Mark Moore

Ofgem’s proposed fee starts at £3,000/MW and climbs to £25,000/MW only if the surplus doesn’t shrink. At the start that’s around 3% of build cost for a short-duration battery. Projects that intend to build can carry it, and those holding a position as an option get a reason to think again.

I’ve supported it in my response to Ofgem. The one addition I’ve suggested is a way to see who ends up holding the queue.

A developer facing a rising security has more than two choices. Alongside staying and leaving, it can sell the project to someone better placed to fund it, and the capacity stays in the queue under a new owner.

The register wouldn’t show that. When Alpiq bought 90% of Harmony Energy in July, for reasons that have nothing to do with the fee, Companies House stopped naming anyone as controlling the company. The TEC Register lists project companies and has no ownership field, so it recorded nothing.

Ofgem expects the competition effects to be limited. Ownership reporting alongside the securities statements would let that be tested as the fee takes effect.

The full article also covers the 9 GW of batteries looking to convert to data centres, and how Ofgem costs the liquidity the fee requires.

If the queue shrinks, how would anyone know whether it’s held by more owners or fewer?

Imagine hiring a haulage firm, and the contract came with three conditions.

You pay a flat daily fee for the truck, whether it leaves the depot or not. For the biggest sites connected straight to the national grid, that’s £20,829 a day, about £7.6 million a year, just to have the connection available.

If the firm needs a new truck to serve a new customer, that customer doesn’t pay for it alone. Everyone else on the local network gets a little added to their bill to help cover it.

And whatever happens, the firm earns a return on its investment set in advance by the regulator, not won in a competitive market. Performance moves it a little either way. Right now the baseline is 5.7% on the national lines and 5.23% on the local ones.

Put plainly, customers are forced to buy the truck, and the haulier still gets paid, on a truck it now owns. Much of what’s spent on it joins the company’s asset base, which is what its return is calculated on.

The only way round it is to generate your own power next door and run a private line. Even then, if you stay connected to the grid, the fixed daily charge still applies.

If you wouldn’t sign that contract with a haulage firm, why accept it from the company that delivers your electricity?

Full sources and figures in the article.

Provenance: Analysis.

User Commitment (CMP192, 2013) makes a project carry part of the network cost, though lightly at first: liability starts at 25% of the Wider Cancellation Charge after a trigger date roughly three years before energisation. Queue management milestones (CMP376, 2023) test progress and remove projects that stall. At entry, the TMO4+ gated process tests readiness and fit against Clean Power 2030. Then came the Progression Commitment Fee (CMP448), approved December 2025. It sits dormant, covers projects between Gate 2 and Milestone 1, and runs from £2,500/MW to £10,000/MW if terminations pass a threshold.

CMP470, Ofgem’s minded-to consultation published on 17 September, starts at £3,000/MW and climbs to £25,000/MW. It switches on when a technology exceeds its government capacity target by more than 50%.

That trigger is the new part. The earlier four respond to a project’s own conduct. CMP470 responds to the aggregate: roughly 90GW of BESS operational or at Gate 2, against a FES-derived 29GW for 2035. A consented battery sitting below the floor has to lift its security the same as a placeholder does. Ofgem’s own impact assessment says the fee makes projects compete on liquidity, and admits it cannot predict how many will leave.

Is a mandated trigger the best approach?

If the trigger is a government target, who carries the cost when the target moves?

72.8 GW of data centre connection requests sit in NESO’s 2025 pipeline data. By 2030, NESO expects 6.0 GW of data centres to be connected in total, of which about 4 GW is new. That new capacity is roughly 5% of the request. Across the whole fleet, expected average draw in 2030 is about 1.4 GW.

Three assumptions sit between those numbers. Queue success is capped at 50%, and lower for less-progressed projects. New sites take seven years to build out. And NESO has cut its utilisation assumption from around 70% to 29% of built capacity, using distribution network data. That cut is why its 2030 demand forecast fell from about 20 TWh to 12.6 TWh even as forecast capacity rose.

