existing) by 2030, supplying 45-55% of U.S. electricity(vs. ~10% today).

oCoal power: Retire all existing coal-fired power plants, reducing U.S. CO2 emissions by ~1 billion tons (1/6 of total net U.S. greenhouse gas
emissions), while avoiding ~40,000 deaths and ~$400 billion in air pollution damages through 2030. Manage associated operational reliability
and local economic transition challenges and impacts. Ready retiring sites for redevelopment as new zero-carbon thermal power plants.

oNuclear power: Preserve existing nuclear power plants wherever safe, and ready retiring nuclear plants for redevelopment as new zero-carbon
thermal power plants.

oNatural gas power plants: Modest decline in generation (10-30%) through 2030 with installed capacity at ±10% of 2020. Existing gas plants play
key role providing firm capacity and system flexibility. Avoid new commitments to long-lived natural gas pipeline infrastructure to avoid lock-in.

oEnergy storage: 5 to 15 GW of battery energy storage deployed by 2030.

5339

Prepare for transformation and expansion of bioenergy industryoEstablish biomass collection/transportation infrastructure: Sustainably use about 80 million t/y of residue biomass for energy by 2030.

oPrepare for dedicated bioenergy feedstock production: Develop high-yield energy crop systems (e.g., switchgrass, miscanthus) for converted(corn) cropland toward commencement of commercial harvests in 2035 and ramping up to 80 million tonnes/year of production by 2040
across 4 million hectares.

oPrepare bioconversion industry transition: Demonstrate advanced gasification-based bioconversion technologies for fuels production anddesign commercial-scale facilities to be deployed in the 2030’s.

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Priorities for the 2020’s: Network Infrastructures

6

6

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a. Expand critical electric network infrastructureoElectric transmission: Build ~195,000 GW-km of new transmission lines connecting solar / wind projects to loads by 2030 (~60% increaseover current US transmission capacity). Strengthen and expand U.S. long-distance electricity transmission by identifying corridors needed
to support wind and solar deployment (through 2030 and beyond given long lead time for transmission), reform siting/cost allocation
process, and develop stakeholder consensus/support to site transmission connecting high renewable development potential zones.

oElectric distribution: Strengthen distribution system planning, investment, and operations to allow for greater use of flexible demand anddistributed energy resources, improve distribution network asset utilization, and efficiently accommodate 5-10% increase in peak electricity
demand from EVs, heat pumps, and other new loads by 2030. Prepare for more rapid electrification and peak demand growth after 2030.

b. Expand critical CO2 capture and storage infrastructureoInterstate CO2 trunk line network: Plan, site, and construct an “interstate CO2 highway system” (trunk line network) by 2030 (~19,000 km),connecting all regions to CO2 storage basins in Gulf Coast, West Texas (Permian), Midwest (IL, IN, MO, KY), Dakotas/Eastern MT(Bakken), and California Central Valley.

o

CO2 storage regulations: Finalize national and/or state regulatory conditions governing: pore space ownership and access; well standards;
injection operations; measurement, monitoring and verification of CO2 containment (during- and post-injection); and long-term liability.

o

CO2 reservoir exploration and appraisal: Characterize with high confidence all major basins for CO2 sequestration and identify sites suitablefor injection of approximately 250 million metric tons of CO2 per year by 2030. Advance field development planning and permitting.

o

Carbon capture and sequestration: Capture and sequester 65 million metric tons of CO2 /year by 2030, including CO2 capture at
5 world-scale cement plants, 5-10 natural gas power plants, and 5-10 large-scale steam- or autothermal-reforming plants making hydrogen.

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Priorities for the 2020’s: Land Sinks and Non-CO2 Emissions

7a. Protect and enhance land carbon sinks
o

o

7

i.

Forestry sector: Target 160 million tCO2e per year additional sequestration through deployment of a variety of measures.

ii.

Agriculture: Target 40 million tCO2e per year additional sequestration, primarily through measures employed on croplands.

Prepare for future land-sink growth: Establish institutional mechanisms to ensure additional land sink enhancements beyond the 2020’s.

b. Reduce non-CO2 emissionso341

Grow the land sink: Deploy measures to achieve 200 million tCO2e per year of additional sequestration in 2030 compared with 2020 so as
to offset business-as-usual reduction of natural land sinks and achieve a net increase in the land sink of 50 million tCO2e per year.

