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The document identifies that while the U.S. needs a three- to four-fold increase in transmission capacity over 30 years, deployment is hindered by federal leadership gaps, insufficient agency staffing, and uncoordinated requirements across federal, state, and Tribal jurisdictions. Quantitative analysis of 33 completed transmission lines shows an average EIS review length of 4.3 years. The author recommends consolidating siting authority under FERC for projects in the national interest, expanding the use of programmatic environmental impact statements, and utilizing the Permitting Dashboard for greater transparency.

The document outlines how Texas municipalities and counties can catalyze the adoption of distributed energy resources (DERs) and virtual power plants (VPPs) to address rising electricity demand and grid instability. It details the types of DERs—generation, storage, and demand-side—and explains how VPPs (referred to in Texas as aggregate distributed energy resources or ADERs) coordinate these assets for grid-level benefits. The briefing identifies drivers for adoption, including the Inflation Reduction Act and extreme weather events like Winter Storm Uri and Hurricane Beryl, and provides a framework for local governments to increase adoption through public education, zoning updates, streamlined permitting, and the enrollment of government-owned assets into VPPs.

Thermal batteries store renewable electricity as high-temperature heat in abundant materials like graphite or bricks, providing a cost-effective alternative to fossil fuels for industrial processes requiring temperatures over 1,000°C. The technology supports grid stability by reducing renewable curtailment and offers a lower-risk alternative to hydrogen for industrial decarbonization. While facing challenges in wholesale electricity market access and infrastructure integration, the sector saw investment spike to over $350 million in 2024.

The briefing examines the components of grid reliability—resource adequacy, operational reliability, and resilience—within the context of the U.S. transition to clean energy. It argues that while load growth and fossil fuel retirements create short-term risks, a diverse portfolio of wind, solar, batteries, and demand-side resources can maintain reliability. The document emphasizes the need for interconnection reform, updated market rules for inverter-based resources, and the scaling of demand-response programs to avoid unnecessary supply-side costs.

The report examines the technical and institutional challenges of maintaining grid reliability in the United States as fossil fuel plants retire and demand grows from data centers and electrification. It argues that reliability does not require traditional baseload power but can be achieved through a combination of wind, solar, battery storage, and demand-side flexibility. The authors highlight that while 80-90% clean electricity is achievable with current technology, reaching 100% may require 'clean firm' resources like enhanced geothermal or advanced nuclear. Key recommendations include reforming interconnection queues, expanding interregional transmission, and implementing performance-based incentives for utilities to prioritize demand-side solutions.

The United States has the world's second-largest pipeline of gas-fired power plants in development, totaling over 85 GW, largely fueled by speculation regarding AI energy needs. However, most of these projects are in early stages, and there is a significant risk that they could become stranded assets if AI power demand does not materialize. The report highlights that renewables and storage are currently cheaper and faster to deploy than new gas power, while specific regions like Texas and the PJM Interconnection area are seeing the highest concentration of these developments.

The author contends that customer-driven demand-side management—such as smart thermostats, heat pumps, and optimized EV charging—can serve as a 'virtual power plant' to maintain grid stability. The text highlights a successful Ontario program that created a 90-megawatt virtual power plant and calls for federal and provincial policy shifts to prioritize energy efficiency investments over fossil fuel infrastructure.

Thermal batteries can abate up to 99% of heat emissions in US chemical and refining plants by storing renewable electricity as heat in materials like graphite or bricks. These systems can provide heat up to 1800°C for reactions and distillation, with a levelized cost of heat between $20 and $87 per MWh. Integration involves assessing heating needs, retrofitting steam systems, and implementing automated charging based on electricity prices. While heat pumps are suitable for processes up to 200°C, thermal batteries address higher temperature needs. The guide advocates for policy reforms, including wholesale electricity rate access and permitting reform for non-adjacent parcels, to enhance the viability of industrial electrification.

The document contends that the U.S. power grid is already transitioning away from coal toward renewables, storage, and flexible natural gas due to market forces, and that the EPA's Rule aligns with these trends. It argues that modern resources like battery storage and flexible gas plants provide better operational reliability than aging coal plants. The brief asserts that the Rule provides sufficient time for resource procurement and includes flexibility mechanisms to protect the grid during periods of stress.

