EnergyPathways
The UK's most ambitious energy project.
Good Morning Team.
I enjoyed interviewing CEO Ben Clube today, covering the entire EPP investment case from start to finish.
Tune in!
But here’s the elevator pitch.
EnergyPathways is developing a single, enormous energy infrastructure project off the Cumbrian coast called MESH — the Marram Energy Storage Hub.
It wants to become:
Britain’s largest natural gas storage facility.
The world’s largest compressed air energy storage facility.
A major new domestic low carbon hydrogen producer.
And one of the UK’s only sources of battery-grade synthetic graphite.
All on one integrated site.
The UK government has formally designated the project nationally significant infrastructure.
But none of it is built yet and all of it is still years away. The market is currently valuing the entire thing at just shy of £20 million, which in energy terms is chicken feed.
The obvious gap between the potential and the market cap is the whole investment case.
Let’s dive in.
Britain’s energy storage problem
The lynchpin of the investment case is energy storage. Britain has almost no spare capacity to store energy, in any form.
This is the problem EPP aims to fix.
On gas, the UK can hold enough in storage for roughly 12 days of average consumption, or about 7.5 days at peak winter demand — against Germany’s 89 days, France’s 103 and the Netherlands’ 123.
The UK’s principal gas storage facility, FTSE 100 Centrica’s Rough field, has flip-flopped between closure and partial reopening for years, with Centrica repeatedly pushing for government support just to keep it viable.
On the renewables side, the problem runs the other way - too much clean power, nowhere to put it. Britain curtailed over £1.5 billion of wind generation in 2025 alone — paying generators to switch off, then paying gas plants to switch on instead, because the grid has nowhere to park excess wind power when supply outstrips demand.
UK offshore wind capacity is on track to roughly triple by 2030. One estimate circulating from government modelling puts the future cost of balancing a renewables-heavy grid at something approaching £8 billion a year if storage capacity doesn’t scale alongside generation.
When the bond market is close to crisis, you can’t afford to waste this amount of money, or energy - in a country with the highest energy prices in the developed world.
Layer on the geopolitics — extended blackouts in Spain and France, ongoing Middle East tension, the Ukraine War and an unpredictable backdrop generally — and UK energy security has become a first-order political issue.
The government’s Clean Power 2030 mission and clear appetite to back domestic infrastructure that cuts reliance on imported gas, ammonia and critical minerals like graphite is just the start.
MESH aims to capitalise on this demand.
What is MESH?
MESH is five things:
1. Large-scale natural gas storage
using salt caverns and the depleted Marram gas field. The licensed area supports potential for up to 60 salt caverns, and the current framing is that this element alone would roughly double Britain’s existing gas storage capacity and provide up to six days of additional national supply, at deliverability rates of around 15 million cubic metres a day.
2. Compressed air energy storage
which is the more technically advanced half of the project right now.
Surplus wind power compresses air into offshore salt caverns; when the grid needs it back, the air is released, heated and expanded through turbines to generate dispatchable electricity.
The offshore plant is designed around three compression trains and two generation trains, feeding four purpose-built caverns of roughly 700,000 cubic metres each, with the grid connection deliberately sited between the B6 and B7a constraint boundaries — the two transmission pinch-points that most frequently force wind curtailment in the first place.
The current specification is 300MW of power capacity and 55.2GWh of storage, sustaining output for over a week.
I’ve heard some describes this as ‘stores wind, sells it later,’ which is accurate but undersells the potential.
Because the system is turbine-driven rather than battery-based, it can participate in several distinct UK electricity markets simultaneously:
standard wholesale market
balancing mechanisms
capacity markets
and (probably the most interesting one) ancillary services, specifically grid inertia provision
That last point connects directly back to the Iberian blackouts mentioned above - a widely held technical explanation for why Spain, France and Portugal suffered cascading outages is that renewables-heavy grids lose the physical inertia that spinning turbines traditionally provide, making them more vulnerable to sudden imbalances.
A turbine-based CAES system is a direct technical answer to exactly that vulnerability, which is a sharper justification for the design than ‘energy storage good, no energy storage bad.’
It’s also worth considering the blue sky.