Metered data points the same way. TwentyForty’s analysis of 96 data centres on UK Power Networks’ network found the median site drew 18% of contracted capacity, and nearly half never passed 40% even at their busiest half-hour.

The distribution connection terms already allow a network to propose reducing capacity after twelve months below 75%. How often that happens is not published.

The workings, sources and limits are in the accompanying article.

If most connected data centre capacity is expected to sit well below its booked level for years, what should happen to it before the network builds for the rest of the queue?

Analysis. The data is NESO’s and TwentyForty’s. The arithmetic and the reading of the connection terms are mine; the clause point comes from original research not yet published.

They sit on different bases. £40-50 is in the range of European energy-only PPA prices. For an illustrative 100MW transmission-connected site at a 90% load factor, the UK charges added on top of energy come to roughly £75-100/MWh before any power has been bought.

On the same basis, excluding energy: UK (Scotland) £75-100/MWh; Sweden about £27-31/MWh, most of it electricity tax; Spain, above 145kV, about £6-8/MWh; Norway about £2-12/MWh, depending on connection point.

Network charges are the smaller part in Scotland. The locational transmission charge for demand there is zero, the fixed residual comes to around £10/MWh at this size, and balancing adds about £13/MWh. Policy levies (RO, CfD, Capacity Market, Nuclear RAB, FiT) add roughly £50-70/MWh.

A renewable private wire can avoid most of those levies, but only on what flows over the wire. Anything drawn through a retained grid connection carries the full stack.

Tomorrow I’ll publish a longer piece on the network side: who the carriers are, how they’re paid, and what a data centre is actually buying from them.

How much of a flat data centre load can a Scottish private wire realistically carry, and has anyone published that figure?

Analysis: NESO, Ofgem, LCCC/EMRS and HMRC 2026/27 figures, with Nordic and Spanish tariff and tax data. Capacity Market and FiT from secondary sources; Nordic network figures are my calculation.

The applied-for figure comes from a compilation of local authority planning portals. The allocated figure comes from a Scottish Government answer to a written question, and the transitional Regional Energy Strategic Plan carries 1.6GW for data centre demand in Scotland. So developers have applied for roughly four times what the people who have to build the network are planning for, and nearly twice what the whole country draws at winter peak.

Both numbers are public. I have not seen them put side by side.

Which is where the structures get interesting. Apatura has nine schemes across the Central Belt, each in a separate vehicle. The Larbert applicant is Apatura DC Project 5 Ltd. ILI has three more, branded The Stoics, at Auchtertool, Hurlford and Newhouse. A planning consent attached to a connection position is a tradeable asset, and holding one requires nobody to pour concrete.

Falkirk holds a pre-determination hearing on the 300MW Larbert scheme next Tuesday, after 6,719 objections. It will be assessed against NPF4 and the Falkirk local plan, on its own. North Lanarkshire will assess Ravenscraig on its own. Fife will assess Auchtertool on its own. The 7,150MW question reaches no single decision-maker anywhere in the system.

I’m thinking about a monthly tracker that traces ownership and progress. Would anyone be interested to see that?

So I went looking for what sits behind those seven.

Six are ASTI schemes I already hold licence dates for: Norwich to Tilbury (two projects), Eastern Green Links 1 and 2, Yorkshire GREEN, and the Brinsworth to Chesterfield to High Marnham upgrade. The seventh, Sea Link, I have left out, because its landing points are inferred from geography rather than named in the ASTI description.

Against the TEC Register of 25 August, those six have 69 contracted projects at their named substations, totalling 37.4 gigawatts. That is 5.5 per cent of the register. Ten of the 69 carry no energisation date at all. Drax alone accounts for 8.2 GW.

This is a narrower cut than the ASTI-wide figure I posted on 7 September, not a revision of it.

As at March 2026 the NAO records three of the seven as off track for Clean Power 2030. The other four are on track, but facing significant delivery risks.

NESO responded the same day, under the heading that strategic planning is essential to delivering value for consumers and industry. One line in it is worth keeping: consumers pay when infrastructure build and generation fall out of step. That is the mechanism, conceded by the body best placed to dispute it. The rest of the response is about coordination across government, Ofgem, network companies and NESO, and says that no single organisation holds all the levers. Reporting takes fewer levers than delivery does.

