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The document criticizes the World Bank and IFC for fostering Pakistan's dependence on expensive fossil gas and imported LNG, urging a shift toward indigenous renewable energy sources and transparent consultation with civil society.

The document challenges the notion that wind curtailment results from an oversupply of wind, using analysis of the Southwest Power Pool (SPP) to show that higher-cost coal plants often remain online while wind is curtailed. It identifies three primary drivers of this waste: inadequate transmission capacity, the practice of coal plants 'self-committing' to avoid being turned off, and a lack of battery storage. The author argues that addressing these infrastructure and operational shortcomings would reduce costs for consumers and lower carbon emissions.

The document provides a comprehensive Q&A on battery energy storage, distinguishing between behind-the-meter and front-of-the-meter systems. It highlights how storage enhances grid flexibility, supports renewable energy integration, and improves community resilience during extreme weather. While noting the environmental and health benefits of displacing fossil fuel plants, it addresses safety risks like thermal runaway and the ethical concerns surrounding the mining of lithium and cobalt. It emphasizes the need for inclusive stakeholder engagement and strong policy design to ensure equitable deployment and sustainable supply chains.

In the first half of 2020, renewable electricity generation in the EU-27 reached 40%, surpassing fossil fuel generation at 34%. This shift was driven by record wind and solar penetration and a 7% drop in electricity demand caused by COVID-19. Coal generation fell by 32%, contributing to a 23% reduction in power sector CO2 emissions. While grids remained stable, the increase in renewables led to more frequent negative wholesale electricity prices, indicating a need for greater system flexibility. Poland emerged as the most coal-dependent EU country, generating as much coal-fired electricity as the other 25 EU members combined.

The policy brief argues that the U.S. can achieve 90 percent zero-carbon electricity by 2035 through a federal clean energy standard and complementary reforms in tax credits, manufacturing, transmission planning, and wholesale market design. This transition would require significant scaling of solar, wind, and battery storage, while retiring the coal fleet and utilizing existing gas plants only for flexibility. The authors emphasize the need for a 'just transition' for coal-dependent communities and the modernization of utility regulation through performance-based models and all-source procurement to ensure the transition is affordable and equitable.

The report examines performance incentive mechanisms (PIMs) designed to motivate US utilities to implement strategic demand reduction (SDR)—a combination of energy efficiency and demand response that optimizes the electricity system. Analyzing seven state case studies, the authors find that while PIMs are effective, the potential for cost-effective load flexibility remains largely untapped. Most current PIMs focus on 'shape' (long-term demand adaptation) and 'shed' (peak demand reduction) services, with limited focus on 'shift' (moving demand between times of day) or 'shimmy' (real-time grid balancing). The report argues that durable, long-term incentives with periodic updates, supported by complementary policies like decoupling and time-varying rates, are most effective at aligning utility business models with public interest and decarbonization goals.

The report proposes a policy framework to reach U.S. net zero emissions by 2050, projecting an annual abatement of over 6 Gt of emissions and 120,000 lives saved from reduced pollution. It details sector-specific strategies: industrial decarbonization through electrification and hydrogen; transportation via electric and hydrogen vehicle mandates; a 100 percent carbon-free electricity standard by 2050; and an all-electric building sales mandate by 2035.

India can integrate 390GW of wind and solar generation by 2030 at a lower total system cost than its current trajectory by increasing the flexibility of electricity supply and demand. The report identifies four primary flexibility needs: operating reserves, ramping, daily balancing, and seasonal balancing, all of which will grow as renewable energy penetration increases. A 'balanced portfolio' combining demand-side management, energy storage, and powerplant flexibility is found to be the most cost-effective approach, reducing energy waste by 82% to 97%, total system costs by 5% to 8%, and carbon emissions by 8% to 12% compared to a thermal-only approach. Regional analysis reveals that states like Tamil Nadu and Karnataka will face acute seasonal and ramping challenges, while Uttar Pradesh could act as a flexibility exporter due to its industrial base. The report concludes that urgent action on data, market design, and infrastructure is required to unlock these flexibility resources.

India faces twin challenges as it scales renewable energy: the need for increased grid flexibility and the risk of coal-based plants becoming economically unviable due to falling plant load factors (PLFs). The report argues that transitioning existing coal plants into flexible resources is a cost-effective short-term solution. This conversion requires technical retrofits to allow for lower minimum loads, reduced start-up times, and increased ramp rates. While this path involves incremental costs of 5-10% of total project costs in NPV terms, it is significantly cheaper than deploying lithium-ion batteries or pumped hydro. The report recommends market-based mechanisms, such as capacity auctions and revised power purchase agreements, to compensate plant owners and ensure a transition toward a low-carbon electricity system.

The briefing examines how commercial electricity rate designs, specifically noncoincident demand charges, incentivize customers to flatten their load profiles using battery storage. While this reduces individual bills, it often conflicts with the needs of grids with high renewable penetration, where flexible demand is required to match variable generation. The author suggests transitioning to peak-coincident demand charges, time-of-use rates, or real-time pricing to better align customer behavior with system-wide costs and grid stability.

