In this article, we explore challenges and solutions regarding how to integrate long-duration energy storage (LDES) into electrical system operations and planning. First, we identify specific challenges with using LDES in electric systems, especially in terms of operations and planning. Second, we describe how other industries (e.g., gas) forecast commodities and inventory, which parallels energy storage. Third, we describe how solutions that other industries have implemented can be used to address the challenges of integrating LDES. Fourth, we provide a high-level overview of a mathematical solution to LDES challenges. Finally, we identify the next steps in developing the proof of concept described in this article.

Multiple state initiatives exist for establishing valuation of distributed energy resources (DER), most notably the California Locational Net Benefits Analysis (LNBA) and the NY Renewed Energy Vision (REV). These frameworks, like most others, require utilities to provide a mechanism for identifying a locational value of DER to the grid in terms of avoided cost. At ComEd, we serve 11,500 square miles of territory in northern Illinois, including the city of Chicago. ComEd has approximately 5500 distribution feeders and our peak recorded load was 23,613 MW, in August 2006. This paper focuses on ComEd’s theoretical and computational framework for identifying a value to the grid in terms of avoided cost, that can be used as the basis to calculate DER compensation for the provision of distribution grid services. This paper emphasizes the value a DER can provide to the grid by necessary controls and active management.

This work concentrates on reserve requirement to balance load and generation in the network where variable energy resources (VERs) are incorporated. The presence of VERs (such as solar and wind generation) and loads introduces variability within each hour and forecast errors, leading to imbalances in supply and demand of a system. Balancing reserves are needed to regulate this imbalance. For a particular system, capacity of reserve is required to be determined for imbalance regulation. In this work, a statistical analysis-based method is proposed to quantify the capacity of balancing reserve requirement for a transmission system considering historical load and VER generation. This proposed method also considers calculation of expanded reserve requirement considering future growth of VER generation. This method is evaluated in 1-minute interval 1-year historical data received from a Caribbean utility under the jurisdiction of the USA. Comparatively lower difference in percentage of error on reserve requirement for given data with simulated results from the proposed method, supports its use in calculating balancing reserve capacity for expanded capacity.

The transition to decarbonized and electrified energy systems is accelerating the adoption of photovoltaic (PV) systems, electric vehicles (EVs), and battery energy storage systems (BESS) in distribution networks. Utilities must expand hosting capacity for these distributed energy resources (DERs) while ensuring grid reliability. Traditional planning approaches often struggle with the probabilistic nature of DER adoption and the computational burden of Monte Carlo-based simulations. This paper introduces a novel probabilistic framework for hosting capacity assessment, eliminating the need for Monte Carlo simulations while improving accuracy and efficiency. We formulate hosting capacity as an optimization problem that accounts for DER adoption uncertainty and grid reliability constraints. Our method determines PV and EV hosting capacities under different confidence levels and identifies optimal non-wires alternatives (NWAs), such as BESS, to enhance grid capacity. Our findings reveal that the proposed method provides more reliable hosting capacity estimates with significantly reduced computational time compared to traditional approaches. Additionally, our co-optimization framework enables utilities to strategically balance NWAs and conventional grid upgrades. These methodologies offer a robust foundation for utilities and regulators to quantify electrification-related grid costs and guide strategic investment decisions.

Flexibility is a key asset in dealing with uncertainties in investment, operations, and decision making. Traditional Transmission and Distribution (T&D) planning today faces unprecedented uncertainties driven by decarbonization and political/economic volatility. Years of low or negative load growth are forecast to become historically high load growth driven by electrification of transportation and building sectors and, in time, agriculture and industry. Generation planning and how it drives T&D planning are subject to uncertainties around renewables adoption, especially when individual consumer decisions determine investments in distributed photovoltaic (PV) and storage. Technology development introduces uncertainties around performance and cost improvements in all these areas. Volatility in public policy can drive volatility in, for instance, electric vehicle (EV) and PV adoption as incentives and mandates change with changes in federal, state, and local politics.

The growing proliferation of distributed energy resources (DERs) is perceived as both a challenge and an opportunity for electric utilities. DER integration requires a modernized power grid capable of addressing the two-way flow of power as well as managing increased energy usage, availability uncertainty, and potentially higher feeder hosting capacity to ensure these new additions do not cause network congestion.