The arithmetic around replication is relatively simple, on paper. The CAES design needs four caverns; the licensed area covers up to 60. Read literally, that’s room for something like fifteen repeats of the CAES module without leaving the existing licence boundary, before any expansion elsewhere in the UK or into Europe via the modular design EnergyPathways has built with Siemens Energy.
I’d treat that 15x framing as illustrative rather than confirmed, though — the 60-cavern figure has so far been used specifically in relation to the gas and hydrogen storage licence, and it isn’t yet clear whether the same cavern pool is meant to be shared flexibly between gas storage and CAES, or whether CAES would need a separate allocation.
Still, even directionally, it points at a company sitting on meaningfully more geological storage potential than its current 300MW design uses — relevant context against the government’s own stated ambition of roughly 20GW of long-duration storage capacity nationally, against next to none today.
At 300MW, a single MESH CAES module is barely 1.5% of that target.
3. Low-carbon hydrogen production
using methane pyrolysis technology licensed exclusively in the UK from Australia’s Hazer Group, alongside global engineering firm KBR.
Unlike electrolysis (green hydrogen, typically £4-8/kg) or steam methane reforming (grey hydrogen, £1-2/kg but heavily emitting, or blue hydrogen with carbon capture bolted on), pyrolysis splits methane into hydrogen and solid carbon directly.
Projected costs for this ‘turquoise’ hydrogen at scale run £2-3/kg. The planned facility targets 20,000 tonnes a year, roughly 90MW equivalent.
4. Synthetic graphite
is a pyrolysis by-product — EPP is targeting 60,000 tonnes a year at 95% initial purity, upgradeable past 99.9%.
Graphite is a formally designated UK critical mineral, currently almost entirely imported (though ironically, the UK had the world’s first graphite mine, sited very close to EPP’s proposed development in Cumbria).
China controls somewhere North of 80% of global production. Battery-grade synthetic graphite has traded above $10,000 a tonne, more than double pre-pandemic levels, in a market growing 15-20% annually.
Running the obvious back of napkin maths — 60,000 tonnes at something close to current pricing — gets you toward the hundreds of millions in gross revenue potential at full nameplate output.
I’d treat that strictly as a ceiling rather than a base case; it’s a top-line calculation with no visible allowance for processing costs, capex amortisation or the realistic blended price once meaningful volume actually hits the market, all of which would pull the number down.
But it’s a by-product, so the margins should be excellent.
5. Potential low-carbon ammonia production
comes further down the line, using MESH-produced hydrogen as feedstock.
I think while exciting, this pillar is not material to today’s thesis. It will be a few years from now, but by that point the re-rate will have happened.
Regulatory risk removed
In September last year, the Secretary of State for Energy Security and Net Zero issued a Section 35 Direction confirming the major elements of MESH should be treated as nationally significant infrastructure.
This is a discretionary power used sparingly, and it put MESH on the Development Consent Order track — fixed statutory stages rather than open-ended conventional planning.
The DCO process typically runs: pre-application work, including environmental impact assessment, usually 12-24 months for complex projects; submission to the Planning Inspectorate, which has six months to examine it; a three-month decision window for the Secretary of State - and a six-week judicial review period afterward.
Hinkley Point C took roughly four years from submission to construction start while large offshore wind developments typically run 2-3 years. Large-scale battery storage has moved through in 18-24 months. MESH probably sits somewhere in the middle of that range.
Gas storage required its own NSTA licence, which took longer to come through than the company’s own earlier guidance suggested — one more data point in a pattern of optimistic initial timelines getting revised as the process actually plays out, which I’ll come back to.
It’s now secured, which has substantially de-risked the entire investment case, and covers an area with potential for up to 60 large-scale salt caverns, and the CAES project doesn’t depend on it at all — the two workstreams progress in parallel.
The other mechanism worth understanding is Ofgem’s cap-and-floor regime for long-duration electricity storage, which is the funding route specifically being targeted for the CAES project.
Modeled on a scheme Ofgem has run for electricity interconnectors since 2014 — which has reportedly returned roughly $256 million to consumers through lower bills over that period — it guarantees developers a minimum ‘floor’ revenue level, which is what makes debt financing viable at sensible rates, while simultaneously capping the maximum return so excess revenue flows back to consumers.