Ireland’s CRU decision of December 2025 starts at 1 MVA of Maximum Import Capacity, and from 10 MVA a site has to bring dispatchable generation or storage at least equal to its import. It’s final, and facing a High Court challenge.

Spain’s draft royal decree, put to public hearing on 27 August, applies from 1 MW of access power; the preamble says access power was chosen because the thing being allocated is network capacity.

Germany’s Energy Efficiency Act catches sites from 300 kW of non-redundant nominal connected load, and the government bill approved by cabinet on 24 June would move that to 500 kW of installed IT power, the EU reporting threshold. Fingrid’s draft grid code sets its large-demand requirements at 30 MW of rated demand.

GB has three numbers on two rulers. Ofgem’s Curate proposal sets the commitment fee threshold at 40 MW, and the drafted CUSC text measures that against connection capacity. The queue management milestones are consulted on at 10 MW of rated IT load. The drafted definition, which I worked through for my Curate response, follows the Cyber Security and Resilience Bill: 10 MW for an enterprise data centre and 1 MW for everything else, colocation included.

Rated IT load and connection capacity pull apart once cooling overhead and redundancy are counted. One scheme can sit above one line and below the next.

Should GB measure the fee and the milestones against one quantity, or is there a case for keeping two?

Analysis. The texts are CRU’s, MITECO’s, the German government’s, Fingrid’s and Ofgem’s. The reading of them is mine, and the GB drafting point is in my Curate response.

Chapter 7 asks whether the new queue management milestones should apply above 10MW rated IT load. That’s Ofgem’s stated preference and it’s what’s being reported.

The drafted CUSC text doesn’t set that threshold. It defines a Data Centre Service as any facility at 1MW or above, unless the facility is on an Enterprise Basis, meaning its sole purpose is serving its owner’s own undertaking, in which case the figure is 10MW. Colocation isn’t enterprise basis. Neither is anything built to lease or sell on. So for most of the commercial sector the drafted floor reads as 1MW.

The draft direction to DNOs then applies that same definition to every distribution customer sitting outside a Transmission Entry Assessment, with no MW threshold in it at all.

The fee, meanwhile, gets a proper threshold instrument. Condition E18, annual review, 28 day consultation, Ofgem approval before the number can move. The milestones get nothing equivalent.

Practically, a 2MW colocation site on a DNO connection is outside the regime as Chapter 7 describes it and inside it as drafted. That’s compute offtaker evidence, long lead procurement, an investment grade rating or committed credit support, and design certification.

Both limbs track the Cyber Security and Resilience Bill, so the drafting is faithful to the Bill. Chapter 7 describes one of them.

Have I read this correctly? Is the definition doing the work of the threshold, or does the threshold decision come later and the drafting simply runs ahead of it?

Over the past few weeks I've been tracking connections in detail, which is useful but doesn't reveal the underlying pattern. So I tested the folklore against published data (base: 14-08-26).

Ofgem's Accelerated Strategic Transmission Investment (ASTI) framework covers 26 transmission projects. Each one carries a delivery date written into the transmission owner's licence, in Appendix 1 of Special Condition 3.41. That date is the optimal delivery year plus twelve months, an allowance Ofgem added in 2022 for supply chain conditions, and Special Condition 3.41.5 then permits a further twelve months before the output counts as undelivered.

A full three years sit between the year the system was judged to need a reinforcement and the date a penalty starts running.

I matched those 26 projects to the NESO TEC Register. That gives 39 substations, 186 entries and 96 GW, roughly 14 per cent of the register by volume.

Then I compared every connection date to its own scheme's licence date.

Under 10 per cent land on the licence year. Another 4.5 per cent fall inside the twelve-month grace. The median entry sits two years beyond it. And 22 per cent are dated before the optimal delivery date, so ahead of infrastructure that on any published reading will not exist yet.

