Energy Systems Analysis

This study explores the energy system impacts of large-scale synthetic methane (e-gas) exports from the United States to Asia, using the US-REGEN energy-economy model. The analysis evaluates how varying levels of export demand—centered on Japan and Southeast Asia—could interact with U.S. decarbonization pathways, infrastructure constraints, and technology deployment. Scenarios span a range of demand levels and policy environments, including a Reference case and a Net-Zero-by-2050 target.

Results show that e-gas production is concentrated in regions with strong wind resources (e.g., SPP and MISO-North). Inter-regional pipeline congestion and renewable resource limits can shift production to other regions like Texas in the highest export-demand scenarios. High-export scenarios significantly increase electrolytic hydrogen production needs and drive expansion in wind, solar, and gas-fired generation, with nuclear also playing a key role in the highest-demand scenarios. In the absence of stringent national emissions targets, e-gas exports can lead to a modest increase in domestic CO2 emissions. Net-Zero targets can exert greater influence on e-gas prices than demand growth.

Robust growth in electric sector capacity in recent years has likely been slowed by technical, policy, and economic barriers, including but not limited to interconnection queues, permitting, availability, cost of emerging technologies, inflation, and supply chain delays. Incorporating these barriers into models is often challenging, resulting in a divergence between model results and realized deployment rates. This analysis attempts to address this challenge by developing scenarios that constrain deployment rates of power system assets, reflecting possible realizations of uncertain barriers.

Net-zero climate targets are being discussed and even requested; however, there is very little scientific discussion of net-zero strategies for local decision-makers such as regions, cities, and corporations. With stakeholders calling for net-zero targets, there is need for scientific guidance. This brief addresses this issue and, using available resources and illustrative analysis, generates foundational insights for more informed dialogue and development of local strategies and policies, which are critical for realistic, actionable solutions. Across analyses, the article finds evidence that net-zero is not for everyone. It is essential to consider differences in decarbonization opportunities and enabling conditions that will help balance the challenges of decarbonization and facilitate greater ambition. Companies, policy-makers, stakeholders, and researchers will find this brief to be of value given its insights regarding potential local low-carbon strategies and transitions and opportunities for progress managing the climate.

The material included in this report originally was developed as a set of technical briefing papers to accompany a series of webcasts conducted as part of EPRI’s 24/7 Carbon-Free Energy Buyers Forum collaborative supplemental project. These webcasts explored key issues associated with the procurement of hourly-matched carbon-free energy (CFE) by the federal government and large commercial and industrial (C&I) companies. This technical update summarizes information developed for this project on three key topics related to the potential deployment of CFE on a 24-hour, seven day per week basis (24/7 CFE): 1) A review of existing and advanced future carbon-free power generation technologies and their expected cost and performance; 2) Energy supply agreements and electric utility tariff designs that may facilitate deployment of 24/7 CFE; and 3) Data tracking and reporting associated with the purchase and use of 24/7 CFE products.

This is an update to the Net-Zero 2050: U.S. Economy-Wide Deep Decarbonization Scenario Analysis, originally published in 2022. The 2024 update includes revised technology assumptions, representation of current policies, emerging trends in data center loads, and a broader perspective on uncertainty with a range of technology and sensitivity cases.

To access LCRI Net-Zero 2050: Sensitivity Analysis and Updated Scenarios v2.0, click here: https://lcri-netzero.epri.com

Platform Requirements

Modern web browsers for desktop or mobile operating systems, including recent versions of:

• Chrome
• Safari
• Firefox
• EDGE

Data center (DC) activity and electricity use have increased rapidly in recent years and are expected to grow significantly in the years ahead, especially with emerging applications of artificial intelligence (AI) for commercial and consumer use as well as growing demand from small-scale data centers, large-scale commercial data centers, and cryptocurrency mining. The need for power has become a critical consideration for DC and AI growth with multi-year connection lead times, demand for reliable electricity, and company emissions targets all creating the potential for regional electricity supply challenges. However, projections of electricity consumption from these fast-moving technologies remain uncertain. Responses to anticipated load growth include both new investments by electric companies and direct power acquisition by DC developers. Both can reflect corporate procurement preferences for clean energy, as seen for example with recently announced dedicated nuclear and geothermal projects. An earlier EPRI white paper discusses key considerations for DC impacts on the power sector and highlights key steps to support rapid DC expansion.

This paper builds on that effort, providing updated projections for future regional load growth from data centers; estimates of load growth from other sources including domestic manufacturing, end-use electrification, and electrolytic hydrogen; and analyses of how these loads could alter electric sector investment decisions and carbon dioxide (CO2) emissions under a range of future policy (including current policy and economy-wide net-zero by 2050 cases) and corporate strategy scenarios.

Data center operation is one of the fastest growing industries worldwide. The International Energy Agency recently projected that global data center electricity demand will more than double by 2026. In the United States, the national outlook could resemble the global outlook, but is highly uncertain.

One key uncertainty that could change the trajectory of data center load growth is the use of generative AI models. Both public and corporate imaginations were triggered by the release of OpenAI’s ChatGPT on November 30, 2022. Evidence about how widely these tools will be used and how much they will change computational needs is just starting to emerge. These early applications were estimated to require about ten times the electricity—from 0.3 watt-hours for a traditional Google search to 2.9 watt-hours for a Chat- GPT query—to respond to user queries. Creation of original music, photos, and videos based upon user prompts and other emerging AI applications could require much more power. With 5.3 billion global internet users, widespread adoption of these tools could potentially lead to a step change in power requirements. On the other hand, history has shown that demand for increased processing has largely been offset by data center efficiency gains.

EPRI highlights three essential strategies to support rapid data center expansion:

1. Data center efficiency improvements and increased flexibility.
2. Close coordination between data center developers and electric companies regarding data center power needs, timing, and flexibility, as well as electric supplies and delivery constraints.
3. Better modeling tools to plan the 5–10+ year grid investments needed to anticipate and accommodate data center growth without negatively impacting other customers and to identify strategies for maintaining grid reliability with these large, novel demands.

Momentum for decarbonization is building in the United States, driven by company targets, state and federal policy, and stakeholder advocacy for greater ambition and transparency. Planning and decision-making for decarbonization will consider the interactions between technology, economics, energy demand and policy in the U.S. power sector, and the entire energy economy. This report draws insights and sensitivities from several EPRI decarbonization pathway studies and summarizes a set of key decarbonization drivers to offer a framing of the energy industry’s ongoing transformation.