Once awarded, levels are fixed for the life of the scheme — generally 25 years, but a minimum of 20 if a shorter term is requested.
Eligible projects need more than eight hours of storage duration, which MESH CAES comfortably clears. The first window saw 171 applications narrowed to 77 entering assessment, mostly lithium-ion battery storage rather than CAES, and EnergyPathways is targeting the second window later this year, with informal engagement on the scheme apparently already underway ahead of formal application.
Consider that the chap who ultimately signed off on the S35 is very likely going to have significantly increased political power soon.
Who’s building this?
EnergyPathways has assembled a partner roster disproportionate to its size.
Siemens Energy — a €39 billion-revenue global energy technology company — has signed a cooperation agreement specifically to co-develop the CAES system and completed pre-FEED studies confirming its economic viability. The agreement is explicitly built as a repeatable, global framework rather than a one-off engagement for this single site, which opens the door to applying the same modular design elsewhere in the UK or in Europe if MESH proves the concept out.
Wood plc is providing the detailed engineering.
Costain plc has completed a first phase of onshore site evaluation at Barrow-in-Furness.
KBR and Hazer Group are running the engineering studies behind the hydrogen and graphite plant.
Zenith Energy is handling the well engineering for the offshore caverns.
Associated British Ports is evaluating its Port of Barrow for the onshore operations base.
Tier-1 engineering firms don’t lend their name to feasibility studies for projects they think are hopeless — the reputational cost is too high and their time isn’t limitless.
Their continued involvement is a form of due diligence already done, by people better resourced to do it than most investors.
How it’s being funded
This is a pre-revenue company, so the financing structure matters as much as the engineering.
The current facility is £15 million which comes in two pieces:
The first is a £5 million secured Loan Note, drawn down at the company’s discretion over three years, each drawdown carrying a 10% original issue discount.
Conversion is priced at a five-day VWAP Reference Price plus a 40% premium, with warrants issued alongside each drawdown carrying the same premium pricing.
The second is a £10 million At-The-Market equity facility, capped at 2.99% of issued share capital per tranche.
You’ve got to be careful understanding how this works, because there’s an easy mix-up - the ATM facility and the Loan Note’s premium-priced Reference Price are separate mechanisms.
ATM shares are sold at whatever the prevailing market price happens to be on the day — not at the discounted or premium reference price that governs loan conversions and warrants. Net proceeds split roughly 95/5 in the company’s favour after the facility provider’s fee.
Two drawdowns have happened so far: £1 million at the end of April, warrants struck at 8.3p against a 5.93p reference price, and another £1 million in early June, warrants struck at 12.24p — implying a reference price north of 8.7p, roughly 47% higher than five weeks earlier.
No warrants have been exercised yet.
This is a classic two-part small-cap financing structure which is common among AIM companies that need capital for capital-intensive projects but don’t yet have revenue or balance sheet strength for conventional bank debt.
That context matters for judging the terms — they’re not what a blue-chip with diversified financing options would accept, but they’re broadly in line with what’s available to a pre-revenue, project-stage company.
On the £5 million loan note, the company controls timing (drawdowns are ‘at the Company’s election’), so it isn’t forced to take on debt or dilution it doesn’t need yet.
The conversion and warrant pricing is set at a premium to the market price (Reference Price plus 40%), not a discount — meaning the investor only benefits from converting if the share price has already risen meaningfully, which loosely aligns their incentives with the company succeeding rather than profiting from a falling stock.
Interestingly though, each drawdown is ‘subject to mutual agreement,’ which means the investor can decline to fund a tranche - meaning this works as an option for the investor.
In practice though, this structure is similar to commissioning a tradie to replace your old kitchen - they get paid tranches as the work is done on time and to standard - and EPP will continue to get funded as long as the project gets to each milestone on time.
This interpretation becomes clearer if you consider the additional terms.
The 10% Original Issue Discount means the company receives 90p for every £1 owed, and with only a six month holiday before 6 monthly repayments, the effective annualised cost of capital is high once you account for the discount being absorbed in roughly a year.