The future U.S. electric grid is being transformed with deep decarbonization of generation (i.e., removing or reducing reliance on fossil fuels and replacing them with renewable and clean energy resources), which in practice is not achievable without a dramatic increase in the reliance on long-duration energy storage (LDES) technologies. Regulators at both the state and federal level are well advised to take steps to address current policy gaps, build frameworks that will enable a greater role for LDES to contribute to grid reliability and be fairly compensated for its grid services. . Decarbonization by definition is dependent on an increasing reliance on variable renewable energy, primarily wind and solar resources, that needs to be stored for longer durations to maintain electric grid reliability and provide operational flexibility to grid operators. However, despite the growing realization of the need for long-duration energy storage (LDES) technologies, a persistent gap of policy levers at the federal and state level creates a vacuum in terms of defining how and where LDES technologies can be utilized to support the electric grid, along with an inadequate regulatory framework wherein these resources will need to be valued and compensated for the services they can provide. This paper—which is primarily intended for US decision makers, but should be of value for all energy professionals and the general public—addresses policy gaps, needs, and opportunities for LDES that require urgent attention from US-based policymakers at the federal and state level. This paper also provides background information on how the US E&U industry is structured and regulated, along with perspectives on LDES technologies and applications, all of which have direct relevance to the paper’s primary focus on the need for LDES policymaking. Discussion Despite a generally accepted future need for long-duration energy storage (LDES) technologies that is directly tied to the rapid of renewable resources on the U.S. electric grid, there is a lack of policymaking, market designs, and compensation mechanisms for LDES technologies. Decarbonization (i.e., the goal of removing or reducing reliance on fossil fuels) cannot be achieved at the aggressive levels envisioned without utilizing LDES. Policymakers must take steps now to build frameworks that recognize the unique ways in which LDES will increasingly contribute to grid reliability and resilience, and receive appropriate compensation for the services it provides. Graphical abstract

The potential of DERs to act as non-wires alternatives (NWA) has been widely studied. This paper focuses on low voltage AC systems (LVAC) because they present various challenges: they have high upgrade costs and a very large number of nodes. To obtain the cost-optimal NWA portfolio (DER type, location and size) for LVAC upgrade deferral without increasing the computational burden, we introduce an incremental injection batch runs approach to calculate sensitivity-based values for each node. Ranking the nodes based on this value allows us to decrease the problem size by excluding bottom-ranked locations. Further, we use the sensitivities to form an optimal power flow whose output is the optimal DER portfolio and corresponding optimal sites and sizes. A case study based on an actual utility meshed distribution network has been presented to demonstrate the proposed framework.

This article discusses the upcoming changes in the electricity industry including electrification, and the drive toward fossil-free generation, and the role of energy storage (ES) in electrification and the operation of a future electric grid without fossil fuels. Though our discussion is primarily focused on the United States electricity system, the issues affecting the operation of future electr...

The topic of Non-Wires Alternatives has recently gained a lot of attention in the literature and industry alike. One of the Distributed Energy Resource (DER) types most commonly examined as an alternative solution to feeder issues is Battery Energy Storage Systems (BESS). BESS has been investigated as a solution, amongst others, to thermal capacity deferral and PV integration problems for both the transmission and distribution sides of the grid. In this paper, we focus on distribution applications of storage and showcase efficient planning-level algorithms to utilize storage against two types of distribution feeder capacity shortages: (i) substation capacity deferral and (ii) voltage magnitude control. The proposed planning methods and algorithms combine computational efficiency with high granularity in time and location. We use generic distribution tree feeder topologies and loading data and hourly shapes to demonstrate our results. We also show how these methods fit in and expand traditional distribution planning and the benefits they can provide given the current status of distribution networks, DER and renewable penetration.

In this paper, we address the issue of valuating distributed energy resources (DERs) as non-wires alternatives (NWAs) against wires investments in the traditional distribution network planning process. Motivated by the recent literature on distribution locational marginal prices, we propose a framework that allows the planner to identify rigorously the short-term locational marginal value (LMV) of DERs using the notion of marginal cost of capacity (MCC) of the best grid investment alternative to monetize hourly network constraint violations encountered during a yearly rate base timescale. We apply our methodology on two actual distribution feeders anticipated to experience overloads in the absence of additional DERs, and present numerical results on desirable LMV-based generic DER adoption targets and associated costs that can offset or delay different types of grid wires investments. We close with a discussion on policy and actual DER adoption implementation.