Non-CO2 GHGs: Reduce non-CO2 greenhouse gases by at least 10% by 2030, includingi.

Reducing HFC production and consumption consistent with the Kigali Amendment to the Montreal Protocol.

ii.

Identifying and eliminating largest CH4 leakage sources in oil and gas production, processing, and pipelines.

iii.

Improving management of N2O and CH4 in agriculture.

iv.

Managing N2O emissions from nitric and adipic acid production.

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Priorities for the 2020’s: Innovation

8

Innovate to create additional real options for technologies needed post-2030
oTechnology option creation: Pursue maturation, scale-up, and cost/performance improvements in clean-energy technologies, including:•Clean firm electricity resources, including advanced nuclear, advanced geothermal, natural gas power plants with CO2 capture,biopower plants with CO2 capture, hydrogen and ammonia combustion turbines; ultra-cheap long duration energy storage;•

Hydrogen production via electrolysis, natural gas reforming with CO2 capture, and biomass gasification with CO2 capture;•

Synthesis of fuels from biomass and H2 + CO2, including methane and liquid hydrocarbons (e.g., Fischer-Tropsch fuels);•

Direct hydrogen-reduced iron and other carbon-free alternatives for primary steel production;•

CO2 capture in a range of industrial applications, including cement, ammonia, biofuels, and hydrogen;•High-yield bioenergy crops such as miscanthus•

Direct air capture methods$130 Billion: Order-of magnitude capital cost estimates for up to 5 first-of-a-kind (FOAK) demonstrations for each technology above,
including FOAK premiums.
o342Technology innovation to reduce siting challenges: Increase investment in research and technology solutions that reduce network
infrastructure siting challenges, including repurposing existing natural gas or oil pipelines for hydrogen or CO2 transport, low-costunderground transmission lines and increasing utilization/transfer capacities of existing electricity transmission.

RETURN TO TABLE OF CONTENTSAll net-zero scenarios are capital intensive. Mobilizing risk capitalfor development and construction will be a significant challengeE+$190 B$ at-risk pre-FID development costs in 2020’s tosupport supply-side capital investment decisions$200$3,000

2.6T$ committed to supply-side plant & infrastructure
in 2020’s: $1.8T in service, $0.6T in construction,
and $0.2T pre-FID.

$2,500$160

Billion 2018 $Billion 2018 $

$180

$140
$120

$100

$2,000$1,500$80$1,000$60$40Power Generation
Transmission
Distribution
Fuels Conversion
CO2 Transport & Storage
Cumulative Capital Committed(incl. assets under construction)
Cumulative Capital Spent(assets in service)
FOAK
Demonstrations
Pre-FID
Investment

$500

$20
$0

$0
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

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2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Note: Excludes investments in demand-side transport, buildings and industry;
biomass crop establishment; and land sink enhancements.

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Net-zero path requires $2.5 T additional capital in 2020s (vs.
REF) across energy supply, buildings, appliances, vehicles, industry.
Total additional capital invested and committed, 2021-2030, by sector and subsector for E+ vs. REF (billion 2018 $)Includes capital invested pre-financial investment decision (pre-FID) and capital committed to projects under construction in 2030 but in-service in later years.
All values rounded to nearest $10b and should be considered order of magnitude estimates. Incremental capital investment categories totaling less than $5B excluded from graphic.

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Other potentially significant capital expenditures not estimated in this study include establishment of bioenergy crops and decarbonization measures in other industries
besides steel and cement, non-CO2 GHG mitigation efforts, and establishing enhanced land sinks.

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TABLE OFCONTENTSTechnical annexes provide details on methods, assumptions, anddata sources for national scenarios and downscaled results.
A. Evolved Energy Research final report

M. Mobilizing capital for the transition

B. Transition pathway sensitivity studies

N. Fossil fuels transition

C. Transport & buildings transitions

O. Non-CO2 emissions transition

D. Solar and wind generation transition

P. Forest land sinks analysis

E. Thermal power plants transition

Q. Agricultural land sinks analysis

F. Electricity transmission transition

R. Employment transition

G. Electricity distribution system transition

S. Air quality / health impacts transition

H. Bioenergy supply industry transition
I.

CO2 transport and storage transition

J. Iron and steel industry transition
K. Cement industry transition
L. Hydrogen transition

Technical annexes are available for download at https://bit.ly/NetZeroAmerica

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