The 3% per month default rate (36% annualised) is punitive if anything goes wrong. The security package — a fixed and floating charge over company assets — puts the investor ahead of shareholders and could constrain the company’s ability to raise other secured financing later.
The two features that deserve the most attention are the ratchet and the missed-payment mechanism.
The reset clause means that if the company ever issues equity at a lower price than the existing Reference Price, the conversion/warrant price ratchets down too — so a future down-round doesn’t just dilute shareholders directly, it also deepens the investor’s existing entitlements.
And the missed repayment provision — letting the investor take shares at a 10% discount to the lowest VWAP over the prior 20 trading days — is the kind of mechanic associated with ‘death spiral’ financings.
If the company is short of cash (which is presumably why a payment would be missed), the share price is also likely under pressure, and satisfying the debt in shares at that depressed price can push the stock down further, making the next settlement even more dilutive.
This is a tail-risk feature - but we do know the deal has been done with a ‘global institutional investor’ - and ultimately the deal is this:
EPP gets the cash, cash with which to build an exception growth case, but cannot afford to miss deadlines.
That’s the bottom line.
On the other hand, the £10 million ATM Facility is written with more shareholder protection than many equity lines of this type.
Shares can’t be sold below the prior day’s closing price — explicitly ruling out the discounted dumping that makes many toxic ATM facilities so damaging. There’s also a per-tranche cap (2.99% of issued share capital), volume participation limits and a requirement to sell ‘in an orderly manner,’ all of which reduces the risk of a single large sale crashing the price.
And the company decides if and when to draw on it at all.
The 5% fee on gross proceeds is a very normal cost — roughly £500k if the full £10m is drawn — which is on the higher end for this type of facility.
However, the investor (not the company) chooses whether to settle up to 50% of proceeds in cash or as a write-down against the Loan Note balance.
That means the company can’t fully rely on the ATM as a cash-generation tool; some of what looks like fresh funding might just be debt reduction the Investor elects rather than cash the company actually receives when it needs it.
For a pre-revenue company, getting £15 million of committed but flexible capital without an immediate large dilutive placing is a good outcome, and the ATM’s anti-discount and volume protections are genuinely better than many comparable facilities.
The trade-off is a debt instrument with a medium effective cost, asset security, and — most importantly — a missed-payment mechanism that could compound dilution sharply if the company ever falls behind on repayments.
The structure works fine if the company executes on schedule and doesn’t need to lean on the Loan Note’s downside protections but it gets considerably more punishing if cash gets tight.
There is also a component here to consider - it’s very possible that being awarded the licence was only possible if financing was in place - and now that the licence is awarded, better terms can be negotiated.
And remember, the total £15 million is a bridge. If EPP successfully reaches its next major milestone and attracts larger-scale institutional infrastructure funding (banks, government or sovereign wealth), this entire facility could be paid off and rendered irrelevant.
So will the team execute?
Essentially, this all means that the investment case relies on management competence even more so than usual.
Fortunately, our CEO is a non-nonsense chap.
Ben Clube has steered the company through the Section 35 process and the licence award, leaning on a team with deep North Sea offshore engineering experience rather than a large in-house headcount, with the heavy lifting on individual workstreams outsourced to the Tier-1 partner network above.
I’d expect further partner announcements over the coming months on that basis — bringing in outside expertise piece by piece, rather than building it internally, looks to be the deliberate model here.
The board was recently strengthened with Martyn Millwood Hargrave as Chief Scientific Adviser and Alison Flower as a Non-Executive Director, with Mark Steeves chairing the board.
FID is now targeted for 2028, with operational startup at the end of 2031.
That’s a 5+ year story before any revenue arrives, which is a geological epoch in AIM market terms. But the wait is worth it for the size of the prize.
Perhaps the most interesting recent observation worth making is that even after the gas storage licence award in May — a very real de-risking event — the shares didn’t sustainably clear 10p in the days that followed, despite having touched as high as 12.75p at other points over the 12 months.
My personal view is that the company has effectively swapped the risk they wouldn’t get a licence for risk that the financing agreement causes damage in the event of delays.
This means, very simply, that operational execution is exponentially valuable - get it right, the share price will rise so the price at which the ATM and facility issues also rises - while conversely, the opposite is also true.
