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Abstract Electric utilities are considering replacing their coal power plants with renewables and energy storage to reduce emissions. However, they have also expressed concerns about operational changes and system reliability brought by these replacements. Utilities in remote rural areas face more challenges as they also face energy insecurity while having limited interconnections to wider systems and reliance on imported fuels. Therefore, it is critical for remote utilities to understand different coal replacement approaches and their impacts on system expansion, operation and energy security. In this paper, we define and investigate three approaches to replace coal using wind and batteries: (1) replacing exact coal generation, (2) replacing at least coal generation, and (3) replacing total energy provided by coal. We develop a case study inspired by the small remote grid in Fairbanks, Alaska, which has a single limited interconnection with the grid south of it. We utilize a power system expansion and economic dispatch model that co-optimizes the capacities of wind and batteries required for each approach and the hourly dispatch of energy and reserves for one year. We further analyze the operational cost variability under fixed and fluctuating fuel prices. We find that replacing the exact coal generation requires minimal operational changes, but also significantly more wind and battery capacities. In contrast, replacing total energy provided by coal induces more cycling in other resources, challenging grids with limited flexibility-providing resources. However, replacing total energy provided by coal allows more generation variability in response to fuel price fluctuations, enhancing energy security. 

Green hydrogen, produced using renewables through electrolysis, can be used to reduce emissions in the hard-to-abate industrial sector. Efficient production and large-scale deployment require storage to mitigate electrolyzer degradation and ensure stable hydrogen supply. This paper explores the impacts and trade-offs of battery and hydrogen storage in off-grid wind-to-hydrogen systems, considering degradation of batteries and electrolyzers. Utilizing an optimization model, we examine system performance and costs over a wide range of storage capacities and wind profiles. Our results show that batteries smooth short-term fluctuations and minimize electrolyzer degradation but can experience significant degradation resulting from frequent charge/discharge cycles. Conversely, hydrogen storage provides long-term energy buffering, essential for sustained hydrogen production, but can increase electrolyzer cycling and degradation. Combining battery and hydrogen storage enhances system reliability, reduces component degradation, and reduces operational costs. This highlights the importance of strategic storage investments to improve the performance and costs of green hydrogen systems. 

Pumps in drinking water distribution networks can be controlled to participate in demand response programs. In this paper, we estimate the demand response potential of water distribution networks based on actual network data. We calculate the power and energy capacities of community water systems within Wisconsin and Arizona, drawing on publicly available data of consumer water demand, population served, storage tanks, and pump specifications. We then extrapolate this data to get an order-of-magnitude estimate for the entire United States. Overall, we found that water distribution networks are sizable demand response assets with an estimated power capacity of 13 GW and energy capacity of 750 GWh in the United States. We also found that large and very large utilities may be the best demand response candidates. This paper also discusses factors impacting water supply flexibility and future research directions.