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The paper outlines an adaptive approach to electricity policy for a hypothetical jurisdiction, focusing on modernizing rate design and market structures to integrate distributed energy resources (DERs). It argues that traditional cost-of-service models are outdated due to technological advances in home automation and on-site generation. The author proposes four key principles for retail rates—cost causation, transparency, adaptability, and customer sophistication—and four principles for market structure—level playing fields, grid stability, innovation, and transparency. The framework is designed to be applicable to both vertically integrated utilities and market-based systems, emphasizing the use of Integrated Resource Plans (IRPs) and Integrated Distribution Plans (IDPs) to ensure long-term system optimization.

Analysis shows that the weighted average cost of coal power in the U.S. rose from $36/MWh in 2021 to $46/MWh in 2024, a 28 percent increase that outpaced inflation. This rise is attributed to higher fuel, operations, and maintenance costs, as well as declining capacity factors. Despite these economics, some U.S. federal policies and state regulators have extended the lives of expensive plants, such as Plant Bowen in Georgia and the Hunter and Huntington plants in Utah, potentially increasing the financial burden on electricity consumers.

The document serves as a regulatory guide, offering a structured set of inquiries to help Public Utility Commissions (PUCs) assess utility resource planning in the context of the Inflation Reduction Act (IRA). It organizes questions into five exhibits covering common IRA considerations, assumptions, forecasts, objectives/scenarios, and solution identification. Key areas of focus include the application of Investment Tax Credits (ITC) and Production Tax Credits (PTC), bonus adders for energy communities and domestic content, the integration of hydrogen and carbon capture and sequestration (CCS) technologies, and the utilization of Energy Infrastructure Reinvestment (EIR) financing. The toolkit also emphasizes the need for utilities to account for IRA-driven changes in load forecasts related to building and transportation electrification, energy efficiency, and distributed energy resources (DERs).

The paper presents 12 combinations of three demand and four supply scenarios to help Tamil Nadu plan its energy mix through 2030-31, emphasizing the need for storage integration in ambitious renewable pathways and careful power purchase planning given the financial state of TANGEDCO.

The document outlines how to assess the cost-competitiveness of behind-the-meter solar PV, noting that parity is achieved when the average cost of energy equals or is less than the retail electricity price. It highlights a common third-party ownership model in the United States that removes upfront costs for consumers and provides a glossary of key energy finance and planning terms.

The document outlines the criteria for determining when utility-scale renewable energy is cost-competitive compared to traditional power sources, emphasizing the importance of the perspective used for comparison. It defines cost parity from three viewpoints: for end-use consumers via Power Purchase Agreements (PPAs), against other technologies filling the same capacity need based on average cost of energy or risk, and against the current wholesale market generation mix based on average wholesale prices during production times.

The document highlights the cost-effectiveness of energy efficiency programs in the U.S., citing specific utility savings in Minnesota, New Mexico, and Arkansas, and economic projections for Massachusetts and Wisconsin. It advocates for scaling up federal appliance standards, updating building codes, and implementing financing mechanisms like PACE and green banks to increase adoption.