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The report argues that the electric vehicle revolution is inevitable due to falling battery costs and increasing consumer demand, making the urgent deployment of charging infrastructure a priority for U.S. utilities and regulators. It identifies high capital costs and unfavorable utility tariffs—specifically high demand charges—as primary barriers to the profitability of DC fast charging (DCFC). The authors advocate for a mix of Level 2 chargers for residential and workplace needs and DCFC for high-traffic corridors, supported by time-of-use (TOU) tariffs to optimize grid integration. Through case studies of California, Colorado, Hawaii, Ohio, and Texas, the report demonstrates how different regulatory environments and grid compositions influence the cost of charging and the potential for EVs to absorb excess renewable energy.

The document analyzes the proposed EU DSO entity, identifying risks such as conflicts of interest in drafting Network Codes (NCs) and potential discrimination against smaller market players. It evaluates four options: scrapping the proposal, creating an independent Consultation Forum, embedding strong regulatory safeguards, or limiting the EU DSO's mandate while transferring rule-setting tasks to ACER. The author concludes that a combination of strong safeguards and a limited consultative mandate is the most desirable approach to ensure non-discrimination and alignment with EU climate and energy goals.

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.

Amory B. Lovins of RMI argues that subsidies for distressed nuclear plants are unjustified because closing high-cost nuclear units and reinvesting their operating expenses into energy efficiency can reduce more carbon than maintaining the plants. He contends that 'baseload' power is not a grid requirement and that variable renewables are more resilient and cost-effective than central thermal plants.

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 report addresses the conflict between the Northeastern U.S.'s aggressive renewable energy targets and its limited available land. It argues that meeting these goals requires a combination of innovative siting on low-conflict lands (such as brownfields and prison lands), the acceleration of offshore wind, the use of distributed energy resources, and the import of Canadian hydroelectricity. The authors emphasize that overcoming local opposition through early community engagement and 'Smart from the Start' principles is critical to avoiding project delays and failures.

The report examines 'M&V 2.0', which combines automated analytics with high-granularity data (such as hourly interval data) to provide near-real-time energy savings estimates. While traditional M&V often relies on delayed reporting and manual analysis, M&V 2.0 offers the potential for faster feedback to program administrators, utilities, and facility owners. However, the authors note significant limitations, including a current focus on existing-conditions baselines rather than standard-practice code baselines, and the difficulty of isolating individual measure-level savings from whole-building meter data. The document outlines the current landscape of proprietary tools, primarily focused on the commercial sector, and discusses ongoing standardization efforts such as the Uniform Methods Project and CalTRACK. To realize the full promise of M&V 2.0, the report recommends conducting more public pilots, establishing collective acceptance criteria for accuracy, and improving automated data access and interoperability.

The document outlines a structured approach to grid modernization, emphasizing integrated distribution planning and the use of outcome-oriented metrics for affordability, resilience, and environmental performance. It suggests tying utility revenue to these performance targets through conditional rates of return or budget caps with shared savings to align utility incentives with public benefits.

The document examines the proposed EU DSO entity, a membership-based body intended to enhance cooperation between DSOs and transmission system operators (TSOs) and coordinate the development of Network Codes. While acknowledging potential benefits for integrating renewables and smart grids, the author warns that the lack of formal independence requirements and regulatory oversight could allow large DSOs to lobby for their own interests, create barriers to competition for renewables and demand response, and marginalize smaller, community-owned DSOs. The briefing recommends that ACER, rather than the DSO entity, should lead the drafting of Network Codes and that the entity be subject to explicit independence and representation criteria.

The document argues that the Energy Market Design Initiative is essential for the success of the Energy Union and the implementation of the Paris Agreement. It outlines how market design can reduce energy poverty, boost security, and avoid fossil fuel lock-in by facilitating clean technology deployment. The authors call for specific actions, including the phase-out of coal by 2030, the promotion of energy efficiency and demand response, and the regulation of distribution system operators to support a decentralised energy system.

The report identifies a set of 21 cost-effective and technically feasible policies that can enable Mexico to meet its 2030 climate goals. It proposes two scenarios: an unconditional package to reduce GHG emissions by 22% below the baseline and a conditional package for a 36% reduction. The analysis indicates that Mexico can achieve these targets while realizing significant net financial savings and public health benefits through reduced particulate matter pollution. The proposed eight-point action plan prioritizes industrial efficiency, methane capture, and carbon pricing as the most impactful interventions.

