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Inflation Reduction Act, Retiring Coal Plants Create Opportunities for Advanced Nuclear Plants

October 16, 2022

by Peter Maloney
APPA News
October 16, 2022

The retirement of aging coal-fired plants combined with the recently passed Inflation Reduction Act has created an opportunity for public power utilities looking to secure long-term, reliable supplies of clean energy, according to advanced nuclear firm NuScale Power.

“The Inflation Reduction Act is the first transformative climate piece of legislation ever in the U.S. to treat nuclear energy as a clean energy source,” Chris Colbert, Chief Financial Officer at NuScale Power, said.

The Inflation Reduction Act of 2022 (IRA) provides production tax credits (PTC) for existing nuclear power plants but, more importantly, for new nuclear power plants and specifically for advanced reactors and small modular reactors – the type NuScale Power is working on. The IRA amends the definition of a qualified facility eligible for a “clean PTC” to mean any plant placed into service after Dec. 31, 2024, that produces zero greenhouse gas emissions.

The IRA also amends the Internal Revenue Service (IRS) rules on qualifying for a clean energy investment tax credit (ITC) by changing the language in the code to allow investments for advanced reactors to qualify for the credit. The change provides a tax credit of 30 percent of the cost of building a zero-emission advanced nuclear power plant that is placed in service after 2025.

“If you design and plan to put in a small modular reactor at the site of a retired coal plant, there is a further 10 percent ITC available, and if you use domestic content there is another 10 percent ITC added on,” Colbert said. “That can add up to a 50 percent reduction in costs.”

In September, the Department of Energy (DOE) released a study that found that hundreds of coal power plant sites across the country could be converted to nuclear power plant sites.

Of the 157 retired coal plant sites and 237 operating coal plants surveyed, the DOE study found that 80 percent were good candidates to host advanced reactors that are smaller than 1 gigawatt (GW).

Converting retired coal plant sites to nuclear power has the potential to add 64.8 GW of clean energy to the power system, and converting operating coal plant sites to nuclear power could add 198.5 GW to the grid, the DOE found.

Between 2015 and 2020, an average of 11 GW of coal-fired capacity retired every year, according to the DOE. The pace of retirements slowed in 2021, to 4.6 GW, but is expected to pick up this year with 12.6 GW of coal retirements scheduled. Additionally, plant owners and operators say they plan to retire 59 GW of the coal-fired capacity by 2035.

Each NuScale small modular reactor (SMR) is designed to generate 77 megawatts (MW) of electricity. Up to 12 SMRs can be combined to make a 924-MW VOYGR™-12 power plant. In addition to their compact design, which makes them scalable and cost competitive, SMRs have enhanced safety features. NuScale’s Power Modules are designed to safely shut down and self cool indefinitely without the need for an external power source. And the factory-fabricated design of a NuScale SMR allows them to be built and assembled in the United States.

Converting the site of a coal plant to nuclear power could also increase employment and economic activity in affected communities, according to the DOE report. And replacing a large coal plant with a nuclear power plant of equivalent size could increase jobs in the region by more than 650 permanent positions, leading to additional annual economic activity of $275 million, implying a 92 percent increase in local tax revenue compared with the tax revenues from the operating coal power, the DOE study found. A case study included in the report was based on a NuScale design example.

For public power utilities, the employment and tax concerns could be a particularly important consideration when deciding what to do with a coal plant or how to meet growing electricity demand while pursuing goals to move toward a clean energy or zero emissions economy.

“The question is, what are you replacing it with,” Colbert said. “By converting to nuclear power, you can do it in a way that does not throw hundreds of people out of work. Those workers would basically be doing the same thing they were doing before, but they would be paid a little more. And the community would be able to keep things going as they were. Nuclear power can mean continued employment, as well as a clean, affordable and reliable energy supply.”