However, beyond the question of “what technology mix aligns with a pathway to decarbonization?” there are several core challenges that impact the feasibility, and speed at which decarbonization can occur. These challenges include the supply chain, development of advanced technologies, reliability, electrification, demand-side participation, load forecasting, and climate resiliency. This report offers a summary of each, and highlights EPRI research and initiatives to address each challenge. The broader energy transition is comprised of these challenges, in addition to decarbonization. Furthermore, these energy transition challenges influence and interact with one another, and a broad understanding of these interactions may improve company strategy and long-term planning.

The international climate policy community aspires to limit global average warming to well below 2°C, including the possibility of limiting warming to 1.5°C. Countries, states, communities, and companies are trying to understand their potential decarbonization roles, opportunities, and risks, as well as develop decarbonization and risk management strategies. Stakeholders, including investors and regulators, are also interested in company climate risks and their disclosure. Understanding the differences and similarities in regional decarbonization opportunities and risks is essential for developing practical, viable, and cost-effective policies and strategies. Using existing available global and U.S. modeling results, this study evaluates differences in regional decarbonization opportunities—globally and within the United States (U.S.). The study finds that decarbonization opportunities and costs vary significantly between global regions and within the U.S. with, among other things, regional emissions reduction rates not equal across regions or to the global or national rates respectively. U.S. regional power sector decarbonization opportunities and pathways vary significantly due to relative regional differences in endowments, current conditions, and future opportunities, with endowments and future low-carbon alternatives the primary factors defining cost-effective regional decarbonization opportunities and transition differences; and, R&D, markets, and policies that encourage utilization of regional endowments and comparative advantages facilitating management of societal transition trade-offs (e.g., costs, reliability, local development, equity). This study is part of EPRI’s suite of technical resources associated with climate risk assessment and greenhouse gas target setting.

The world has changed since the U.S. announced in April 2021 the goal to reduce economy-wide greenhouse gas emissions to 50% below 2005 levels by 2030 and to achieve net-zero economy-wide emissions by 2050. Rapid and ongoing changes to energy technologies, markets, and policy are affecting pathways to a low-carbon future, particularly the pathways to the near-term, interim 2030 target. This analysis updates earlier EPRI research of 50x30 pathways to account for new challenges and near-term uncertainties that have arisen since 2021, including increased costs for energy technologies and fuels as well as updated incentives such as those in the Inflation Reduction Act of 2022 (IRA). Relative to 2021, a rebound in emissions, increased inflation, and more constrained supply chains increase the challenge of halving emissions by 2030, but IRA could offset some of these impacts and accelerate the deployment of clean electricity, electric vehicles, and other low-carbon technologies. The rate of emissions reductions must increase beyond historical trends by several times to meet 2030 targets and continue at a similar pace to reach net-zero emissions by 2050. Core decarbonization pathways remain similar to earlier analysis—clean electricity, energy efficiency, and electrification.

As part of the Low-Carbon Resources Initiative (LCRI), EPRI and GTI Energy led an integrated energy system scenario modeling exercise to evaluate alternative technology strategies for achieving economy-wide net-zero emissions of carbon dioxide (CO2) in the U.S. by 2050. The analysis builds on extensive, collaborative research, including an inter-model comparison assessment and related EPRI studies. The study found that a broad portfolio of clean-energy technologies is integral to an affordable and reliable clean energy transition. This report highlights several key insights for the potential role and value of low-carbon technologies, informing both R&D strategy and decarbonization investments over the next decade.

The executive summary and main report are accessible online at https://lcri-netzero.epri.com/.

Foresight assumptions are central to long-term electric sector planning and energy systems models. These model features can alter investments and shape policy analysis. With a particular focus on intertemporal perfect foresight and sequential myopic approaches, this investigation analytically and numerically assesses the conceptual and computational implications of model foresight assumptions. Results of the investigation include a mathematical outlining of the mechanism of divergence between model outputs with different foresight assumptions, development of a validated sequential myopic mode for EPRI's REGEN model, and associated numeric insights. The investigation concludes with recommendations for REGEN and long-term energy models more broadly, including a preliminary exploration of systematic combination of foresight approaches.

This white paper explores strategies to achieve the U.S. greenhouse gas (GHG) economy-wide emissions target of a 50–52% reduction from 2005 levels by 2030, identifying least-cost emission reduction actions across the electric sector, transport, buildings, and industry. Successfully implementing these strategies will require substantial policy changes coupled with accelerated deployment of electric end-use technologies and of electric sector technologies (including expedited financing, siting, permitting, and integration). While the analysis focuses on the U.S., many key findings provide insights that are valuable for nations with similar goals and rates of change.

In a new analysis, EPRI explores scenarios for achieving net-zero emissions targets in the U.S. electric sector in the context of deep economy-wide decarbonization, considering the implications of how the target is defined, the timing of the target, the costs of the transformation, and interactions with the end-use sectors.

This report examines the impacts of higher renewable portfolio standards (RPS) on electric sector planning in Arizona and the Western United States. The analysis explores the role of renewables in achieving CO2 reductions and the economic, environmental, and power sector investment implications of renewable standards vis-à-vis alternate approaches to reaching equivalent CO2 goals. Using the U.S. Regional Economy, Greenhouse Gas, and Energy (REGEN) model, results compare differences in generation mixes, system costs, and emissions between scenarios with renewable targets from 30–70% by 2030, increasing to 50–90% by 2050.

Many electricity utilities are announcing voluntary carbon dioxide (CO2) reduction goals for emissions from their generating units. Utilities with such goals accounted for at least 80% of electric sector CO2 emissions as of the year 2000. In addition, several states now have policies or proposed policies requiring electric sector decarbonization in their jurisdiction by 2050 or earlier. This technical update investigates the implications for U.S.-wide electric sector CO2 emissions if all utilities meet their stated goals, and if all states meet their stated targets. The results also include high level estimates of the dollars per ton implicit costs of reaching these targets given current technology costs, fuel costs, and other assumptions.

This analysis investigates and compares the cost-effectiveness of renewable energy standards and technology-neutral policies for reducing carbon dioxide (CO2) emissions from Minnesota’s electric power sector through 2050. Using EPRI’s in-house electric sector capacity expansion and dispatch model, US-REGEN, the analysis quantifies the cost-differences between the policy approaches, and examines the key drivers of those differences, including (1) how generation and transmission capacity investments in the state and across the region are expected to change over time; (2) the flow of electricity and renewable energy certificates (RECs) in-and-out of Minnesota; and (3) the revenues generated by in-state electric sector resources.