I ran it twice, once taking the earliest governing scheme and once the latest, because several substations depend on more than one upgrade. Waiting for the last upgrade made the fit slightly worse.

So, connection dates don't track the published regulatory schedule. Whether they track an engineering programme that the licence date only loosely follows, I can’t tell you from the published data.

Perhaps a high drop-out rate is simply expected to do the correcting?

If you're underwriting a project on its connection date, what do you think sits behind that date? Are you still relying on folklore and luck?

I traced eleven companies at Companies House, from the project vehicles up to the top of the UK structure. Every PSC entry unchanged since formation. No charges registered anywhere in the chain. The top company files a statement that it knows of no registrable person, which is correct, because the shareholder above it is Canadian and not registrable here. Management of the portfolio moved to Octopus Energy Generation in March and was confirmed publicly in June. That was a management mandate. No shares moved, so the ownership record sat still through all of it.

Then I looked for what separated the seven from the four that stayed. Gate status doesn't do it, the withdrawn projects were more likely to carry a Gate 1 label than the survivors. Connection date doesn't either, the latest date in the whole group belongs to a project that stayed.

What I think decides it isn't published. Gate 2 wants an option that reflects the operational timeline. Reform pushed dates into the 2030s, so options agreed for two or three years need extending, and by then the landowner knows what the site is worth. Annual payments replace a single fee. One of the withdrawn projects, rated 900 MW, carries a cumulative loss of about £430,000, so relatively little had been spent on it.

If you are selling into developers, how can you tell a live pipeline from a parked one?

Between 2 February 2024 and 14 August 2026 the register grew from 531 GW to 685 GW, and from 1,577 projects to 2,064. Narrow it to the reform window and it's starker. Of the 1,851 projects on the 28 January 2025 file, 1,791 are still there in August 2026. Sixty had gone, carrying 18.2 GW between them. Another 273 had joined.

The explanation arrived last week in a response to an environmental information request (NESO ref FOI/26/174). The register's Gate column is populated only once an agreement has been countersigned, and stays blank until then. On the 14 August file, 400 GW of the 685 GW is blank.

So the register is a contractual record with a countersignature lag in front of it. It was never built as a scorecard for the reform, and it doesn't work as one.

That matters in both directions. I keep seeing the queue total quoted as evidence the reform hasn't bitten, and it isn't evidence of that. It's evidence that contracts take a while to sign.

Where would you go instead for a project-level view of what reform actually removed?

Note added 27 September 2026: the blank-Gate figure on the 14 August 2026 file is 395.3 GW; the post rounds it to 400 GW.

My first attempt at this grouped capacity by connection year across the snapshots. That analysis was wrong and I dropped it. Built projects have their effective date blanked on the current file, so the year bands were not comparing like with like, and the totals mixed genuine date changes with projects that had only just joined the register.

So I tracked individual project IDs instead.

On the February 2024 file, 326 projects carried a connection date of 2026 or earlier, 55.5 GW between them. Two and a half years on, here is where that cohort sits. 71 projects are built, 16.3 GW. 99 still carry a near-term date, 13.9 GW. 137 have moved to 2027 or later, 22.8 GW. Another 19 have left the register altogether, 2.6 GW.

So about 41 per cent of that near-term capacity has pushed back by at least a year, against 29 per cent delivered.

Some of that is capacity genuinely arriving later. Some will be projects parking a date they have no intention of meeting. The register doesn't distinguish between the two, and I don't think anything published does.

If you're modelling revenue against a connection date on a current TEC entry, how much weight are you putting on it?

Checking them took longer than writing the post would have.

Aura Power merged with Verdant Energy on 6 August, backed by CVC DIF, creating a platform with around 1GW operating and under construction plus a 10GW pipeline. The Aura Power brand stays. Founder Simon Coulson stays too, on a minority stake.

Cero Generation was never independent in the window I was checking. Macquarie's Green Investment Group launched it back in 2021. Enso Energy, its UK development partner, is a separate company entirely.

Starlight is NextEnergy Group's in-house development arm. Earlier this year it sold a Scottish battery project to the NEUK I Fund, owned by NextEnergy Capital, inside the same group.