The benefits of SMRs fit well with the needs of public power utilities, Colbert said. Instead of having to take a share in a large nuclear power plant, public power utilities can take a stake in a nuclear plant configured with the number SMRs to match their demand while having the comfort of knowing that more units could be added, if needed, in the future.

The Inflation Reduction Act also grants other benefits to public power utilities by providing a refundable direct pay credit that allows them to take advantage of tax credits that have been available to for-profit utilities for years.

The overwhelming majority of renewable energy projects have been financed using tax credits, either a PTC or an ITC. The Congressional Joint Committee on Taxation estimated that the value of energy-related tax incentives in 2022 alone would be $25 billion. Because they cannot directly benefit from tax credits, public power utilities have been left out of many of those projects.

Even before the legislation was signed, several public power utilities were considering adding an SMR plant to their generation portfolio through the deployment of NuScale’s technology.

Furthest along in embracing SMRs, however, is Utah Associated Municipal Power Systems (UAMPS), which is working toward the deployment of a NuScale VOYGR-6 SMR power plant as part of its Carbon Free Power Project at the DOE’s Idaho National Laboratory in Idaho Falls.

The prospects of the Carbon Free Power Project were bolstered in August 2020 when NuScale announced that the Nuclear Regulatory Commission (NRC) had completed the last and final phase of the Design Certification Application process for the design of its SMR technology, a crucial first step in the nuclear permitting process.

NuScale is now looking forward to reaching another milestone in the regulatory process.

In July, the NRC directed its staff to issue a final rule certifying NuScale’s SMR design.

The rulemaking would amend NRC regulations to incorporate NuScale’s SMR standard plant design, which would allow applicants intending to build and operate an SMR plant to reference the design certification rule.

“If approved, the certification would be published in the Federal Register and have the effect of law,” Colbert said.

The rulemaking is on the docket for the NRC to make a decision in November.

The timing is important.

“Many people are still wrapping their heads around the impact of the IRA,” Colbert said.

Meanwhile, the clock is ticking.

The Biden administration has set a goal for the country to reach 100 percent carbon dioxide pollution-free electricity by 2035. And the support provided by the IRA has an expiration date. The expanded ITC benefits go away in 2032 or when 75 percent decarbonization is reached.

“It is a great opportunity – the expanded ITC and the potential availability of former coal plant sites – but folks are going to need to get ahead of this if they want to ensure a secure supply of affordable, reliable electric power,” Colbert said.

Public Power Utilities in Massachusetts Enter Expanded Hydropower Power Purchase Agreement

October 16, 2022

by Paul Ciampoli
APPA News Director
October 16, 2022

FirstLight Power recently announced the expansion of a power purchase agreement with Energy New England (ENE). As part of the agreement, 13 Massachusetts-based public power entities have agreed to purchase over 110 gigawatt hours per year of hydroelectric power produced by two of FirstLight’s hydroelectric facilities in Connecticut.

The agreement will help participating communities continue to make progress toward meeting Massachusetts’ requirements for municipal utilities to obtain 50 percent of their supply from carbon-free sources by 2030 under the climate legislation passed into law in 2021.

Working in collaboration with ENE, the new power purchase agreement will run from 2024 through 2030. In addition, it expands on the successful partnership with ENE and power purchase agreement that FirstLight entered with 21 municipal utilities in 2020, which at the time represented the largest renewable energy purchase by municipal utilities in New England to date.

In 2021, FirstLight extended many of these agreements with several participating utilities including Middleborough Gas and Electric Department (MGED) and Taunton Municipal Lighting Plant (TMLP).

The public power entities participating in the contract include: Belmont Municipal Light Department, Braintree Electric Light Department, Concord Municipal Light Plant, Danvers Electric Division, Groveland Municipal Light Department, Hingham Municipal Lighting Plant, Mass Development Finance Agency (MDFA)/Devens Utilities, Merrimac Municipal Light Department, Norwood Municipal Light Department, Reading Municipal Light Department, Rowley Municipal Lighting Plant, Wellesley Municipal Light Plant, and Westfield Gas & Electric.

