## 1 Introduction  
Current energy systems, relying primarily on fossil fuels (coal, oil, natural gas), produce carbon and greenhouse gases (C&GHG), contributing to the problem of global climate change. There is therefore, an increasing need to reduce C&GHG emissions. From initial targets of 80% reductions by 2050, in June 2019, the UK Government set a revised target of net zero emissions by 2050 [1], which was followed by the launch of the EU's 'European Green Deal' in December 2019 [2]. These aims will require significant effort across many industrial sectors that represent large emission sources, including electrical power generation. Worldwide, transitioning from fossil fuel to cleaner, but intermittent, unpredictable, and inherently more variable mixed renewable energy sources (wind-power and solar photovoltaic [PV] plants) for electricity generation is enabling GHG emission reductions. However, if naturally variable renewable electricity sources comprise high percentages(>80%) of the generated supply, the daily and seasonal variations in generation and capacity places greater challenges on power networks to meet transmission and distribution demands [3]. Alongside seasonal variation in electricity demand, issues then arise over security of supply, as power systems require balancing at various scales, ranging from second and minute reserves, to hourly, daily, weekly, and inter-seasonal (monthly) storage to meet and offset variability [3,4]. Therefore, patterns of demand not following such variations in electricity generation from renewable sources require fast-ramping, back-up generation, supported by reliable forecasting and, importantly, increased bulk, grid-scale storage capacity [3,4]. Electrical energy storage (EES) technologies are recognised as underpinning technologies to meeting these challenges, but they vary greatly in capacity, role, and costs. Some technologies provide short-term, small-scale energy storage options (e.g., batteries), whereas others represent load-levelling and longer-term utility scale and grid support through chemical and mechanical bulk energy storage technologies. The two largest and only current commercial, grid-scale, mechanical bulk energy storage technologies capable of providing fast ramp rates, good part load, and long duration are pumped hydroelectric storage (PHS) and compressed air energy storage (CAES) [5]. They are less economic or suitable as inter-seasonal storage options to balance longer term, seasonal fluctuations, or long-lasting wind shortages due to low volumetric energy storage densities (\(\approx\)0.7 and 2.40 kWh/m\({}^{3}\), respectively; see below) [6]. Despite extensive investigation and research into CAES technology from the 1960s [7,8], worldwide, commercially operational grid-scale CAES capacity is provided by just three salt cavern-hosted facilities: the conventional (diabatic) Huntorf, Germany (1978, 321-MW) [9], and McIntosh, USA (1991, 110-MW) CAES plants [7,8,10], and in November 2019, the small (1.75 MW/7 MWh+) plant at Goderich, Canada, which became the world's first commercial adiabatic CAES plant [11]. Sustained rapid growth in wind power and making it dispatchable has renewed interest in CAES [5,12]. Despite significant research and some extended tests [13,14], no porous rock CAES plants exist, which is due mainly to economic and geological factors that, prior to development as a realistic storage option at scale, must be overcome [3,12]. Nevertheless, offshore porous rock storage is advocated as having inter-seasonal potential for the UK [15]. Particularly pertinent, following the UK Government's October 2020 announced intention of becoming the world leader in green energy involving mainly increased offshore wind farm generation [16], we explore the prospects and possible capacity of salt caerns for UK CAES exergy storage in selected onshore and offshore massively bedded halite deposits (Figure 1).