The briefing examines how battery energy storage systems (BESS) can replace fossil fuel generation to ensure grid reliability. It details three primary functions of batteries: balancing variable renewable energy supply and demand, providing stability services like frequency and voltage regulation, and enabling 'black start' capabilities to restore power after blackouts. The author contends that batteries often offer lower costs and faster response times than thermal plants. To maximize these benefits, the document recommends that utilities conduct analytical studies to identify specific reliability needs and utilize all-source procurement processes to ensure the most cost-competitive resources are selected.

The document highlights the risk of insufficient electricity generation during summer heat waves in North America, driven by projected peak load growth of 38 GW through 2028. It proposes Virtual Power Plants (VPPs)—aggregations of distributed energy resources (DERs)—as a key tool to enhance grid reliability and community resilience. VPPs are presented as more affordable than gas peakers or batteries and can be deployed in 6-12 months. The briefing outlines three essential policy principles: expanding the DER asset base, ensuring fair compensation, and enabling value stacking. Case studies from the US and Canada demonstrate VPPs' ability to provide peak capacity, reduce infrastructure costs, and offer backup power during extreme weather.

The document advocates for the adoption of virtual power plants (VPPs) to address electricity grid reliability and affordability during summer peaks. It highlights that VPPs can leverage existing assets to manage investment costs and enhance community resilience against extreme weather, providing guidance for regulators to replicate successful VPP implementations from other jurisdictions.

The Virtual Power Plant Flipbook provides a resource for utilities to implement VPPs—aggregations of distributed energy resources like batteries and electric vehicles—to enhance grid reliability and decarbonization. It offers case studies on various technologies, compensation frameworks, and partnership models to serve as a starting point for program managers and grid operators.

The document argues that the U.S. coal fleet is already in a sustained economic decline, making the EPA's emissions rules a catalyst for prudent utility planning rather than a source of economic or reliability risk. It asserts that the 2032 compliance timeline is sufficient for utilities to procure replacement resources, citing hundreds of gigawatts of 'shovel-ready' projects in interconnection queues. The authors maintain that 'baseload' coal is no longer necessary for grid stability, as portfolios of wind, solar, battery storage, and low-utilization gas can meet peak loads and growing demand without compromising reliability.

The document outlines a consensus framework for defining and measuring the impact of corporate voluntary actions on grid decarbonization, emphasizing that true impact is the difference in total emissions between a scenario where an action is taken and one where it is not. It highlights that total impact must account for both short-run power plant operations and long-run supply changes, while acknowledging that empirical verification of structural change remains difficult, leading to inherent uncertainty in impact estimates.

The United States is experiencing a surge in data center power demand, projected to reach 35 GW by 2030, which risks driving utilities toward increased natural gas generation. RMI proposes that data center operators can instead support grid reliability and decarbonization by maximizing energy efficiency (e.g., AI-driven cooling), enhancing demand flexibility to shift workloads, deploying Grid-enhancing technologies (GETs), and negotiating green tariffs for renewables and storage. The document emphasizes that these actions can set a precedent for other upcoming large loads, such as electric vehicles and industrial onshoring, while urging regulators to ensure equitable cost allocation and transparent planning.

The document examines the integration of clean electrolytic hydrogen into the U.S. electric system, emphasizing its potential as long-duration energy storage for 'last mile' decarbonization. It analyzes how the design of the Section 45V tax credit—specifically the 'three pillars' of incrementality, temporal matching, and deliverability—will determine whether hydrogen production increases net greenhouse gas emissions or supports grid reliability. The authors warn that without these pillars, electrolysis could drive significant load growth (up to 32% by 2032) and potentially increase emissions. The brief also highlights risks related to NOx emissions, water consumption, and public safety, urging developers to engage early with host communities to ensure an equitable transition.

The report analyzes transmission development between 2010 and 2020, finding that while projects requiring an Environmental Impact Statement (EIS) represent only 3.5% of new lines, they account for 26% of new line miles. These projects are typically longer, more likely to be driven by renewable generation interconnection, and more likely to cross state or international borders. The average EIS review timeline is 4.3 years, with a moderate correlation between line length and review duration. The authors argue that these long and unpredictable timelines pose a challenge to future grid reliability and decarbonization goals, especially as federal funding and authority increase the likelihood of projects triggering federal reviews.

The document outlines the role of virtual power plants (VPPs) in aggregating distributed energy resources (DERs) to provide utility-grade services and argues that strong policy and regulation are essential to scale these benefits over the next one to four years.

The report examines how grid-enhancing technologies (GETs) can address interconnection bottlenecks in the PJM region, potentially enabling 6.6 GW of new solar, wind, and storage projects by 2027 and providing approximately $1 billion in annual production cost savings.