As part of the latest agreement with ENE, FirstLight’s Shepaug Generating Station (in Southbury, Conn) and Stevenson Generating Station (in Monroe, Conn) will supply the energy and renewable energy credits.

One of the largest hydroelectric facilities in Connecticut, Stevenson Station was recently qualified as a Class I (in Maine) renewable energy facility. As Connecticut’s largest hydroelectric generation station and the second largest source of carbon-free electricity in the state, Shepaug Station is a Maine Class II renewable energy facility.

JEA, Other Florida Utilities Sign Agreements to Join the Southeast Energy Exchange Market

October 16, 2022

by Paul Ciampoli
APPA News Director
October 16, 2022

Florida public power utility JEA and three other Florida utilities have signed agreements to join as members of the Southeast Energy Exchange Market (SEEM), effective Jan. 1, 2023.

Duke Energy Florida, JEA, Seminole Electric Cooperative and TECO Energy recently expressed their intent to join the expanded platform and expect active energy trading in mid-2023.

The new SEEM platform will facilitate sub-hourly, bilateral trading, allowing participants to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. Participation in SEEM is open to other entities that meet the appropriate requirements.

Other founding members of SEEM include Associated Electric Cooperative, Dalton Utilities, Dominion Energy South Carolina, Duke Energy Carolinas, Duke Energy Progress, Georgia System Operations Corporation, Georgia Transmission Corporation, LG&E and KU Energy, MEAG, N.C. Municipal Power Agency No. 1, NCEMC, Oglethorpe Power Corp., PowerSouth, Santee Cooper, Southern Company and TVA.

With the addition of these Florida companies, the SEEM footprint would include 23 entities in parts of 12 states with more than 180,000 MW (summer capacity; winter capacity is nearly 200,000 MWs) across two time zones.

Calif. Energy Commission Updates Load Management With Call for Time Sensitive Rates

October 14, 2022

by Peter Maloney
APPA News
October 14, 2022

In a ruling that affects the state’s investor-owned utilities, as well as some of its largest public power utilities, the California Energy Commission (CEC) recently updated the state’s load management standards, including measures calling for rates that reflect costs and emissions in a more timely fashion.

Under the updated standards, which take effect April 1, 2023, Pacific Gas and Electric, Southern California Edison, San Diego Gas & Electric, Sacramento Municipal Utility District (SMUD), Los Angeles Water and Power (LADWP), and large community choice aggregators will be required to:

The updates will save consumers money by shifting usage to times of cheaper or abundant electricity, the CEC said, adding that a better-balanced grid slows the rise of electricity costs, strengthens the grid, reduces the need for more fossil fuel plants, and avoids electricity transmission and distribution congestion.

The updates also will help customers take better advantage of utilities’ lower time-dependent rates so smart appliancdes can be used and buildings can automatically respond to more frequent rate changes that reflect electricity grid conditions, the CEC said. That change will save consumers money by shifting usage to times of cheaper or abundant electricity, the CEC said.

The CEC expects the changes have the capacity to produce $243 million in net benefits over 15 years and could reduce annual peak hour electricity use by 120 gigawatt hours.

The CEC, as the state’s primary energy policy and planning agency, has statutory authority to adopt standards to help shift energy use.

Since 1978, the CEC encouraged load management through utility air conditioner cycling programs that automatically reduce use at commercial or industrial sites.

And, over time as technology has advanced, more appliances such as thermostats, pool pumps and residential water heaters have been automated to reduce use or shift time of use from high-demand hours, in response to signals from utilities and energy aggregators.

APPA Survey of Members Shows Distribution Transformer Production Not Meeting Demand

October 12, 2022

by Paul Ciampoli
APPA News Director
October 12, 2022

An American Public Power Association (APPA) survey of its members shows that production of distribution transformers is not meeting current demand, “as evident in the significantly growing lead times, lack of stock in yards and the high number of project deferrals,” APPA said.