KEY INSIGHTS

• A technology-neutral carbon reduction policy (e.g., a CO2 target) could achieve the same level of CO2 emissions reduction in Minnesota at lower cost than a high renewable electricity standard of 60% by 2030 and 95% by 2050, saving $2.7 billion in total electric sector costs between 2015–2050.
• A high renewable standard would likely require significant investments in new transmission between Minnesota and neighboring states, more so than a comparable CO2 target.
• Operating under a CO2 target, Minnesota’s generation fleet could provide the state with higher electric sector revenues than under a comparable high renewable standard.
• A CO2 target supports approximately the same amount of new Minnesota wind, and more instate generation investment overall, than a high renewable standard achieving the same level of carbon reduction.

Data centers have become the fastest-growing source of U.S. electricity demand, and regional clusters of facilities are transforming local grid dynamics, fueled by increased consumer demand for streaming and other data-intensive services, cryptocurrency, and artificial intelligence (AI). Drawing upon state-level data on operational capacity, construction in progress, and announced plans, EPRI developed Low, Medium, and High scenarios for U.S. data center capacity growth through 2030. Data centers are projected to consume 9% to 17% of U.S. electricity by 2030, up from 4% to 5% today. The projected range of 2030 data center electricity demand is 60% higher than prior EPRI scenarios, which reflects the accelerated pace of data center development. Capacity continues to accumulate in primary data center markets, but the emergence of new capacity in other states suggests increased prioritization of power access and land availability, particularly for large AI training centers. Under reference policies, natural gas dominates incremental supply, while carbon-free energy commitments shift investment portfolios toward low-emitting generation and energy storage. Collaboration is essential to maintain and enhance grid reliability and to address affordability and community impacts as data centers connect to the grid.

This study explores the energy system impacts of large-scale synthetic methane (e-gas) exports from the United States to Asia, using the US-REGEN energy-economy model. The analysis evaluates how varying levels of export demand—centered on Japan and Southeast Asia—could interact with U.S. decarbonization pathways, infrastructure constraints, and technology deployment. Scenarios span a range of demand levels and policy environments, including a Reference case and a Net-Zero-by-2050 target.

Results show that e-gas production is concentrated in regions with strong wind resources (e.g., SPP and MISO-North). Inter-regional pipeline congestion and renewable resource limits can shift production to other regions like Texas in the highest export-demand scenarios. High-export scenarios significantly increase electrolytic hydrogen production needs and drive expansion in wind, solar, and gas-fired generation, with nuclear also playing a key role in the highest-demand scenarios. In the absence of stringent national emissions targets, e-gas exports can lead to a modest increase in domestic CO2 emissions. Net-Zero targets can exert greater influence on e-gas prices than demand growth.

The electric grid has long delivered reliable, cost-effective power to consumers, including data centers, by pooling diverse resources to lower costs and enhance reliability for all. This “good for all” model has fueled economic growth for more than a century. Today, nearly all data centers depend on the grid, with onsite backups providing additional resilience.

But rapid growth in data center demand—driven in part by AI processors with power densities up to 10 times higher per square foot than traditional storage-focused facilities—has exposed mismatches between grid expansion and data center development timelines. As a result, speed to power has become a critical factor in site selection.

This paper evaluates four broad strategies for powering new data centers globally. Currently, the dominant approach is Grid-Connected Inflexible where grid power is available on the required timeline. However, where there are significant grid constraints, three alternative strategies are emerging: Grid-Connected Flexible, Bridge-to-Grid, and Islanded.

Available online: speed2power.epri.com

Thermal energy networks offer a neighborhood-scale decarbonization strategy, using shared infrastructure to efficiently transfer thermal energy among interconnected buildings and shifting the focus from individual building-level solutions. While pilot projects have demonstrated localized benefits, the broader impacts of scaling thermal energy networks in the U.S. have not been explored. Assessing the full potential of these systems requires a systematic approach to identifying feasible deployment sites, assessing their technical and economic potential, and their integration into long-term energy system models. This report addresses the first step by (1) establishing key criteria for assessing the feasibility of thermal energy networks and (2) developing a geospatial methodology to map thermal energy sinks. The analysis presents a case study in Framingham, Massachusetts using scalable tools and publicly available geodata to characterize building stocks, calculate heating and cooling loads, and identify high-density load centers. Building-level heating and cooling load profiles are calculated using a gray-box model, aggregated into a thermal energy demand density map, and used to identify and characterize thermal sinks within the study area. The identified thermal sink aligns with sites selected for a potential thermal energy network pilot project, validating the methodology. Finally, the report provides guidelines to expand the analysis and advance the assessment of the system-wide value of large-scale deployment of thermal energy networks.

Geothermal energy is gaining attention as a reliable source of clean, firm power for the U.S. power sector, spurred by advancements in enhanced geothermal systems (EGS) and drilling techniques. To address its underrepresentation in capacity expansion models, EPRI and the National Renewable Energy Laboratory, with funding from the Department of Energy’s Geothermal Technologies Office collaborate in this project to enhance the representation of geothermal technologies and resources in EPRI’s US-REGEN model and to derive general guidelines for improving the representation in other capacity expansion models. To this end, hydrothermal, near-field and deep EGS resources are integrated following NREL’s ReEDS model temperature-based resource supply curves and cost assumptions. Six scenarios are analyzed with the improved geothermal representation, two economy-wide net-zero pathways—differentiated by the availability of carbon capture and storage (CCS)—across three geothermal cost scenarios (conservative, moderate and advanced). In the advanced cost scenario, geothermal, particularly deep EGS, could reach 36 GW of capacity nationally by 2050 in the pathway with CCS and 59 GW in the pathway without CCS, contributing up to 8.5% of total electricity generation. However, deployment remains limited under conservative and moderate cost assumptions. These findings underscore the relevance of incorporating EGS into capacity expansion models and offer guidelines for better technology integration. These guidelines emphasize consistent resource definitions, temperature-based classifications, regional disaggregation, and addressing cost uncertainty, while tailoring the technology representation to the model’s structure and complexity to ensure accurate and informed utility planning and policy development.