What might this be worth?
What follows is an illustrative way of thinking about how the valuation could move at each de-risking gate, built from the revenue figures floated for the project and from how comparable development-stage energy infrastructure stocks have actually re-rated, in both directions, around similar milestones.
Treat it as a way to reason about the optionality, not a price target.
Today: pre-FID, pre-financing, roughly £19 million or so.
At FID (2028 guided).
Base case: both CAES and gas storage reach FID broadly on schedule with the DCO granted or well advanced, clearing the bulk of planning and engineering risk.
Bull case: the hydrogen/graphite workstream reaches FID alongside the other two, with a named cornerstone partner already in place.
At cornerstone financing/construction start.
Probably the single biggest re-rating event in either direction, since it’s where financing risk — the thing that’s historically crippled projects like this — actually resolves.
Base case: financing closes roughly as guided, with EnergyPathways retaining a meaningful equity stake in what’s now a debt-backed, construction-ready asset.
Bull case: competitive tension among cornerstone investors, premium equity pricing and the Knox & Lowry expansion assets folded into the package, with the cap-and-floor allocation also secured by this point, locking in revenue certainty on the CAES side specifically.
At first revenue / operations (late 2031 guided).
The disclosed figures give two anchors: roughly $200 million a year in potential combined revenue from the hydrogen, graphite and ammonia subsystem alone, and ‘hundreds of millions of pounds annually’ floated for the fully integrated system.
Run the maths on a fully built-out, multi-module CAES platform within the existing licensed cavern allocation — speculative as that scaling assumption is — and the long-run ceiling looks considerably larger again than the single-module figures suggest, against a UK LDES market the government itself is trying to grow toward 20GW from almost nothing.
Base case: revenue ramps toward even a tiny fraction of the disclosed full-system ambition, at which point an operating, cash-generative, multi-revenue-stream asset should command a materially different multiple than a pre-revenue developer.
Bull case: full nameplate achieved across all revenue streams, with replication into a second or third CAES module within the existing licence area already underway.
The bear case is the same across each component - it simply doesn’t work out.
The reality is that the spread between bear, base and bull cases is wide at every gate - so AGAIN, delivering on time is key to building confidence and getting as close to the bull case as possible.
In pure revenue terms, consider the conjoined components:
1. Gas storage
The company hasn’t put a revenue figure on this segment specifically, so the most useful thing I can do is anchor to Rough’s actual track record.
Centrica’s Rough facility generated roughly £500 million during the gas-market dislocation in late 2022 — an unusually good trading year, not a steady-state number, caused by the impact of the Ukraine War.
In 2025, dwindling returns and low seasonal spreads meant the division was expected to lose between £50 million and £100 million.
But more normally, analysts model Centrica’s entire energy trading division at somewhere around £310-370 million of EBITDA, of which Rough is one contributor among several.
In other words, when times are good, Rough pays massive returns, but bad years can see small losses - this is key to why MESH needs to be multi-commodity, as like Centrica, it needs diversification to weather the storms.
Centrica itself has also been explicit that redeveloping Rough into a larger gas-and-hydrogen facility would cost roughly £2 billion, and that it needs a cap-and-floor-style regulatory support framework to make that economic — which tells you something useful.
Even the UK’s most experienced gas storage operator doesn’t think pure merchant economics are enough to justify new build at this point, and is asking for the same kind of revenue-certainty mechanism EPP is targeting for CAES.
On margin character, storage is a high-fixed-cost, low-variable-cost asset once built — most of the spend is the infrastructure itself, not ongoing operations — so EBITDA margins on contracted capacity revenue specifically tend to run high, plausibly 50-70%, with the trading/spread component being far lumpier year to year.
I wouldn’t put a single number on what MESH’s gas storage segment is worth; it’s a multi-tens-of-millions-of-pounds-a-year opportunity at full build, scaled down from Rough’s economics to reflect a smaller, newer facility.
But government incentives to build out energy storage are very plausible and I see this happening as well.
2. CAES
This is the one segment with a half-decent direct comparator.