In August 2022, APPA surveyed its members about distribution transformer supply and demand. The survey “highlights the expanded nature of this problem subsequent to the results of two previous surveys we have done on this matter, beginning in November 2021,” APPA said.

The data from the survey informed the Department of Energy and the Electric Subsector Coordinating Council (ESCC) of the severity of the supply chain distribution transformer shortage across the entire electric sector.

Ninety-five public power utilities serving a total of 6,719,596 meters responded to the survey.

Along with its finding that production is not meeting current demand, another key takeaway from the survey is that demand has grown consistently in the past and will continue to rise in the future.

 Because demand is out pacing supply, many public power utilities are at a high risk of stocking out on transformers in 2022 or following one storm.

Between 2019 and 2020, demand across all voltage classes for distribution transformers rose 3.6% for public power survey respondents. During this period, the lead time to procure distribution transformers averaged two to three months. Economic forecasts anticipate that the calculated annual growth rate for distribution transformers in North America will continue to increase and  be 9.1% for 2022-2030.

Between 2020 and 2022, the number of distribution transformers purchased remained largely steady. However, beginning in 2021 and continuing into 2022, the number of distribution transformers available for purchase no longer meets the demand. Evidence for this imbalance can be seen in the significantly increasing lead times and the deferral of projects, APPA stated.

Meanwhile, between 2020 and 2022, average lead times to procure distribution transformers for all voltage classes rose 429% for public power respondents — from about two to three months pre-2021 to about 12 months in 2022. Some utilities reported being quoted lead times of more than three years.

APPA reported that many utilities are deferring or canceling infrastructure projects because they are unable to procure the additional distribution transformers required for these projects. Among public power utilities, one in five projects were deferred or canceled.

Most responding utilities reported low or near zero emergency stock, which is often used to recover post-disaster or to do infrastructure maintenance. Some public power utilities reported being within weeks of hitting the bottom of their distribution transformer stocks. In the event of a catastrophic hurricane or other natural disaster, the industry risks stocking out much sooner, APPA pointed out.

APPA continues to work through the ESCC and other forums to discuss the problems and identify solutions that the federal government can act upon to alleviate the supply chain shortages, specifically with regards to distribution transformers.

APPA has taken a number of actions to address ongoing supply chain challenges. APPA recently rolled out an additional feature to its eReliability Tracker that is available to all public power utilities and allows for voluntary equipment sharing by matching systems with the same distribution voltages. APPA also recently finalized a new supply chain issue brief. APPA members can download the issue brief here.

In May, APPA sent a letter to Secretary Granholm at the Department of Energy asking that they consider a temporary waiver of efficiency standards in distribution transformers that may lead to an increase in supply.  That request was declined in August.  In a speech in June at APPA’s National Conference in Nashville, Tenn., APPA President and CEO Joy Ditto urged member utilities to share their supply chain challenges with APPA so that the trade group can relay details on these challenges to federal partners and discuss how critical burdens on the sector can be alleviated.

In May, APPA convened a supply chain summit that included participation from public power utility officials who discussed their supply chain challenges and mitigation strategies.

Company Looks to Extend Operation of 2,400-MW Texas Nuclear Power Plant

October 8, 2022

by Paul Ciampoli
APPA News Director
October 8, 2022

Vistra Corp. on Oct. 3 announced that it is seeking to extend the operation of Luminant’s Comanche Peak Nuclear Power Plant in Texas through 2053, an additional 20 years beyond its original licenses.

Luminant is a subsidiary of Vistra.

The company has officially submitted its application for license renewal with the Nuclear Regulatory Commission. The two-unit nuclear plant has a capacity of 2,400 megawatts.