The document examines the challenges RTOs face as the U.S. grid shifts from large central generators to variable renewables and distributed energy resources (DERs). It argues that 'flexibility'—the ability to respond to changes in supply and demand across various timeframes—is essential for reliability and cost minimization. The authors recommend eliminating self-scheduling for all generators and imports, preserving negative pricing, and improving the coordination between natural gas and electricity markets. It also suggests creating technology-neutral products that value specific capabilities, such as ramping and frequency response, and highlights successful examples like MISO's Dispatchable Intermittent Resource category and CAISO's Flexi-Ramp product.

The report examines the potential for electric vehicles to act as flexible loads to balance electricity supply and demand, particularly to mitigate the 'duck curve' caused by high solar penetration. It analyzes technical barriers, utility roles, and rate designs, concluding that managed charging can reduce system costs and emissions if aligned with clean energy availability.

The report argues that electricity systems can transition to near-total renewable energy at a cost competitive with gas-based systems, provided a portfolio of flexibility resources is deployed. It identifies six types of flexibility needs—ranging from instantaneous reserves to seasonal balancing—and evaluates technologies such as batteries, demand-side management, and hydroelectric power. Regional analysis shows that while most areas are well-positioned for the next decade, long-term needs for intraday and interday balancing will require significant investment and market redesign to avoid costly lock-in of fossil fuel assets.

The document advocates for a more coherent institutional framework within the EU to ensure that energy market design supports the 2030 and 2050 climate goals. It identifies a disconnect between the IEM's focus on free movement of gas and electricity and standalone climate legislation. Key recommendations include creating an independent regional institution (IRSO) for least-cost system balance, strengthening the independence and mandate of National Regulatory Authorities (NRAs), and expanding the oversight roles of ACER and ENTSO-E to explicitly incorporate flexibility and demand-side measures.

The document argues that as variable clean energy sources become a larger part of the electricity mix, grid operators must transition from simply dispatching supply to meet uncontrollable demand toward a flexible system that dynamically matches supply and demand. It identifies a hierarchy of flexibility resources, noting that improved operations (such as sub-hourly dispatch and better weather forecasting) are the lowest-cost options, followed by demand response, grid infrastructure upgrades, flexible generation (e.g., fast-ramping gas plants), and energy storage.

The report identifies the California water sector as a major electricity consumer, accounting for nearly 20 percent of the state's demand. It argues that while growing needs for groundwater pumping, desalination, and water recycling increase energy intensity, utilities can mitigate this by investing in on-site renewables, power purchase agreements, and demand response services. Key barriers include a lack of standardized electricity source data, regulatory misalignment, and financial constraints like Proposition 218.

The report introduces the electricity system value chain, a non-linear framework designed to map the flow of energy, information, and money across the grid. It breaks the system into three fundamental layers—organizational, electrical, and communications—and defines essential functions (input, process, output) within each. By applying this framework, stakeholders can identify the specific technical and regulatory connections required to realize and monetize system values, such as frequency regulation or renewable energy integration. The document provides step-by-step examples of applying the framework to solar PV and battery systems in both behind-the-meter and distribution-scale environments.

The report examines the transition of the U.S. power sector from coal to natural gas, highlighting that while this shift provides immediate reductions in some pollutants, it creates long-term risks including price volatility, methane leakage, and stranded assets. Through modeling three scenarios—Business as Usual, a Carbon Standard, and a Carbon Standard plus Renewables and Efficiency Policies—the authors find that a diversified energy mix is the most economically and environmentally sound approach. The 'Carbon Standard plus Renewables and Efficiency Policies' scenario is projected to reduce power plant carbon emissions by 70% below 2005 levels by 2040 and generate net societal benefits of nearly $170 billion by that year. The report recommends strengthening the EPA's Clean Power Plan, implementing federal renewable electricity and energy efficiency standards, and increasing regulations on fugitive methane emissions.

The document outlines various energy storage technologies—including pumped hydro, batteries, thermal, compressed air, flywheels, and hydrogen—detailing how they balance electricity supply and demand. It highlights the transition from a reliance on pumped hydroelectric storage toward rapidly scaling lithium-ion batteries, noting a 72 percent drop in battery capital costs between 2015 and 2019. The guide argues that energy storage enhances grid reliability, enables higher renewable energy integration, and provides community benefits by replacing polluting fossil fuel 'peaker' plants and increasing resilience against extreme weather.

The report argues that traditional bundled, volumetric block rates are obsolete for a grid with increasing distributed energy resources (DERs) because they fail to reflect the temporal and locational value of electricity. It proposes evolving rate design along three continuums: attribute unbundling (separating energy and capacity), temporal granularity (moving toward real-time pricing), and locational granularity (addressing distribution 'hot spots'). The authors suggest a transition strategy using a combination of evolving default rates and opt-in alternatives, supported by third-party technologies to maintain a simple customer experience. Recommendations for regulators include increasing data transparency, enhancing valuation methodologies for DER attributes, and establishing clear timelines for rate transitions.