Corre Energy has disclosed that its 320MW Ahaus project — almost identical in power rating to MESH CAES’s 300MW — could capture roughly €1 billion of net revenue over a 15-year offtake agreement, which averages out to around €65-70 million a year.
If MESH CAES lands anywhere near that, you’re looking at something like £55-60 million a year from this single module, though I’d treat that as a loose sanity check rather than a true comparable, since contract structures differ and Corre’s figure is itself a company projection rather than an audited outcome.
On margin, the economics look very attractive, because the input ‘fuel’ is curtailed wind power that would otherwise be wasted at close to zero marginal cost.
The main cost lines are maintenance — CAES systems run 5-10x higher maintenance costs than batteries because of all the moving mechanical parts — and the capital cost of the kit itself. Once built and ideally backed by a cap-and-floor allocation, I’d expect EBITDA margins in the 60-80% range, which is roughly what you’d expect from a regulated, revenue-certain infrastructure asset generally.
On the capex side specifically, since ‘profit potential’ only matters relative to what it costs to build - a real-world comparable, Huaneng’s 300MW/1500MWh CAES project in China, cost $270 million to construct.
Power-train cost benchmarks separately suggest something like $1,350 per kW for a base-case CAES system, which at 300MW (300,000kW) lands around $400 million.
Putting those together, a reasonable order-of-magnitude range for MESH CAES’s core build is somewhere between $270-600 million (roughly £210-£475 million) — and given MESH is designed for over seven days of discharge against Huaneng’s roughly five hours, the extra cavern development required pushes me toward the higher end of that range, since cavern volume (even though cheaper per unit than the power train) still adds real cost at this scale.
That’s the actual size of the capital conversation behind ‘cornerstone financing’ — multiple hundreds of millions, not the £15 million currently funding FEED.
You can see the potential!
3. Hydrogen
The company’s claimed production cost for pyrolysis-based ‘turquoise’ hydrogen is £2-3/kg. For context, UK green hydrogen via electrolysis costs roughly $7/kg in production terms (alkaline or PEM, including capex and near-term grid power prices) — more than double EPP’s claimed cost — and the government’s own subsidised strike price for green hydrogen under the first Hydrogen Allocation Round averaged £241/MWh, or about £8/kg.
If EPP’s hydrogen can be sold anywhere near that £8/kg reference point — whether through formal low-carbon hydrogen support (pyrolysis is described as a qualifying technology under the relevant standard) or simply through industrial offtake agreements priced off the same decarbonisation value — the gross margin per kilogram looks excellent.
Run it conservatively - even at an achieved price of £5/kg against a £2.5/kg cost, 20,000 tonnes a year implies roughly £100 million of revenue and £50 million of gross margin from this single 90MW module, before capex amortisation.
That’s a better starting position than most UK hydrogen projects currently have, because the production cost is structurally lower than the alternatives the government is already paying to subsidise.
The big unresolved question is what EPP would actually achieve in a negotiated offtake as offtakers on this scale are small in number — but that would be a lovely problem to have.
4. Graphite
As noted above, 60,000 tonnes a year at anything near today’s $10,000/tonne price gives a gross revenue ceiling around $600 million, but that’s a top-line number using a spot price for premium volumes, not a realistic blended price for 60,000 tonnes of new annual supply hitting the market.
On margin, there’s an interesting structural point - because graphite is a by-product of the hydrogen process, a share of the underlying production cost arguably gets absorbed by the hydrogen side of the ledger already, which could make the graphite segment’s standalone margin look more attractive on paper.
The caveat is that reliably hitting 99.9% battery-grade purity at commercial volume is (in my view) going to be a technical challenge, and any blended realistic price across a full 60,000-tonne annual run is very likely below the current spot price for small premium batches.
You’re still making very serious money but I think better to assume a discount to premium spot and be pleasantly surprised if you get top dollar.
5. Ammonia: nothing quantified anywhere in the public material yet — pure optionality, not modelled.
But optionality does have a value attached.
Putting it all together
Stacking rough, hedged ranges across the four quantifiable segments — tens of millions for gas storage, perhaps £50-60 million for a single CAES module, something like £100 million-plus for hydrogen at a reasonable achieved price, and a discounted fraction of that graphite ceiling — gets you into a full-system range that’s consistent with the ‘hundreds of millions a year’ figure floating around, probably somewhere in a wide £150-400 million annual revenue band at full nameplate output across everything.