Nuclear energy is arguably an important option in the United States and global clean energy portfolios. The 2023 Conference of the Parties to the United Nations Framework Convention on Climate Change (COP28) finished with an announcement by leaders of 22 countries of a goal of tripling nuclear energy capacity by 2050 to meet climate goals and energy needs. However, nuclear power still faces a complex economic and policy environment that may challenge the growth of the industry. The development of new advanced nuclear reactor (AR) technologies could help the nuclear industry overcome some of these challenges and encourage a more robust expansion of nuclear capacity. Nonetheless, this growth will also depend on the market and policy conditions of the energy sector. This analysis investigates the conditions under which nuclear power could play a role in future markets in the United States and Canada. This study uses EPRI’s North America Regional Economy, Greenhouse Gas, and Energy (NA-REGEN) energy-economic model to explore tradeoffs across assumptions about technologies, markets, and policies. Model results suggest that ARs could be economically viable across a range of scenarios, but there may need to be substantial changes in current market and policy conditions in order to spur stronger deployment of AR capacity in the United States and Canada. The results show substantial variation in the regional economic viability for AR power across the United States and Canada.

Today’s accelerating shift from internal combustion engine vehicles to electric alternatives provides an essential path to decarbonization but requires retooling of the auto industry, rapid expansion and updating of the electric grid, and creation of new, secure mineral supply chains. In this paper, the Natural Resources Defense Council (NRDC) and EPRI explore the fundamental role that future vehicle efficiency improvements—additional and complementary to electrification—can play in lessening infrastructure and energy needs and reducing consumer costs. Electrification by itself brings major energy savings and other benefits, but the additional and often-overlooked improvements considered here reduce the amount of electricity needed to power vehicles, which is projected to be a large future load. This study characterizes key automotive technology advances and examines their potential impacts from the perspective of consumers, electricity and charging infrastructure providers, and automakers. Efficiency and lightweighting steps could effectively cut energy consumption per mile in half over the next 30 years. If these steps are achieved without raising vehicle costs, the study projects consumer energy cost savings of more than $200 billion annually for on-road transportation traveled by 2050, including reduced investments in the physical grid and charger buildout needed to support the shift towards electric mobility. Further work is suggested to examine in more detail the cost of the proposed vehicle efficiency strategies, to estimate the supply chain benefits of getting more miles from less battery material, and to conduct a broader assessment of additional ways that more efficient vehicles can contribute to consumer, automaker, and grid value.

Low-carbon ammonia produced with low-carbon electricity (green) or carbon capture (blue) has the potential to serve as a critical component of a future decarbonized energy system, whether it is used in the chemicals industry, for example, as feedstock for fertilizer; used as a hydrogen carrier; or used directly as a fuel. While low-carbon ammonia synthesis has been considered cost-prohibitive in the past, recent US Inflation Reduction Act (IRA) incentives for clean energy and hydrogen production have the potential to reduce production costs. This project develops a feasibility study to evaluate the levelized costs (with and without IRA incentives) and resource requirements of producing blue and green ammonia in the US in the 2030 timeframe. This study finds that low-carbon ammonia production costs with IRA credits may be comparable to historic grey ammonia prices in select regions in the US. IRA credits have the potential to reduce levelized costs, lowering green ammonia costs by up to two-thirds and blue ammonia costs by approximately 20%. Results suggest that green ammonia produced in regions with good-quality wind resources (for example, SPP or Texas) may have levelized costs (LCOA) under $300/tonne, while blue ammonia may be more competitive than green ammonia in several US regions at low gas prices. The study further considered the transport of ammonia from the US to Japan, which may increase costs by approximately $100/tonne of green ammonia. This study also analyzed the electric resource requirements for green ammonia production. Using data from modeled scenarios for green ammonia, this study found that 2–8 GW of electric resources per million tpy green ammonia (primarily for hydrogen production) may be required, depending on the resources utilized. Note that these values depend strongly on the quality of the electric resources, the levels of demand, and the available electric resource supply in a given region and, therefore, are presented here as first-order estimates only. More detailed analysis with site-level information will be required when considering specific projects. Further, this study estimates that 1.6 million tpy CO2 sequestration potential may be required per million tpy blue ammonia.

Provisions in the U.S. Inflation Reduction Act (IRA) strongly incentivize clean energy production, including subsidies for low-carbon hydrogen production and carbon capture utilization and sequestration. These provisions could alter the economics of clean fuel production for domestic use as well as export. Methane derived from CO2 and low-carbon hydrogen, typically referred to as e-gas or e-methane, is one such clean fuel — a low-carbon alternative to fossil-based natural gas. This project develops a feasibility study to evaluate the resource potential and levelized costs of producing U.S. e-gas, synthesized from biogenic CO2 captured from existing ethanol plants and low-carbon hydrogen sourced directly from renewable electricity, for export to Japan. The study uses insights from prior modeling with EPRI’s U.S. Regional Economy, Greenhouse Gas, and Energy (US-REGEN) model, supporting LCRI. This study estimates an upper bound on the amount of e-gas that theoretically could be produced using available biogenic CO2 from ethanol plants, as well as the amount of hydrogen (and electrolysis) required to support this level of e-gas production. A levelized cost analysis was developed for a range of scenarios of e-gas production that primarily vary in the location of hydrogen production, e-gas synthesis and fuel/products transport. Results based on current ethanol production levels suggest a total U.S. e-gas potential of 15.6 million metric tons per year (770 tbtu per year, based on higher heating value) with levelized costs that could vary between $1.1 and $1.5 per kg ($23 - $30 per MMBtu) e-gas. Hydrogen production costs (driven by electrolyzer costs) and synthesis costs strongly impact the estimated levelized costs. The amount of hydrogen required to support this level of e-gas production, 9.8 million metric tons per year (1,100 tbtu per year, based on lower heating value), is equivalent to current levels of U.S. annual hydrogen production and may require 80 GW or more of new wind resources. This study also provided additional context on several factors that could affect the feasibility of e-gas production, including a) sensitivity analysis around e-gas synthesis costs b) existing natural gas pipeline utilization c) pathways of future biofuel production d) uncertainty around IRA incentives and e) siting and permitting challenges for new infrastructure.

Increasing electrification in the buildings, industrial, and transport sectors will lead to changes to both the magnitude and shape of future electricity demands. While these changes pose potential challenges for electricity system operation, electrification also provides opportunities for greater demand flexibility. Moreover, as utilities expand intermittent renewables to meet decarbonization goals, system flexibility and the technologies that can provide this flexibility are expected to become increasingly valuable. Most capacity expansion models are limited to supply-side technologies for providing flexibility, such as flexible generation, transmission, and energy storage. However, there is growing evidence that flexible demand resources may be able to provide substantial system flexibility at lower cost. To explore the value of flexible demand resources, this research developed a novel methodology for including flexible demand resources in a capacity expansion model so that investments in flexible demand compete directly with flexible supply. Managed light-duty vehicle (LDV) charging is used as a case study since personal light-duty vehicles are parked for most of the day and thus represent a potentially large flexible demand resource.