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 report argues that the rapid growth of electric vehicles (EVs) requires a shift in regulatory paradigms to ensure that new loads benefit rather than impair the electricity grid. It emphasizes the role of state utility regulators in designing smart charging policies, rate structures, and infrastructure ownership models. Through case studies of California and Washington, the document illustrates different approaches to EV deployment and integration, highlighting the need for adaptive regulation, such as scalable pilots and scenario-based distribution planning, to manage the unpredictable nature of EV adoption.

The briefing examines the economic potential of demand flexibility, highlighting how smart household devices and aggregated commercial and industrial loads can lower system-wide peak demand and grid costs. It emphasizes that while individual residential devices offer some savings, the full value of flexibility is realized through aggregation and participation in wholesale and ancillary service markets via distributed energy resource management platforms.

The Rocky Mountain Institute presents a business model for net zero energy (NZE) districts that achieves life-cycle cost neutrality compared to business-as-usual (BAU) developments. The model centers on an Integrated Energy Services Provider (IESP) that manages a micro-utility, district heating and cooling, and renewable energy deployment. By shifting capital costs for heating/cooling and solar PV away from parcel developers and providing on-bill financing for energy efficiency, the model reduces upfront costs for developers and lowers total energy bills for tenants. The approach includes outcome-based energy-performance requirements enforced through a system of incentives and penalties. A case study of a 180-acre mixed-use development in a midsize U.S. city demonstrates that the model remains economically favorable even under challenging conditions such as low electricity rates and a lack of net metering.

The report analyzes various policy scenarios for China's energy transition, highlighting that carbon pricing and renewable energy standards are the most powerful tools for reducing emissions. It emphasizes that regulatory policies, particularly energy efficiency standards in buildings and industry, are highly cost-effective. The analysis suggests a transition toward a service-based economy and a decarbonized electricity grid to meet emissions peaking goals by 2030.

The document addresses four perceived barriers to the clean energy transition: the 'duck curve' ramping problem, the necessity of curtailing excess generation, the high cost of renewables, and the role of natural gas in emissions reductions. It argues that demand response and battery storage can manage variability, regional electricity trading can prevent waste, and energy efficiency combined with falling technology costs keeps customer bills low. Finally, it asserts that renewable energy and energy efficiency have contributed more to U.S. carbon emission declines since 2007 than the shift to natural gas.

The report argues that electric vehicles (EVs) represent a significant demand-side opportunity for the electricity grid. By treating EV charging as a distributed energy resource (DER), utilities can use smart charging—even without vehicle-to-grid (V2G) capabilities—to avoid infrastructure investment, integrate more variable renewables, and reduce system costs. The authors emphasize that charging behavior is most effectively influenced in the first few months of ownership, necessitating early action on rate design and infrastructure planning. Through modeling in five U.S. states and analysis of California pilots, the report demonstrates that optimized charging can substantially flatten load profiles and prevent peak demand increases. It outlines various roles for utilities (facilitator, manager, provider) and recommends the use of time-of-use (TOU) and dynamic pricing to shift loads to off-peak hours.

The report evaluates alternative electricity rate designs for mass-market customers, focusing on time-based rates and demand charges. It finds that well-designed time-based rates can significantly reduce peak load (0-50%) and total energy consumption (0-10%) without harming customer acceptance. Key drivers of success include high peak/off-peak price ratios, active enabling technologies, and opt-out enrollment. In contrast, the report notes a significant lack of empirical evidence regarding the impact of mass-market demand charges on peak reduction or customer acceptance, describing current claims as largely speculative. The document provides a framework of design dimensions—such as cost allocation, peak coincidence, and financial mechanisms—to guide utilities and regulators in implementing more sophisticated pricing structures that reflect system costs.

The paper argues that traditional cost-of-service regulation incentivizes utilities to invest in capital expenditures to meet peak demand. To counter this, it proposes a PIM based on an outcome-oriented metric—specifically the percentage reduction in peak load—rather than a measure-by-measure counterfactual approach, which it claims failed in California's Risk Reward Incentive Mechanism (RRIM). The author recommends setting long-term targets (five to eight years) with annual interim goals and utilizing a sloped, symmetrical incentive structure with upper and lower caps. To manage risk, the proposal suggests a gradual implementation starting with small revenue amounts, eventually scaling the PIM based on independent studies of the net societal benefits of peak reduction.