The current licenses for units 1 and 2 extend through 2030 and 2033, respectively. The company is applying to renew the licenses through 2050 and 2053, respectively.

DOE Releases Opportunities for Nearly $5 Billion in Carbon Capture Technologies

October 8, 2022

by Peter Maloney
APPA News
October 8, 2022

The Department of Energy (DOE) recently announced nearly $4.9 billion in funding opportunities that aim to demonstrate and deploy carbon capture systems, as well as carbon dioxide transport and storage infrastructure.

The funding, which derives from the Bipartisan Infrastructure Law, is designed to support three programs.

The Carbon Storage Assurance Facility Enterprise (CarbonSAFE) initiative, which is being managed by the DOE’s Office of Fossil Energy and Carbon Management (FECM), provides up to $2.25 billion to support the development of new and expanded large-scale, commercial carbon dioxide (CO2) storage projects with capacities to store 50 or more million metric tons of CO2, along with associated CO2 transport infrastructure. Projects should focus on detailed site characterization, permitting, and construction stages of project development under CarbonSAFE.

The Carbon Capture Demonstration Projects Program, being managed by the DOE’s Office of Clean Energy Demonstrations (OCED) in partnership with FECM, will provide up to $2.54 billion to develop six integrated carbon capture, transport, and storage demonstration projects that can be replicated and deployed at fossil energy power plants and major industrial sources of CO2, such as cement, pulp and paper, iron and steel, and certain types of chemical production facilities. The funding opportunity announcement (FOA) provides up to $189 million for up to 20 integrated front-end engineering design studies, with a second FOA expected later this year to support detailed design, construction, and operation of carbon capture projects, as well as transport and storage of the captured CO2.

The Carbon Dioxide Transport Engineering and Design initiative, being managed by FECM, will provide up to $100 million to design regional CO2 pipeline networks to safely transport captured CO2 from key sources to centralized locations. Projects should focus on carbon transport costs, transport network configurations, and technical and commercial considerations that support broad efforts to develop and deploy carbon capture, conversion, and storage at commercial scale. 

DOE FOAs require that applicants submit Community Benefits Plans detailing their commitments to community and labor engagement, quality job creation, diversity and equity, and implementation of the Biden administration’s Justice40 Initiative.

Oak Ridge Lab Report Helps Hydropower Operators Prepare for Climate Change

October 8, 2022

by Paul Ciampoli
APPA News Director
October 8, 2022

A new report from the Department of Energy’s Oak Ridge National Laboratory (ORNL) aims to provide hydropower operators data that will better enable them to plan for changing climate conditions.

The data collected and analyzed in the report can aid operators in shifting operational schedules and seasonal water use as part of an overall mitigation strategy in the face of changing climate conditions and reduced water availability, the report’s authors said.

Among other findings, the report projects that earlier-than-expected snowmelt season in the western United States is likely to impact water runoff, resulting in less water for hydropower generation in the summer months, just as energy demand grows. In addition, Increased evaporation because of rising temperatures is also putting a strain on water needed for flood control, navigation, municipal water supplies and industrial and agricultural use.

The report also found that, except for part of summer and fall, there is a persistent increase in projected precipitation, especially in the winter, resulting in a net annual precipitation increase of up to 8 percent.

On a seasonal basis, the report found that winter and spring runoff are generally projected to increase across the conterminous United States while summer runoff is projected to decrease for many parts of the country, especially in the West and the South, resulting in a shift in the timing and seasonality of the water availability.

That effect may be magnified in the Southwest and Southeast because hydropower reservoirs in those regions have less storage capacity than federal hydropower reservoirs under the control of the Bonneville Power Administration and the Western Area Power Administration, the report found.

As a result, on a seasonal basis, most models project increasing hydropower generation in winter and spring, and decreasing generation in summer and fall caused by earlier snowmelt and changing runoff, the report said.