Transport electrification is expected to be one of the largest contributors to electricity demand growth over the next few decades and uncoordinated vehicle charging may exacerbate peak loads. Yet light-duty vehicles are parked for most of the day and thus plug-in electric vehicles may collectively represent a large flexible demand resource. This study introduces a novel method for assessing the value of flexible demand resources in EPRI’s capacity expansion model (US-REGEN) using coordinated vehicle charging as a case study. We quantify the dispatch and value of coordinated vehicle charging in different regional contexts, across various levels of consumer participation, and for a range of workplace electric vehicle supply equipment (EVSE) costs. We find that coordinated vehicle charging is valuable in most regions, but especially in regions with large solar generation shares. In these regions, there is a strong incentive to shift vehicle charging to the daytime (and particularly to workplaces) so that it better aligns with solar output. To do this, the utilization of existing workplace EVSE capacity should be maximized. However, investment in new workplace EVSE capacity is only economic if costs decline well below today’s costs, either through technological learning or subsidies. Coordinated vehicle charging leads to cost savings by reducing investments in energy storage.

In recent years, prospects for the future deployment of battery energy storage resources in the electric sector have increased markedly, as battery costs have declined, and their technical performance has continued to improve. However, battery energy storage technologies have complex cost, value, and performance characteristics that make them challenging to model in long-term power system capacity expansion models.

Phase 1 of this project explored the potential value of incorporating five features that are not commonly represented in existing long-term capacity planning models: (i) battery energy storage system (BESS) degradation; (ii) grid (network) modeling; (iii) ancillary services; (iv) sub-hourly temporal resolution; and, (v) uncertainty. Simulation results identified that BESS degradation is the feature with the largest impact on planning outputs in models with energy storage.

Phase 2 of this study, which is described in this report, takes the next logical step and focuses on experimenting with different degradation models for Lithium-ion battery energy storage systems in a capacity planning model. The objective of Phase 2 is to answer the question: What is the most economically efficient (that is results in the lowest overall system costs when degradation is taken into account) and computationally efficient approach to battery degradation that can be incorporated into long-term power system resource planning models? To answer this question, five methods to make a capacity planning optimization problem “degradation-aware” were developed and simulation experiments were completed that incorporated one method at a time. These simulations were done using a “maquette” version of a large power system located in the Southeastern United States.

Experimental results show that selecting a proper degradation approach can materially reduce total system costs relative to a result that assumed a fixed battery lifetime. Models that keep the battery’s state of charge at lower levels can extend the battery’s operational life and improve economic efficiency (that is the added benefit of extending the battery’s life exceeds the added cost of controlling the

battery’s use pattern). Other models that limited the total amount of energy discharged from the battery or simulated energy capacity fade are not as economically efficient. Many of these degradation simulation models can be solved in a computationally efficient manner and do not add a significant computational burden to existing battery optimization models.

Capacity expansion models used by electric companies to develop future long-term resource plans continue to evolve to be able to better assess the potential value and future deployment of energy storage and other emerging power system technologies. One challenge in developing these new and improved models is that doing so often requires tradeoffs between economic efficiency and computational complexity. The simulation results in this analysis pave the way for incorporating “degradation-aware” yet computationally light models for battery storage systems in power system capacity planning problems.

Expectations for the future role of energy storage resources in the electric sector have increased in recent years, as technological developments have been accompanied by policy support. However, energy storage technologies have complex cost, value, and performance characteristics that make them challenging to model.

This analysis aims to determine which features that are not commonly represented in existing long-term capacity planning models may, if included, materially alter key decisions related to how much energy storage is expected to be cost-effective. Using an integrated model of capacity planning and operations, the analysis varies the inclusion of five features to understand how model complexity can impact planning insights: degradation, grid (network) modeling, ancillary services, subhourly temporal resolution, and uncertainty.

Model results indicate that degradation has the largest impact on planning outputs, including those related to energy storage deployment and operations. Other features have smaller impacts on investment and dispatch outcomes. Grid modeling does not alter cost-effective levels of energy storage in the conventional capacity planning setting with a fixed planning reserve margin, though it impacts transmission planning decisions on the locational placement of resources. The extent of cost-effective battery storage capacity in these scenarios is primarily driven by capacity needs, but energy time-shifting represents a non-trivial fraction of the system value of storage.

Long-term electric sector capacity planning models continue to evolve to more comprehensively assess the potential value of energy storage and other emerging technologies. Model formulation decisions entail tradeoffs between the accuracy of the representation and model parsimony, and determining which model details matter can help to prioritize efforts and to ensure the appropriate valuation of resources under wide range of possible futures.

This analysis investigates the conditions under which nuclear power could play a role in future markets. This study uses EPRI’s U.S. Regional Economy, Greenhouse Gas, and Energy (US-REGEN) energy-economic model to explore tradeoffs across assumptions about technologies, markets, and policies.

Model results suggest that advanced nuclear could be economically competitive across a range of scenarios and that several key drivers may influence deployment:

• Energy and environmental policies. Policy and market environments (for example, emissions pricing) may drive nuclear deployment as much as cost targets.
• Revenue streams. The extent of advanced nuclear deployment depends jointly on changes in costs and market value of different technologies.
• Regional factors. Key regional differences (for example, gas pipelines, policies, existing asset mixes, and transmission) make the economic competitiveness of advanced nuclear vary across the country.
• Capital costs. Capital cost “sweet spots” for new nuclear investments depend critically on the costs of other technologies and on markets (such as gas prices).

Market opportunities hinge on a combination of these factors, which impact the competitiveness of nuclear relative to other electric sector resources and require modeling to evaluate.

Extensive deployment of advanced nuclear would likely require new policies, innovation in technologies to significantly lower costs, and/or innovation in business models and markets to enable supplemental revenue streams. With policies targeting emissions reductions, the presence of technologies such as advanced nuclear can reduce compliance costs. However, simultaneous cost reductions for other generation options—especially dispatchable low-carbon technologies—create additional economic competition for nuclear deployment.

On August 25, 2025, the Minnesota Public Utilities Commission (‘The Commission’) published a notice of public comment soliciting public feedback on its proposed use of regulatory costs of greenhouse gas (GHG) emissions in utility resource planning (Docket Number E999/CI-07-1199; G008,G002,G011/CI-23-117; G999/CI-21-565). Under the proposal, state natural gas utilities would be required to assign costs to the GHG emissions associated with their plans and operations. This is a significant development with precedent setting potential for other states, as well as potential federal policy. To EPRI’s knowledge, this is the first time GHG pricing has been suggested in gas utility resource planning. As such, there are new technical issues that are important for The Commission, utilities, and the public to consider.