Applying a blended EBITDA margin assumption in the 55-70% range (storage and CAES pulling it up, hydrogen and graphite pulling it down) gets you to an illustrative EBITDA figure perhaps in the £80-250 million range at full maturity.
Translate that into equity value and you immediately hit the real question: contracted, de-risked infrastructure cash flows of that scale would typically support a high-single to low-double-digit EV/EBITDA multiple once operational — call it 8-12x as a rough infrastructure-fund benchmark — which would put enterprise value somewhere in the £650 million to £3 billion range at the very top end of a fully successful build-out.
But that has to be netted against the several hundred million pounds of capex and project debt actually required to build it, and against however much further equity dilution happens between now and then.
The gap between that enterprise value and what’s left for today’s shareholders depends on financing terms that are yet to be negotiated.
That’s the honest version of ‘asymmetric upside’: the revenue and margin economics, where you can actually check them against real comparables, look wonderful — particularly the hydrogen cost spread.
And we NEED more gas storage and we NEED to capture the billions of pounds of wasted wind energy currently being wasted.
There is a political element in all of this that is hard to model - but the key point is that any level of government backing changes the risk profile immensely.
And the government consider the project nationally significant.
The bull case, for the dreamers
I cover asymmetric investments for sophisticated investors seeking exposure to blue sky potential growth.
I expect readers to understand the risks exist and are very real.
But if all goes to plan, then very soon, government validation will have materially de-risked the planning pathway. Tier-1 partners across engineering, technology and infrastructure have independently screened the project and committed resources.
There’s exclusive UK access to a cost-competitive hydrogen technology, a graphite by-product in a structurally undersupplied market, and a financing structure built to reward shareholders rather than extract value from them.
The licensed cavern area appears to hold more capacity than the current single-module design uses, pointing at real replication potential well before considering expansion beyond MESH itself via the repeatable Siemens framework.
And it’s hard to ignore the obvious follow-on dynamic: licences like this don’t come around often, and EnergyPathways secured one that considerably larger players would also have wanted.
That scarcity tends to attract takeover interest in this sector regardless of what any individual company says publicly, and I wouldn’t be surprised if interest — formal or informal — continues circling the stock as FEED progresses, though there’s nothing in the public record suggesting a deal is imminent and it shouldn’t be treated as one.
Layer on Rough’s repeated wobbles, the Iberian blackouts and a government explicitly hunting for shovel-ready clean infrastructure, and the timing argument is compelling.
What to watch next
Confirmation that the KBR-Hazer hydrogen and graphite engineering study has completed
Progress on the formal DCO pre-application process
Formal Ofgem cap-and-floor application in the second window, building on the informal engagement reportedly already underway
Further drawdowns under the £15 million facility and whether the reference price keeps climbing
Additional partner announcements as the team continues to lean on outside expertise rather than scale headcount internally
Any sign cornerstone financing discussions are closing
That last one is key, and small caps always leave clues for you to pick up on if you’re prepared to Sherlock Holmes for breadcrumbs.
And it’s worth considering catalysts that could come out of the blue at any time:
A takeover offer at a whacking great premium.
Government support via Great British Energy or similar.
A fund taking a position now the licence is secured.
MESH CAES is awarded cap-and-floor.
National Grid ESO or NESO formally inlcludes MESH in capacity / stability planning models.
Siemens Energy expands the scope from CAES design to a global rollout framework.
UK/European winter gas stress event that creates scarcity re-pricing of storage risk.
Any of these these could see a one day re-rate.
The bottom line
EnergyPathways is an unusual proposition for a sub-£20 million AIM company: government-validated, Tier-1-partnered, structured with shareholder-aligned financing, sitting on more storage capacity than its current design even uses and diversified across distinct energy and materials markets.
That combination is rare at this size, and it’s why I like the set-up. However, pretending there are not risks is not reasonable.
Ergo, this isn’t a trade. It’s something to buy and hold for years.
And if Ben pulls this off, the financial returns vis à vis the market cap could be incredible.