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The report identifies a 'planning gap' in deregulated U.S. power markets where short-term wholesale price signals and Clean Electricity Standards (CES) fail to incentivize long-lead time, capital-intensive technologies like nuclear, geothermal, and long-duration energy storage. To address this, the authors propose a 'hybrid market' approach called state-led planning, which consists of three core components: system needs assessments, technology development roadmaps, and state-led procurement. This framework allows states to provide the long-term revenue certainty required by investors while maintaining the operational efficiencies of competitive wholesale markets. The report highlights Illinois's Clean and Reliable Grid Affordability Act as a primary example of this approach in practice and discusses the role of FERC Order 1920 in improving regional transmission planning.

FERC has ordered six regional grid operators (PJM, MISO, SPP, CAISO, ISO-NE, and NYISO) to update their tariffs to address challenges posed by rising load growth from large energy users, such as data centers. The orders focus on five reform categories: standardizing interconnection applications and study processes, preventing cost shifting through increased transparency and cost recovery agreements, establishing rules for co-location and behind-the-meter generation, creating new transmission service types for flexible loads, and developing study processes for electrically proximate generation. The document outlines a strict timeline for RTO/ISO responses and filings, starting in July 2026.

The policy brief examines how virtual power plants (VPPs) can mitigate grid interconnection delays for large loads, specifically data centers, in the United States. It highlights that VPPs can scale to meet over 20% of US peak demand by 2030 and are significantly cheaper than new gas plants. The document proposes three commercial models—pass-through funding, capacity transfer, and reliability reinforcement—to align incentives between large loads, utilities, and VPP aggregators. It also recommends reforms in interconnection policy, integrated planning, and customer protection to enable this transition.

In 2025 Q3, US utility resource plans showed increasing projected electricity demand and emissions, with many utilities delaying fossil plant retirements to ensure resource adequacy. Load growth is primarily driven by large loads like data centers, while the phase-out of federal renewable tax credits and MISO regulatory changes have led to reduced wind and solar plans and increased reliance on gas capacity. Current IRP projections indicate a significant gap between planned emissions reductions and the net-zero targets required by 2035 for climate alignment.

The report examines how battery energy storage can enhance grid reliability—specifically resource adequacy, stability, and resilience—while reducing costs. It contrasts the successful deployment of batteries in Texas (ERCOT) and California (CAISO), where well-defined ancillary services and value stacking have lowered costs, with the PJM region, where high uplift costs and interconnection hurdles persist. The author recommends that regulators and planners define competitive ancillary service products, properly value resource adequacy, and modernize interconnection processes to replace expensive legacy fossil fuel generators.

The briefing identifies regulatory uncertainty, slow permitting, and the lack of a cohesive strategy as primary barriers to geothermal energy in California. It proposes establishing a statewide strategic plan, streamlining environmental reviews, updating decades-old well regulations to accommodate next-generation technologies, reforming interconnection and resource adequacy frameworks to reflect year-round value, and increasing funding for high-upfront pre-development costs.

The US power sector is experiencing unprecedented load growth, requiring the grid to expand more than five times faster than in the previous two decades. To address this, the report recommends maximizing existing grid value through grid-enhancing technologies (GETs) and demand-side flexibility, accelerating connections via 'energy parks' and streamlined interconnection processes, and adopting proactive, scenario-based planning. It also suggests targeted affordability measures for low-income customers and specialized rate designs for large loads to prevent cost-shifting and stranded-asset risks.

California possesses vast untapped geothermal potential, particularly in superhot rock resources, which could significantly support the state's clean energy goals. However, the industry faces substantial barriers, including a lack of long-term strategic planning, complex and lengthy permitting processes, outdated regulations, and interconnection uncertainties. The report recommends the creation of a statewide strategic plan, streamlining environmental reviews, updating well regulations, and establishing a clean energy infrastructure financing fund to attract private capital and accelerate deployment.

The report critiques the reliance on Levelized Cost of Electricity (LCOE) for power system planning, noting that while useful for tracking historical technology costs, it fails to account for system-wide needs, generation profiles, and integration costs. It highlights that clean firm technologies can reduce overall system costs despite higher LCOEs. The authors recommend moving toward comprehensive system-level analyses that model temporal and spatial constraints to optimize decarbonization pathways.