The combination of declining winter heating load and increasing hydropower generation suggests that federal hydropower surpluses are likely during the winter months, the reports’ authors said. Thus, they said, the ability to shift water from winter to summer months and to maximize the revenue from winter surpluses to compensate for potential increased power purchase requirements in the summer will be valuable for all power marketing administrations.

The ORNL researchers used downscaled global climate projections to simulate future hydrologic conditions at 132 federal hydropower facilities across the United States to compile the report.

In order to provide more hydropower stakeholders with the tools and data to plan for climate change impacts, the Department of Energy said it is extending its research to non-federal hydropower facilities, whose operators may not have the resources to study and address these challenges.

PNNL Report Says Hydropower Can Still Perform During Extreme Droughts

October 8, 2022

by Peter Maloney
APPA News
October 8, 2022

Even during the severe droughts of the last two decades, hydropower has sustained 80 percent of average power generation levels, according to a report by researchers at the Pacific Northwest National Laboratory (PNNL).

“That’s a noticeable dip — but it’s still a lot of renewable energy,” Sean Turner, water resources modeler at PNNL and main author of the report, said in a statement.

The megadrought in the Southwest is the driest and longest in the last 1,200 years, depleting water reservoir levels to critically low levels over the past 22 years and has raised concerns among policymakers and system planners over the reliability of the electric grid.

Droughts particularly affect hydroelectric power dams, as well as some thermoelectric power plants that require large amounts of water for cooling. But drought rarely impairs hydroelectric power across all regions of the Western United States simultaneously.

In the last 20 years, there has not been a drought that has affected all major hydropower generation regions at once, the report said, noting that current river flows and reservoir levels in California and the Southwest are low due to ongoing drought, which affects hydropower generation in those regions, but the lion’s share of hydropower generation in the West is dispatched to the grid from the Northern Cascades and Columbia River Basin, in Washington, Oregon, Idaho, and British Columbia.

“The current drought is severe but it’s nowhere close to being the worst hydropower generation year for the West and water resource conditions are actually above average right now in the Northwest,” Turner said.

The report combined 20 years’ of annual power generation data from more than 600 hydroelectric power plants with historical precipitation data from eight hydropower climate regions of the Western United States and used the data to extrapolate hydropower generation as far back as 1900.

The findings were published in a retrospective report funded by the Water Power Technologies Office within the Department of Energy’s (DOE’s) Office of Energy Efficiency and Renewable Energy.

Meanwhile, another PNNL researcher is investigating how well hydropower dams perform during heat waves and exceptional load demand. PNNL power systems modeler Konstantinos Oikonomou that a heat wave can actually create favorable conditions for hydropower plants.

Rapid snowpack melt during a heat wave can help reservoirs fill with water, which can allow hydropower plants to meet increased load demand, Oikonomou said.

To further test their results, PNNL hydrologists and power system modelers simulated the effect of compound heat waves and droughts on the power grid and found that regional interconnections are critical to manage extreme events.

Oikonomou’s research is now focused on creating a new framework for simulating grid behavior under extreme weather conditions, such as compounding droughts and heat waves, and under occurrences like faulty transmission lines.

“This information will help power plant operators and system planners explore mitigation strategies to fortify the grid against outages,” Oikonomou said.

Broad Portfolio Approach Needed to Reach Affordable, Reliable Clean Energy: EPRI

October 8, 2022

by Peter Maloney
APPA News
October 8, 2022

A broad portfolio of clean energy technologies will be required to reach an affordable and reliable clean-energy transition, according to new research by the Electric Power Research Institute (EPRI).

The Low-Carbon Resources Initiative (LCRI) report, by EPRI and GTI Energy, modeled three scenarios to evaluate alternative technology strategies for achieving economy-wide net-zero emissions of carbon dioxide (CO2).

The All Options scenario assumes a full portfolio of clean energy technologies is available, including renewables, nuclear, fossil and bioenergy with carbon capture and storage, electricity storage, hydrogen and hydrogen-derived fuels, and biofuels.