On November 21, 2025, EPRI submitted the public comments in this document to The Commission and the related public docket. EPRI has been studying topics directly related to the issues at hand for nearly twenty years and has over fifty years of research experience in the relevant underlying science. EPRI’s comments identify the following important technical considerations if applying the costs of GHGs in natural gas utility resource planning:

1. Communicating the distinction between the cost of GHGs and the social cost of GHGs
2. Designing a study to estimate ranges of costs of GHG values for Minnesota to capture local emissions transition opportunities
3. Accounting for natural gas emissions abatement policies to avoid additional costs in reducing GHG emissions
4. Clarification on whether non-CO2 GHGs are being considered and subsequent public input
5. Technology portfolios when applying regulatory costs in gas planning
6. Clarification on the types of emissions being considered and subsequent public input
7. Emissions leakage when applying regulatory costs in gas planning
8. Evaluation of natural gas price implications

EPRI’s public comments include a detailed discussion for each topic, as well as references to supporting research and resources.

EPRI’s public comments primarily draw on its extensive research related to the estimation and use of the social costs of greenhouse gases (EPRI’s Social Cost of Greenhouse Gases Scientific Initiative) and related to the development of corporate climate targets and strategies (EPRI’s SMARTargets Initiative).

Market drivers (including data center load growth, shifting fuel prices, and evolving federal incentives) are reshaping energy system investments, while U.S. state clean energy and emissions policies are expanding. This analysis uses EPRI’s U.S. Regional Economy, Greenhouse Gas, and Energy Model (US-REGEN) energy systems model to evaluate how policy and market drivers could affect energy technology investments, fuel use, emissions, and costs through 2050. Model results suggest that state policies may accelerate the adoption of emerging fuels and technologies, with the scale and composition set by policy stringency and costs. Electric capacity additions and load growth exceed recent historical rates across most scenarios and regions. Key findings highlight planning needs across resources, sectors, fuels, and geographies to meet growing energy demand while achieving reliability, affordability, and energy and emissions goals.

In response to the U.S. Department of Energy’s (DOE’s) draft report, A Critical Review of Impacts of Greenhouse Gas Emissions on the U.S. Climate, released in July 2025, EPRI submitted formal comments during the public review period. As an independent, non-profit research organization with a public-benefit mission, EPRI often develops objective, science-based comments grounded in its extensive R&D portfolio and its unique role as the electricity sector’s collaborative research organization.

EPRI’s comments in this case focus on the implications of the DOE report for the power sector, particularly in the areas of reliability, resilience, and adaptation. Drawing on research from EPRI’s Climate REsilience and ADaptation initiative (READi), as well as longstanding work in low-carbon pathways, air quality, and the social cost of carbon, the comments emphasize the importance of high-quality data, robust scientific foundations, and transparent methodologies. The report examines the DOE’s treatment of extreme weather, emissions policy, and socioeconomic risks, and offers constructive recommendations to improve the scientific rigor and practical relevance of the final report. EPRI’s contributions aim to support informed decision-making and continued public and scientific engagement on climate resilience and energy system planning.

This dashboard offers an interactive way to explore a curated collection of energy and end-use policies and incentives across the United States, spanning both state and federal levels. Users can interact with a hex map, pie chart, and searchable table to filter policies by state, policy type, sector, and more. Each policy entry includes a concise summary, key classifications (such as sector, date enacted, and policy type), and a direct link to the original source for further reading. This is a non-exhaustive list and we intend to update it with new releases over time. Whether you're conducting research, informing decision-making, or simply exploring the policy landscape, this tool provides a clear and accessible entry point.

Please visit https://apps.epri.com/energy-policy-dashboard to view this interactive dashboard.

Platform Requirements

Modern web browsers for desktop or mobile operating systems, including recent versions of:

• Chrome
• Safari
• Firefox
• Edge

Many countries are using investment- and subsidy-based climate policy approaches such as tax credits and grants. However, evidence is limited about the impacts of these policy instruments on energy systems and emissions. This analysis highlights potential issues in assessing the impacts of investment-based policies and brings together empirical and modeling estimates of impacts of the U.S. Inflation Reduction Act (IRA) as a case study. Data on clean energy manufacturing projects, household clean technology uptake, and public expenditures in the U.S. show record levels of investment after IRA’s passage—including a 64% increase from 2022 to 2024—and analysis suggests that further increases are expected in the future. Although IRA incentives could amplify trends of increased deployment of renewables, energy storage, and zero-emitting vehicles, there has been a notable trend break in announced investments in emerging technologies such as electrolytic hydrogen and carbon management. Modeled projections suggest that IRA could lower household energy bills by $85 to $430 per year and roughly double emissions reductions over the next decade.

This is an update to the Net-Zero 2050: U.S. Economy-Wide Deep Decarbonization Scenario Analysis, originally published in 2022. The 2024 update includes revised technology assumptions, representation of current policies, emerging trends in data center loads, and a broader perspective on uncertainty with a range of technology and sensitivity cases.

To access LCRI Net-Zero 2050: Sensitivity Analysis and Updated Scenarios v2.0, click here: https://lcri-netzero.epri.com

Platform Requirements

Modern web browsers for desktop or mobile operating systems, including recent versions of:

• Chrome
• Safari
• Firefox
• EDGE

In 2024, the U.S. Securities and Exchange Commission (SEC) issued a final climate risk disclosure rule; however, its future is uncertain. Nonetheless, climate risk assessment is valuable for company planning and there is increasing demand for climate risk information and disclosure. Company-level climate risk assessment and disclosure are new activities for most companies and stakeholders, with significant scientific and analytical needs and challenges. This publication identifies the technical requirements, analytical needs, and technical issues associated with preparing for and responding to the SEC’s rule, as well as climate disclosure in general. Overall, this publication provides technical perspectives to inform (1) potential future disclosure, (2) climate risk assessment analytical activities and communications, and (3) internal and external engagement.