This paper presents part of the work ComEd and Quanta Technology have performed to quantify the locational and temporal value of DER to avoid distribution grid upgrade investments. It focuses on the formulation of a robust and efficient algorithm for DER optimal dispatch on a distribution feeder to mitigate the violation of current and voltage limits using the allocated cost of capacity and locational marginal value of real and reactive DER injection/withdrawal.

Distributed Energy Resources (DERs) are argued to be a significant benefit to the electric utility grid. While DERs generate significant benefits to their owners and as well as society, the compensation and operating structure of the distribution system of most utilities is such that DERs result in minimal benefits to the distribution system. As we show, the benefits correctly attributed to the distribution company (the wires company) are a function of what service (real, reactive power) the DER is able to provide, when and where, and at what level of certainty the DER is able to provide the service. We introduce the concepts of Marginal Cost of Capacity (MCC) and Locational Marginal Value (LMV) in the calculation of the value of DERs to the distribution system.

Distributed Energy Resources (DERs) are argued to be a significant benefit to the electric utility grid. While DERs generate significant benefits to their owners and as well as society, the compensation and operating structure of the distribution system of most utilities is such that DERs result in minimal benefits to the distribution system. As we show, the benefits correctly attributed to the distribution company (the wires company) are a function of what service (real, reactive power) the DER is able to provide, when and where, and at what level of certainty the DER is able to provide the service. We introduce the concepts of Marginal Cost of Capacity (MCC) and Locational Marginal Value (LMV) in the calculation of the value of DERs to the distribution system.

Electric utilities are experiencing a rapid growth of distributed energy resource (DER) deployment in their distribution grids. DERs can result in operational challenges in distribution grids, while at the same time can be viable assets in helping electric utilities better plan and manage grid design, operation, and planning. The DER valuation becomes an extremely important factor in this situation to ensure that DERs are fairly and accurately valued for the services they provide. This paper investigates the idea of spatiotemporal valuation of DERs and develops a sensitivity-based locational marginal value (LMV) calculation method that can be solved without the need for solving the network power flow problem. Furthermore, the impact of cost allocation to various upgrades in the system on LMV calculation is investigated, with the goal of demonstrating the fairness of the proposed LMV calculation method. The proposed model is applied to a standard test system for evaluation and validation.

Discusses the market and development of power distribution energy resource systems (DERs). A huge game changer for utilities and possibly market operators will be the need to gain visibility and potentially control of hundreds of thousands of DERs. DERs can, and will, include photovoltaic (PV) generation, electric vehicles (EVs), demand response (DR), combined heat and power, storage, small-scale ...

Discusses the market and development of power distribution energy resource systems (DERs). A huge game changer for utilities and possibly market operators will be the need to gain visibility and potentially control of hundreds of thousands of DERs. DERs can, and will, include photovoltaic (PV) generation, electric vehicles (EVs), demand response (DR), combined heat and power, storage, small-scale wind, and other technologies. Some might say that this is the province of a distributed energy management system (DERMS), but a supervisory control and data acquisition (SCADA) system with applications by any other name is an energy management system (EMS)/ distribution management system (DMS)/ DERMS or even a battery energy management system.

Electric power systems around the world are undergoing an unprecedented transformation. In the U.S., this evolution has been clustered and described under various terms, including smart grid, grid/utility of the future and grid modernization. Building this intelligent grid is a monumental task – particularly on the distribution and grid-edge sides, which are vast and heterogeneous – that has led to the emergence of new concepts, technologies, and paradigms. Here is a roadmap to implementing them.

In Addition To Their Age, Particularly in large metropolitan areas, electric power systems throughout the industrialized world face challenges brought on by new technology trends, environmental concerns, evolving weather patterns, a multiplicity of consumer needs, and regulatory requirements. New technology trends include the development of more efficient, reliable, and cost-effective renewable generation and distributed energy resources (DERs), energy storage technologies, and electric vehicles (EVs), along with monitoring, protection, automation, and control devices and communications that offer significant opportunities for realizing a sustainable energy future. The medium- to long-term vision for the electrical grid is to transition away from carbon-based fuels toward increased penetration of renewable DERs and use of energy storage and electric transportation.