The Higher Fuel Cost scenario assumes all technologies are available, but with higher costs for gas, oil, bioenergy, and CO2 transport and storage.

The Limited Options scenario assumes geologic storage of CO2 is not available and bioenergy supply is limited, but all other technologies are available.

Power Generation

Among the key findings, the LCRI report found that electric generating capacity would grow substantially, from 1,650 gigawatts (GW) to 4,860 GW, a 160 percent to 480 percent increase over current resources.

Across all scenarios, total wind and solar through 2050 ranged from roughly 600 GW to 3,500 GW, compared with 273 GW today, with the high end driven by electricity supporting hydrogen production.

Total clean firm capacity to balance the increase in intermittent resources also would grow, anywhere 1,140 GW to 1,446 GW, including a combination of natural gas, nuclear, hydrogen, hydro, geothermal, bioenergy, and electric storage technologies.

Nuclear Capacity

In all scenarios, the report’s authors found that existing nuclear would provide essential firm capacity in a net-zero energy system. In the Limited Options scenario, in which carbon capture and storage is restricted, new advanced nuclear technologies, such as small modular reactors, would provide around 60 GW of generating capacity as a carbon-free baseload option by 2050. Also, continued expansion and modernization of transmission and distribution network would be essential to support increased integration of renewables, electrification, and flexible demand-side resources. In all scenarios, they said, transmission and distribution investments would increase over time.

Natural Gas

Natural gas infrastructure would also play a crucial role in all scenarios in providing firm capacity for a transitioning power sector and for delivering low-carbon fuel to industry and buildings, particularly in colder climates, the report said. The composition of delivered gas varied by scenario and could include a blend of fossil, renewable and synthetic natural gas, and hydrogen, the report said.

With available options for carbon capture and storage, negative emissions, and blending, annual natural gas consumption could remain at levels similar to today, even in a net-zero energy future, the report said.

With higher natural gas prices, pipeline gas consumption would decline to about half of today’s level. In the Limited Options scenario, without carbon capture and storage, renewable and synthetic natural gas could substitute for fossil gas and pipeline gas consumption would decrease to around 17 percent of current levels.

The report found that carbon capture and storage technologies would be “pivotal” for the new natural gas plants that would be needed to provide up to 33 percent of clean firm capacity and, potentially, a significant portion of hydrogen and ammonia production.

Hydrogen

The report also projects the use of hydrogen as a low CO2 fuel will increase whether through fuel cell vehicles, blending with the natural gas supply to support needs in buildings, or through direct use for process heating in industries. And in a scenario in which carbon capture and storage is limited, hydrogen use will “expand significantly.” Bioenergy could also emerge as another key decarbonization resource, providing low-CO2 alternatives to petroleum-based fuels.

Energy Efficiency

The report’s modelling shows that adoption of efficient electrification technologies and structural shifts to less energy-intensive activities across the economy will combine to reduce final energy 25 percent to 38 percent by 2050 compared with current levels, even with 80 percent GDP growth compared with 2020. Final energy refers to energy consumed at the point of end use.

The modeling shows that “reductions in energy consumption enable emissions reductions throughout energy value chains and across the transportation, buildings, and industrial sectors through technological improvement and switching to more efficient energy carriers and technologies,” the report’s authors said. Many of those changes are cost effective and are assumed to occur even in the absence of an explicit decarbonization target, they added.

Overall, “optionality enables affordability,” the authors concluded. “Achieving economy-wide net-zero CO2 emissions while maintaining reliable delivery of energy and energy services across the economy will require a broad set of low-carbon technologies,” they wrote, adding that a flexible approach to CO2 reduction would allow each sector and region “to follow their own decarbonization path while minimizing overall costs.”

“Imposing greater limitations on resource and technology options could significantly increase the overall cost to achieve net-zero emissions,” the report’s authors said.