Many electric companies have announced voluntary CO2 reduction targets, including goals to reach net-zero emissions from their generating units. Approximately 90% of 2005 power sector emissions are subject to either a utility target or state emissions policy. This deliverable tracks the implications of company CO2 targets and state-level decarbonization policies on U.S. power sector emissions using public data sources. This analysis indicates that power sector CO2 would decline by 75% by 2050 from 2005 levels if utilities and states meet their stated targets. Since the 2020 version of this analysis, the number of companies with net-zero targets not covered by existing state-level targets increased from 18 to 24, and many utilities increased the reduction percentages for interim targets. The analysis also documents that 58% of companies included in the analysis (covering 72% of emissions) mention environmental justice or equity in their climate reports.

The Inflation Reduction Act offers potentially beneficial tax credits for deploying new generation and storage assets, but some tax credit bonuses require compliance with certain criteria that may entail additional costs. Understanding the expected net benefit of the credits as well as some aspects of the market for apprenticeship labor and domestic content will help resource planners develop better cost assumptions for their planning efforts. This report begins with a brief overview of the Inflation Reduction Act of 2022 and an analysis of some of the key requirements for tax credit bonuses: the market for apprenticeship labor and domestic content in the United States. It then presents the findings of a cost study on compliance with the IRA’s labor and domestic content bonus requirements. The results indicate that compliance with the labor bonus requirements (prevailing wages and apprenticeships) may result in significant savings across technologies and credit types, whereas compliance with the domestic content bonus requirements (domestically sourced iron, steel, and manufactured products) may cost nearly as much or more than the value of the bonus.

Hydrogen and low-carbon fuels could play important roles in reaching economy-wide net-zero emissions, especially for applications in industry, transport, and energy storage. The Inflation Reduction Act (IRA) contains novel production tax credits for clean hydrogen (45V), which can have complex impacts on hydrogen production, electric generation, and emissions. This report describes an analysis using EPRI’s US-REGEN model to quantify potential impacts of the 45V subsidy under scenarios that vary qualification criteria and the scope of the demand response for hydrogen. The analysis indicates that 45V credits could lead to significant deployment of electrolytic hydrogen across all scenarios, while net emissions effects depend on the qualification criteria. Projected fiscal costs imply higher outlay per tonne of CO2 reduced than for other IRA provisions.

In May 2023, the U.S. Environmental Protection Agency issued proposed rules under Section 111 of the Clean Air Act titled “New Source Performance Standards for GHG Emissions from New and Reconstructed EGUs; Emission Guidelines for GHG Emissions from Existing EGUs; and Repeal of the Affordable Clean Energy Rule.” This report contains EPRI’s comments on the proposed rules and supporting information in docket EPA-HQ-OAR-2023-0072.

The U.S. Environmental Protection Agency is drafting new and existing source performance standards for the U.S. power sector under Sections 111(b) and (d) of the Clean Air Act, respectively. This analysis uses EPRI’s US-REGEN model to assess the potential implications of these rules for power sector investment decisions, operations, emissions, and costs. This modeling indicates that performance standard design decisions—especially their flexibility/trading provisions, form, and stringency—can materially alter electric sector outcomes.

On November 11th, 2022, U.S. EPA requested public input on its planned peer review of the draft new social cost of greenhouse gases (SC-GHG) estimation methodology that EPA released on the same day.

SC-GHGs are important metrics that are used in regulations and other federal decisions to assess policy proposals, justify actions, and set standards with significant financial and social implications. The U.S. Government SC-GHG estimates are also being considered by U.S. states and other countries. However, SC-GHG estimates are complex to calculate, requiring multi-century modeling of potential future global societies, climate change, sea level rise, and economic damages from climate change.

This publication represents the public comments EPRI submitted on December 1st, 2022, on EPA’s planned peer review process and peer review panel candidates. EPRI’s public comments are technical in nature and based on extensive EPRI SC-GHG related research and expertise covering SC-GHG estimation as well as application (i.e., use), including EPRI’s participation on the National Academies of Sciences, Engineering and Medicine (NASEM) Social Cost of Carbon committee, who’s recommendations EPA’s draft methodology was designed to address.

Overall, EPRI observes that EPA’s proposed peer review and overall scientific process is insufficient to develop scientifically robust and reliable estimates and insufficient for the public to have confidence in the outcome. Based on EPRI’s research and experience in this area, the process needs the following: a revised peer review candidate selection process and list to ensure full and unbiased coverage of the core scientific disciplines underpinning the SC-GHG, a peer review process that is expanded to a scientific review process appropriate for a regulatory methodology with significant implications, a substantial increase in opportunities for public engagement and input, and an improved overall scientific process for developing and using updated SC-GHG estimates. EPRI’s comments discuss each of these recommendations in detail.

Please also see EPRI’s public comments on EPA’s draft new SC-GHG methodology (3002026256), which finds that the methodology and estimates are not yet scientifically reliable and robust for policy use, with the methodology containing multiple significant technical issues and not satisfying the NASEM recommendations. The comments then provide specific recommendations for how to address these issues and move forward.

On November 11th 2022, the U.S. EPA released a proposed rule for regulating methane emissions from oil and gas operations (Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, Docket ID No. EPA–HQ–OAR–2021–0317). Along with the proposed rule, EPA introduced a draft new methodology for estimating the social costs of carbon and other greenhouse gases (SC-GHG).

The SC-GHGs are important metrics that are used in regulations and other federal decisions to assess policy proposals, justify actions, and set standards with significant financial and social implications. The U.S. Government SC-GHG estimates are also being considered by U.S. states and other countries. However, SC-GHG estimates are complex to calculate, requiring multi-century modeling of potential future global societies, climate change, sea level rise, and economic damages from climate change.

This publication represents the public comments EPRI submitted on February 13th, 2023, on EPA’s draft new SC-GHG methodology and use of SC-GHG estimates in the proposed rule. EPRI’s public comments are technical in nature and based on extensive EPRI SC-GHG related research and expertise covering SC-GHG estimation as well as application (i.e., use), including EPRI’s participation on the National Academies of Sciences, Engineering and Medicine (NASEM) Social Cost of Carbon committee, who’s recommendations EPA’s draft methodology was designed to address.

After thoroughly reviewing EPA’s draft new methodology, EPRI has found that the methodology and estimates are not yet scientifically reliable and robust for policy use. The methodology contains multiple significant technical issues and does not satisfy the NASEM recommendations. This should be addressed before the estimates are deployed to inform policy, for EPA’s methane rule and otherwise. In general, EPRI recommends an improved process, enhanced documentation, a revised methodology, and improved application of SC-GHGs. EPRI’s detailed comments include specific overall and module-specific and cross-module recommendations, as well as discussion of our technical observations that underpin each recommendation and insights that inform how to move forward.

