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In recent months, conflict in the Persian Gulf region has severely impacted global trade flows of energy and related products, highlighting the vulnerability of these supply chains to geographic and geopolitical factors. Exports from Middle East countries with significant oil and gas reserves, including Saudi Arabia, United Arab Emirates, Kuwait, Qatar, Iraq, and Iran, currently account for around 40% of global crude oil trade, 29% of trade in refined petroleum products, and 14% of natural gas trade, along with 20–30% of global trade in fertilizer and related inputs. Nearly all of these exports are transported by ship through the Strait of Hormuz, a narrow passage subject to strategic control by Iran and other parties.

This technical brief evaluates Global Warming Level (GWL) frameworks as an alternative to traditional scenario-year approaches for assessing climate hazards and informing energy system planning. Conventional climate assessments rely on projections tied to specific emissions pathways and future time horizons. This approach conflates uncertainties related to socioeconomic assumptions with those of climate model responses. In contrast, the GWL framework conditions climate outcomes on predefined global average temperature thresholds, effectively isolating the physical magnitude of global warming from model-driven regional variability.

By enabling comparisons across multiple models and emissions pathways at consistent warming levels, GWL-based analysis can provide a clearer interpretation of climate signals. However, each framework represents uncertainty differently: scenario-year approaches emphasize temporal evolution and pathway dependence, while GWL approaches focus on physical climate states independent of timing.

For utility planning, spanning infrastructure design, risk assessment, and regulatory compliance, these two frameworks are ultimately complementary. Rather than choosing one over the other, energy sector decision-makers can utilize hybrid approaches that integrate the temporal strengths of scenario-year modeling with the physical risk thresholds of the GWL framework. Finally, the brief identifies how emerging advances in climate modeling and artificial intelligence could further enhance these integrated assessments.

Recent proposed revisions to the Greenhouse Gas Protocol (GHGP) Scope 2 Guidance may significantly increase the geographic and temporal granularity required for location-based method (LBM) of scope 2 greenhouse gas (GHG) emissions accounting. While these changes are intended to improve accuracy, transparency, and comparability of corporate inventories, they may also introduce unintended internal consistency challenges when applied across regions with overlapping electricity grid boundaries. This white paper examines how the proposed emission factor (EF) hierarchy, particularly the prioritization of subnational and hourly EFs, can result in the overlapping attribution of grid emissions within a single corporate scope 2 inventory. The analysis demonstrates how mechanically applying the most granular accessible EFs at the facility level can lead to double counting of the same underlying generation resources and concludes by outlining practical approaches reporting entities can use to mitigate these double counting risks.

This success story describes a collaboration between Salt River Project (SRP) and EPRI to address limitations in traditional resource adequacy studies caused by insufficient temporal resolution in future climate data. Utilities increasingly face planning and operational uncertainty due to evolving weather patterns, electrification, and changing resource mixes, yet future climate datasets have historically lacked the hourly granularity and consistency required for robust reliability assessments. To bridge this gap, EPRI developed a forward-looking hourly weather dataset tailored to SRP’s planning needs, incorporating variables such as temperature, humidity, wind speed, and solar irradiance for future climate scenarios. The approach applies a climate data translation methodology that preserves historical variability while aligning projections with utility-ready formats. The resulting workflow enables integration of hourly climate-informed inputs into existing planning models and establishes a replicable approach for utilities seeking to enhance long-term resource planning and reliability analysis under changing climate conditions.

This interactive storyboard summarizes findings from recent Climate Vulnerability Assessments (CVAs) conducted at nuclear power plants under EPRI and INPO guidance. CVAs are systematic, forward-looking evaluations of how projected climate hazards — including extreme heat, drought, intense storms, and biological fouling — may affect plant structures, systems, and components (SSCs) and their ability to operate reliably. The storyboard walks through the CVA process in four phases: recognizing climate risks and assembling cross-functional teams; screening and characterizing site-specific climate hazards; evaluating plant-level exposure and vulnerability through engineering analysis and walkdowns; and prioritizing response actions using an eliminate–mitigate–accept framework. Key findings indicate that rising air and cooling water temperatures represent the dominant hazard across all sites assessed, that the majority of SSCs retain adequate design margin under current conditions while a small number of cooling and heat-rejection systems show narrowing margins under mid-century projections, and that indirect and cascading exposure pathways — rather than direct thermal stress on individual components — often drive the most consequential vulnerabilities. Lessons learned emphasize the value of cross-functional engagement, system-level exposure assessment, structured walkdowns, coordinated multi-site campaigns that share insights in real time, and early initiation of design-basis data requests.

