UK-listed developer EnergyPathways is planning the Marram Energy Storage Hub (Mesh) in the eastern Irish Sea, a project designated by the UK government as nationally significant. Mesh comprises a 300MW compressed air energy storage (CAES) system across four salt caverns and natural gas storage in a further eight caverns. EnergyPathways also wants to produce gas from the undeveloped Marram field and then to later use the field for storage. Eventually, the firm plans to repurpose the gas storage caverns for hydrogen. It is also considering a methane pyrolysis plant in Barrow-in-Furness to produce 20,000 t/yr of hydrogen and 60,000 t/yr of graphite, while evaluating conversion of the hydrogen into up to 110,000 t/yr of ammonia. Argus spoke with chief executive Ben Clube about technology, phasing and policy. Edited highlights follow:
What problem is Mesh trying to solve?
The UK grid is moving from base-load gas power to mostly renewables. The immediate challenge is intermittency, which in the UK means wind rather than solar. Most surpluses arise in events lasting more than 24 hours. This needs long-duration energy storage (LDES), which the government sees as critical. LDES projects shortlisted so far run for up to 30 hours and 17 on average. Relying on batteries is flawed, as UK batteries average 1.4 hours and stacking is prohibitively expensive.
How does your CAES system work and compete with gas-fired power?
We will store surplus renewable power as compressed air in salt caverns and discharge it through turbines when renewables fall short. The 55GWh system has 190 hours of duration, covering wind lulls of up to seven days. It is diabatic, meaning we heat the air with a fuel at discharge, initially natural gas and ultimately 100pc hydrogen. We aim to reach full power in two minutes from a cold start. As a turbine system, it will deliver synchronous inertia that earns grid stability revenue.
The UK relies heavily on gas-fired generation to back up renewables. Gas sets the electricity price about 60-70pc of the time, but supplies less than 30pc of power. When dispatching, we will displace gas and its price-setting role, as we believe our short-run marginal cost will undercut combined-cycle gas turbines (CCGTs). We will store curtailed wind effectively priced at or below zero and burn far less gas, so our emissions trading system (ETS) costs are lower. Our efficiency is also about 60pc, against about 50pc for CCGTs given how variably they run.
The entire storage system will be grid-connected. Our connection strategy is being worked through, but we could add flexibility between offshore generators and the grid. With grid costs and green subsidies pushing up industrial power prices, we also see significant opportunities for behind-the-meter supply to industry.
Why build offshore and how far could storage grow?
The offshore salt sequence lets us build very large caverns of 700,000m³ each, providing economies of scale. We estimate capital costs at about £9,000/MWh of storage, against about £200,000/MWh for batteries and 5-6 times ours for pumped hydro. Our licence area could hold up to 60 caverns and CAES is modular, so we can add units in phases. Some estimates put UK renewable surpluses at up to 70 TWh/yr. Cycling our 55GWh for 10 times a year is only about 500GWh.
Where does natural gas storage fit in?
Gas is essential for keeping the lights on, but domestic output is falling quickly with the North Sea's decline and policy settings. The UK has little gas storage capacity. By 2030, it could import up to 90pc of its gas in winter peaks, much of it bought just-in-time on the spot market. A government consultation on gas supply security last year was really about developing more. We have offered a large project using the same salt sequence and an undeveloped gas field, which is ideal for storage. It would hold six days of national supply, doubling UK capacity, and we think it is viewed favourably as it costs less than other projects being considered. The stored gas would also be a strategic reserve to drive our power generation beyond the 190 hours from CAES.
Why add hydrogen production using methane pyrolysis?
The hydrogen would displace natural gas in our power generation and storage, providing a decarbonised strategic reserve. We quickly dismissed renewable electrolytic hydrogen because of UK electricity costs. Cracking methane takes about a sixth of the energy of cracking water. Pyrolysis also yields solid carbon. With the technologies we are evaluating, this is graphite and graphene, which are more valuable and useful to industry than carbon black. Graphite is the major commercial enabler. The government considers graphite a critical mineral, with the UK reliant on imports and China dominating global production and processing. Hydrogen for power and storage would reach the offshore caverns from the port of Barrow plant through existing, hydrogen-compatible pipelines. We think all this will make our low-carbon hydrogen competitive with UK blue hydrogen.
Why are you assessing Hycamite's technology alongside that of Hazer and KBR?
Both are methane pyrolysis, but they work differently and deliver slightly different products. Hycamite's technology is more about graphite, with grades that suit battery, defence and nuclear uses. The Hazer Group and KBR technology has strengths in hydrogen production, scalability and downstream ammonia. We are evaluating both and the plant could use both.
What are your ammonia plans and how will hydrogen use be split with power?
We would use hydrogen ourselves for power generation. We are also evaluating a clean ammonia plant, integrating pyrolysis hydrogen with KBR's ammonia synthesis loop. The UK has effectively no ammonia production — grey or low-carbon. Undeveloped gas in this part of the UK also typically comes with nitrogen, a major cost advantage over installing an air separation unit. It is early stage, but we think we will be competitive with renewable ammonia prices and could even compete with grey imports, which use cheaper methane, especially with the carbon border adjustment mechanism (CBAM). We would also consider exports to Europe, as the port gives us shipping, rail and road links for ammonia and graphite.
The exothermic ammonia loop will cut a significant share of the hydrogen plant's energy needs. We can also adjust hydrogen output with electricity prices, in effect storing surplus power as hydrogen, which lowers costs. Then it comes down to the value of hydrogen-to-power relative to ammonia.
Which part of Mesh will be built first?
Each project component is independent. LDES is the pillar, but has the longest lead time, mainly because of planning processes. Gas storage could move very quickly with the right policy framework, which we expect in the Energy Independence Bill in autumn. If it mobilises investment, we will push ahead and could be running by 2030-31. The hydrogen plant could be built in as little as two years, and we want to progress it on graphite's commercialisation potential instead of waiting on the government's hydrogen strategy. If things go well, it could come ahead of the other two. It would start using grid gas, but stored gas or indigenous gas in the field would further improve its commerciality.