EPRI submits these comments in response to the U.S. Department of the Treasury’s request for public comment on Implementing the Inflation Reduction Act’s Clean Energy Incentives. We file these comments under Notice 2022-57, Request for Comments on the Credit for Carbon Oxide Sequestration, while noting that the comments are broadly applicable to other Inflation Reduction Act energy generation incentives.

Browse posted comments here: https://www.regulations.gov/comment/IRS-2022-0028-0018

On January 13, 2022, EPRI submitted public comments on the Biden Administration’s advance notice of proposed rulemaking (ANOPR) for consid­ering greenhouse gas (GHG) emissions and the social cost of carbon in federal procurement (Federal Acquisition Regulation: Minimizing the Risk of Climate Change in Federal Acquisitions, FAR Case 2021-016). The ANOPR was published by the Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA). This publication represents EPRI’s public comments.

EPRI’s comments discuss important technical issues associated with potential procurement consideration of GHGs, including the risk of pricing GHGs more than once and the economic inefficiency of procurement as an emissions reduction policy instrument. The public comments are grounded by EPRI’s research, including its social cost of greenhouse gases (SC-GHG) and climate-related risk research, and touch on a variety of critical issues for industry and society that are relevant beyond the context of the ANOPR, including technically grounded use of SC-GHG estimates, GHG accounting and decision consideration, climate-related risk assessment, and GHG goal setting.

On February 26th, 2021, the Biden Administration published “interim” social cost of greenhouse gas (SC-GHG) estimates for carbon dioxide, methane, and nitrous oxide (link). In early May, the Administration requested public comment on the “interim” estimates and technical document, with comments due June 21st, 2021 (link). This publication represents the public comments EPRI submitted.

EPRI’s public comments are technical in nature and based on extensive EPRI SC-GHG related research and expertise covering SC-GHG estimation as well as application (i.e., use). The SC-GHGs are important metrics that are used in regulations and other federal decisions to assess policy proposals, justify actions, and set standards with significant financial and social implications. The U.S. Government SC-GHG estimates are also being considered by U.S. states and other countries. However, SC-GHG estimates are complex to calculate and use, requiring multi-century modeling of potential future global societies, climate change, sea level rise, and economic damages from climate change. EPRI’s public comments identify critical technical issues that need to be addressed for reliable, robust, and stable estimates and use in the near-term with the interim estimation methodology and policy applications, as well as in the longer-run in terms of scientific challenges that need to be overcome and the type of scientific review of future methodologies needed for public confidence in the estimates and the use of those estimates.

The Biden Administration has also requested “final” SC-GHG estimates by January 2022. EPRI’s comments identifying scientific challenges, and the opportunities for addressing them, inform that process as well. In general, EPRI’s comments stress the importance of putting science first and developing SC-GHG estimates as robust scientific metrics that can meaningfully inform decisions and instill public confidence in the insights generated.

Meeting a federal 100% Clean Energy Standard (CES) will require and drive transformative change in the electric power sector, even as other decarbonization efforts are underway across the country at regional and state levels and in other sectors. However, the extent to which this change may occur can depend on the specific provisions included (or excluded) in a CES, and ultimately implemented. Using EPRI’s in-house energy system modeling framework, the U.S. Regional Economy, Greenhouse Gas, and Energy Model (US-REGEN), this study quantifies differences between approaches to implementing a federal 100% CES by examining (1) changes in modeled generation portfolio choices; (2) other policy compliance choices such as electricity and credit trade and alternative compliance payments; (3) CO2 emissions; and (4) electricity prices across a range of policy design scenarios.

There is strong debate over whether and how to regulate CO2 emissions from the electric sector and consensus seems unlikely in the near future.  At the same time, electric companies have to make generation capacity investment decisions today that could last for 60 years, during which time CO2 policy could change dramatically.  For example, a gas-fired unit built today may face a price on CO2 at some unspecified time in the future which will increase the cost of dispatching that unit.  Under what conditions should an electric utility build low-CO2-emitting generation capacity today, even if it is not the lowest-cost alternative in today’s policy environment?  This technical brief summarizes the results of research on this question by the Electric Power Research Institute’s (EPRI) Program 201-B.

This analysis investigates and compares the cost-effectiveness of renewable energy standards and technology-neutral policies for reducing carbon dioxide (CO2) emissions from Minnesota’s electric power sector through 2050. Using EPRI’s in-house electric sector capacity expansion and dispatch model, US-REGEN, the analysis quantifies the cost-differences between the policy approaches, and examines the key drivers of those differences, including (1) how generation and transmission capacity investments in the state and across the region are expected to change over time; (2) the flow of electricity and renewable energy certificates (RECs) in-and-out of Minnesota; and (3) the revenues generated by in-state electric sector resources.

KEY INSIGHTS

• A technology-neutral carbon reduction policy (e.g., a CO2 target) could achieve the same level of CO2 emissions reduction in Minnesota at lower cost than a high renewable electricity standard of 60% by 2030 and 95% by 2050, saving $2.7 billion in total electric sector costs between 2015–2050.
• A high renewable standard would likely require significant investments in new transmission between Minnesota and neighboring states, more so than a comparable CO2 target.
• Operating under a CO2 target, Minnesota’s generation fleet could provide the state with higher electric sector revenues than under a comparable high renewable standard.
• A CO2 target supports approximately the same amount of new Minnesota wind, and more instate generation investment overall, than a high renewable standard achieving the same level of carbon reduction.

Can new electricity demand from data centers, electrification, and other sources actually lower average retail electricity prices? Despite widespread concerns, the answer is sometimes yes. This paper synthesizes economic theory, recent empirical and modeling evidence, and emerging tariff designs to clarify the conditions under which load growth can support affordability for existing customers while enabling investments in clean, reliable infrastructure.

Available online: https://winwin.epri.com/

Decarbonization and supporting policies can have important implications for household expenditures on energy services with distributional impacts across different customers. Recent policies and incentives have included carveouts and other considerations of distributional impacts, environmental justice, and equity. This analysis investigates one dimension of equitable decarbonization for the transport sector—namely, how household vehicle purchasing decisions can vary across income classes. Using detailed survey data and EPRI’s U.S. Economy, Greenhouse Gas, and Energy (US-REGEN) model, which has been modified to include income classes, this analysis illustrates the effects of income on vehicle electrification and associated implications for costs and energy burdens. Electric vehicle adoption increases for higher-income households due to characteristics such as their higher driving intensities and lower effective discount rates. However, these income effects are small relative to other considerations, as electric vehicle shares are high across all household incomes (60–80% of new sales are electric by 2050).