Access the Story Map here: Climate Vulnerability Assessment

This illustrative case study applied portions of EPRI’s Climate Resilience and Adaptation initiative, or Climate READi™, framework to evaluate climate-related risks across the bulk and distribution grids for Wisconsin Power and Light Company (WPL) in the U.S. Midwest. It demonstrated how traditional planning processes can be leveraged to conduct climate-resilient planning by systematically integrating asset vulnerabilities, climate hazards, and societal considerations within a structured, coordinated approach.  Results provide detailed key findings for the bulk and distribution systems by integrating asset vulnerabilities into modeling frameworks to quantify the impacts of extreme weather and climate hazards on reliability, which informed system adjustments. The findings also demonstrated cost-effective pathways to strengthening system resilience against climate-driven events by assessing the effects of increased severity while also considering the broader impacts on prudent investment decisions.

Detailed sections include:

1. Bulk System Resilience through an Integrated Planning Framework
2. Distribution Grid Resilience Planning with Updated Climate Hazards
3. Accounting for Societal Considerations in Distribution System Planning
4. Applying Cost Benefits to Distribution Climate Resilience Planning

Click here to access the Story Map: Climate-Resilient Planning in the U.S. Midwest

This discussion paper presents a practical framework to help power system planners evaluate how much additional load, particularly from rapidly growing data centers (DCs), can be integrated without expanding generation, storage, or transmission infrastructure. As DC growth creates unprecedented planning challenges and opportunities for the electricity sector, the framework defines and quantifies available system “headroom” through a staged analytical approach. This approach combines probabilistic resource adequacy assessments to capture operational uncertainty; hourly nodal operations simulations to represent generator constraints and transmission limits; sub-hourly operations simulations to account for fast-response dynamics such as load variability and ramping; and power flow analyses to evaluate locational risks and transmission reliability requirements. At each stage, the framework compares inflexible and flexible DC operating profiles, demonstrating how DC flexibility—aligned with EPRI’s Flex MOSAIC™ flexibility classes—can mitigate reliability risks and unlock additional capacity. The paper also highlights practical considerations for realizing this headroom, including co-simulation of grid-enhancing technologies (GETs), and positions the framework as a complementary tool to follow-on analyses supporting faster, reliability-conscious large-load interconnection planning.

Electric utilities face challenges from tree related outages, which remain one of the most significant drivers of service interruptions across distribution systems. These outages already impose high reliability and resilience costs today, and the combination of aging infrastructure, evolving vegetation conditions, and intensifying climate stressors is expected to increase this risk in many regions. Vegetation management is one of the most resource intensive and operationally complex tools available for reducing outage risk, yet its effectiveness varies widely across geographies, forest types, weather regimes, and utility practices. Given the scale of investment required, utilities need a clear and evidence-based understanding of how vegetation management affects outage rates under current conditions, how these effects may change as the climate evolves, and how vegetation management compares to or interacts with other adaptation strategies. This report provides a foundation for understanding tree failures, their interactions with overhead distribution electric infrastructure, and the factors that influence how vegetation management can help reduce outages during storms, both today and in a changing climate moving forward.

Distributed generation (DG), particularly customer-sited solar and battery storage, is increasingly influenced by a diverse set of policy and incentive mechanisms implemented by states and electric companies. These incentives, including upfront rebates, performance-based payments, export compensation mechanisms, tax incentives, and behavioral rate structures play a critical role in shaping customer adoption and long-term distributed energy resource deployment. This project reviews existing incentive-based distributed generation programs across the United States, with a particular emphasis on Midwest electric companies in the U.S. The study evaluates the combination of policy levers and how they contribute to sustained distributed resource growth. In addition, the research assesses how DG programs and adoption drivers are currently represented in Integrated Resource Planning (IRP) processes. This project evaluates current modeling approaches and explores opportunities for more integrated representations of DG within planning models. The findings highlight the importance of layered policy frameworks and improved modeling approaches to support more accurate forecasting of distributed generation and its role in future power system planning.

This report compiles information about load forecasting practices, focusing on forecast development that relates to electric resource and integrated system planning. A sample of documents focused on integrated resource plans, load forecast methodology, or supporting documents from electric companies and planning agencies was analyzed. Load forecasting methods, processes, data, and assumptions are investigated. The research also conducted a broad, high-level comparison of industry practices with EPRI’s internal long-term load modeling tools. Connections to resource planning needs and directions for future research are identified.

This technical brief raises awareness about the need for meaningful corporate climate risk metrics and the misleading use of non-risk metrics as proxies, such as greenhouse gas (GHG) emissions, GHG targets, weather events, and asset locations. Currently, there is an absence of agreed-upon climate risk and risk management metrics. This brief facilitates and advances the metric development process by outlining a conceptual framework for climate transition risk and non-risk metrics. It also offers a proposal for developing categories of climate risk metrics designed to inform different utility priorities. The brief focuses on utilities, but the conceptual proposal can be applied to other sectors. This topic is relevant to corporate climate risk disclosure rule development and compliance, climate reporting, and stakeholder engagement.

This study evaluates the latest vintage of global greenhouse gas (GHG) emissions pathways from the Intergovernmental Panel on Climate Change (IPCC), the International Energy Agency, the Transition Pathway Initiative (TPI), Principles for Responsible Investing (PRI), and the Network for Greening the Financial System (NGFS). These pathways are key inputs to global climate policy, methodologies evaluating corporate climate strategies, and planning for future climate change. It is essential to understand the pathways and how to appropriately interpret and apply them in corporate climate target setting and risk assessment and management decisions and discussions.