Ember's response to the ERAA 2025 consultation highlights significant discrepancies between ENTSO-E's proposed commodity prices and market futures, noting that fossil fuel prices are underestimated while CO2 prices are overestimated. The document argues that the ERAA underestimates battery storage and demand flexibility potential, fails to account for battery CAPEX reductions, and underestimates wind and solar capacities in several European countries compared to National Energy and Climate Plans (NECPs) and industry forecasts.

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 report addresses the surge in US electricity demand, noting that utility integrated resource plans covering 48% of sales expect load to grow 20% from 2023 to 2035. It argues that traditional forecasting is inadequate for new large loads—specifically data centers and industrial reshoring—which possess unique load shapes, high uncertainty, and 'flight risk'. The authors recommend that regulators shift toward scenario-based forecasting, increase the frequency of updates (e.g., quarterly), and implement 'least-regrets' capital investments and risk-shifting tariffs to protect ratepayers from the costs of forecast errors.

The document outlines a framework for evaluating the economic impact of transmission infrastructure, focusing on three primary benefit categories: congestion relief, resource adequacy, and public policy savings. It describes the specific calculations used for these benefits, the financial models applied to different ownership structures (investor-owned, public power, and merchant developers), and compares the results against original project projections for three specific case studies. The authors acknowledge several conservatisms in their approach, including the exclusion of certain benefit categories and the use of isolated line capacity estimates rather than complex power flow simulations.

The report identifies four primary drivers of resource adequacy risk in the Western United States: load growth uncertainties, extreme weather and climate change, delays in planned resource builds, and slow transmission expansion. To mitigate these risks, it proposes ten specific options for regulators categorized into three strategies: improving planning practices, widening the suite of resource adequacy solutions, and reforming utility business models.

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.

India's power grid is facing increased strain from record-breaking heatwaves and power demand, as seen in May 2024 when nationwide demand hit 250 GW. While battery energy storage systems (BESS) costs in India have dropped 65 percent over the last two years, investment is hindered by market rules that only recognize 'energy only' dispatch strategies. The document asserts that if regulators recognize a 'full value stack'—including resource adequacy, ancillary services, and transmission and distribution (T+D) deferral—BESS profit margins could range from 24 to 70 percent. To unlock this market, the document recommends that the Forum of Regulators provide valuation guidance, state regulators incorporate BESS into long-term resource adequacy planning, and the Central Electricity Authority (CERC) increase transparency and access to ancillary service markets.

The document introduces resource adequacy (RA) as a planning concept to minimize blackouts while balancing costs, specifically focusing on India's new Resource Adequacy Planning Framework released in June 2023. It details the metrics used for reliability, such as loss of load probability (LOLP) and normalized energy not served (NENS), and outlines the roles of the Central Electricity Authority (CEA), National Load Dispatch Center (NLDC), and distribution utilities (Discoms) in executing national and state-level plans. The guide emphasizes that adopting integrated resource planning (IRP) best practices and advanced planning tools will help Discoms manage peak demand and integrate renewable energy more effectively.

The document examines the vulnerability of the US gas-fired power plant fleet to extreme winter and summer weather, noting that gas plants are the primary source of generation failures during major storms. It argues that current resource adequacy metrics overvalue gas reliability and recommends transitioning to probabilistic modeling, increasing transparency, and prioritizing renewables, storage, and demand-side solutions to ensure a resilient power grid.

The document analyzes the current state of electricity markets in India, noting that while power exchanges (PX) are growing, they only account for 7% of total demand. It identifies key barriers to market adoption, including the dominance of inflexible long-term power purchase agreements (PPAs), unpredictable market clearing prices, and inaccurate supply-demand forecasting. The paper highlights that states like Gujarat and Tamil Nadu could achieve significant fuel cost savings by shifting from PPAs to day-ahead markets (DAMs). It recommends redesigning PPA structures, introducing contracts for differences (CFDs), strengthening institutional market monitoring, and developing state-level resource adequacy frameworks to better integrate variable renewable energy.