This study derives key insights regarding the following:

• Proper use of global emissions pathway data,
• Uncertainty in emissions transitions consistent with a global temperature,
• Potential economic activity transitions and uncertainty underlying emissions transitions,
• The attainability of ambitious global emissions pathways,
• Robust low-emissions transition insights, and
• The robustness of EPRI’s previous technical observations and company insights and guidance—technical principles and limitations of global pathways.

Regarding the latter, in addition to informing current climate change conversations, this study tests the robustness of prior insights and guidance derived from evaluating previous vintages of global emissions pathways.

This study examines the timing and scale of a hydrogen energy industry buildout – modeled to support an economy-wide net-zero pathway – and evaluates whether the U.S. construction sector has sufficient skilled craft labor to deliver that buildout in the presence of competing industrial and infrastructure construction.

The skilled craft workforce has faced a widely reported decline in both numbers and skill levels, affecting projects in planning and execution. While some of this is a lingering, structural issue, much of it is cyclical, tied to large swings in economic activity. These cycles force workers out of the industry, often into other fields, where their under-utilized craft skills deteriorate – sometimes permanently. The report focuses on 19 specific skilled craft worker disciplines essential to hydrogen and other construction projects, assessing current capacity and long-term gaps.

Over the next decade, a surge in public infrastructure, industrial, and hydrogen-related projects – some driven by federal legislation – could keep demand for construction labor high. This could create delays in starting and completing projects, even as it sustains well-paying jobs. Hydrogen-related labor needs are expected to persist through 2050, though near-term demand is likely to be dominated by other large federally supported projects to rebuild infrastructure, reshore manufacturing, and expand renewable energy. Labor demand estimates for hydrogen projects are based on project schedules, while broader construction needs from 2030 to 2050 reflect econometric projections for other sectors.

While the federal Occupational Employment and Wage Surveys show only modest wage increases tied to labor demand, this likely underreports real market changes due to infrequent data collection and industry fragmentation. In practice, owners and skilled craft workers respond quickly to changing conditions, adjusting schedules, negotiating higher wages, and reallocating labor to meet urgent needs.

The study finds that even before hydrogen-related projects ramp up, the U.S. construction workforce lacks sufficient craft labor supply to meet overall project demand. This shortfall poses a systemic challenge affecting all construction sectors, including hydrogen. Greater cooperation between owners and contractors will be critical for training, reskilling, and retaining skilled craft workers – particularly to replace aging workers and prepare new entrants for technically demanding roles.

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).

Gridded reanalysis products are widely used in energy system planning and operations to characterize long-term weather and extreme events. This study evaluates how three widely-used reanalysis products (ERA5, ERA5-Land, and MERRA2) capture the magnitude, timing, and shape of daily temperature cycles across the contiguous United States compared to in-situ station observations from 2000–2022. Results show that while bias correction can reduce some of the bias in gridded temperatures, discrepancies in the timing and shape of daily temperature extrema often remain. For example, ERA5, exhibits a 1–2 hour lag in the occurrence of daily extrema, most pronounced in winter and for western mountainous regions. While ERA5 generally shows the closest agreement with station observations in capturing the shape of hourly temperature around extrema, ERA5-Land and MERRA2 match observations more closely at many locations. These timing and shape discrepancies have direct implications for load forecasting, peak demand estimation, and grid flexibility requirements. We recommend that energy system practitioners carefully validate reanalysis datasets using metrics specific to their applications and regions before integration into planning and operational models.

This visual synopsis summarizes the key insights from the full report Outlooks to Foundations: Construction Craft Labor Risks and Workforce Solutions for the Energy Transition – A Hydrogen Case Study (3002034766). The report assesses the U.S. construction industry’s ability to meet skilled craft labor demand through 2050 for hydrogen and large industrial and infrastructure (I&I) projects, while characterizing associated wage impacts and labor supply elasticities.

• Peak Demand Timing
• Structural Labor Shortages
• Tight Markets, Uneven Impacts
• Limited Wage Responsiveness
• Opportunities for Action

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.

To access Powering Intelligence 2026: Updated Scenarios of U.S. Data Center Electricity Use and Power Strategies (Website), click here: https://powering-intelligence.epri.com

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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.

Recent extreme temperature events have challenged the energy grid, prompting new regulatory standards for grid resilience. However, the complex, non-linear relationship between weather and grid performance is often obscured by critical data gaps, thus planning for higher-intensity events without addressing these shortcomings can create a false sense of security. This technical brief summarizes a survey of the EPRI Global Change, Climate Risk, and Target Setting research advisors, which identifies a pressing practitioner need for technical guidance. It further details current data limitations, discusses several key implications of recent North American Electric Reliability Corporation (NERC) standards, and proposes robust extreme temperature event definitions to strengthen system planning.

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.