Fidra Energy hasn't changed hands, but it was EIG Global Energy Partners' platform from the outset, not really independent either.

One name survived the check. TBC Partners, a founder-owned family office, still trades as itself.

The post I meant to write doesn't exist. The one I found instead makes the case better than my original research did.

Name five independent developers in this market today. How many would survive the same check?

Since 12 June 2026, any demand facility over 30 MW connecting directly to Fingrid's transmission network must be able to cut its power intake by at least 30%, to at least three separate levels, within 15 minutes of being asked. Data centres, electrolysers, electric boilers, all in scope. The obligation bites now, running ahead of the full KJV2026 grid code, which is still out for consultation and closes this Friday.

A graphic doing the rounds on LinkedIn presents this as an integrated flexible load model: battery storage, on-site generation, heat reuse into district heating and energy market participation, all pictured as though each one carried the same status. Only the curtailment capability is actually mandated. Everything else in that picture is one commercial route to meeting it.

Worth being precise about what the obligation costs, because there is an easy misreading here. The requirement is measured on import at the connection point. A facility has to draw less, and it can do that by throttling compute, by discharging a battery to cover its own load, or by running backup plant it has probably already built for resilience. None of those needs an export-capable connection. The harder problem is the controls and telemetry layer that lets the system operator dispatch the reduction reliably inside fifteen minutes, which for a colocation operator is a tenant contract question as much as an engineering one.

Britain has already signposted the same direction.

Ofgem's live Curate consultation, closing 16 September, deals with queue viability and the proposed Data Centre Commitment Fee, and is silent on curtailment. The flexibility question sits in the Operate pillar, which Ofgem has flagged for consultation in autumn 2026 with a focus on flexibility requirements and operational control for large demand users.

If the UK does go in this direction what could it mean for your project?

Note added 27 September 2026: the KJV2026 consultation closed on 21 August 2026, and Ofgem’s Curate consultation closed on 17 September 2026.

On Monday I asked where you'd actually look to find out who you're contracting with on a UK battery project. This is why I asked.

I checked again this morning. Harmony Energy Limited now carries a statement that there is no registrable person or registrable relevant legal entity. Nobody is named at all.

Nothing improper has happened here and I want to be clear about that. Alpiq completed its purchase of a 90% stake in July. Unlisted overseas companies can't go on a UK PSC register, so Alpiq can't be listed. The rules then say look through to the individuals behind it, and Kavanagh's retained 10% sits under the 25% threshold. The statement is the correct filing. It's the regime working as written.

Meanwhile the visible business is unchanged. Same name, same chief executive, same team, eighteen grid-scale projects delivered and around 400MW under construction. Second ownership change on that name in about a year, after Harmony Energy Income Trust was taken private by Foresight in June 2025 through a bidco split 51/49 with one of Foresight's own portfolio companies.

So the UK's beneficial ownership regime is built to find an individual, and it does, right up until control passes to a diffusely held overseas corporate. Then the trail ends lawfully and the register names no one.

What do you actually rely on, when the register says nobody?

(BtW, no disrepect to Harmony here, it was just one of a series of recent transactions that illustrated the point that I was trying to make.)

I've read a lot of pieces this year telling data centre developers to engage earlier and be more transparent. The advice is sound. I haven't seen anyone measure it though.

The measurement exists in other sectors. Slovic wrote about trust and risk perception in 1993 and concluded that public distrust isn't ignorance, it's structural, and once trust goes it's very hard to get back. Moffat and Zhang modelled community acceptance across an Australian mining region in 2014, and found procedural fairness was the strongest single predictor of trust, and that the quality of contact with a community mattered while the quantity of it didn't. Devine-Wright surveyed 503 residents in the South West in 2013 about a proposed high voltage power line and found trust in the developer was one of the significant predictors of opposition.

None of that work has been pointed at data centres.

Over the past few months I've spent some time tracing the fifteen largest UK data centre schemes back to whoever ultimately controls them. It's Companies House, PSC filings and planning documents, and it takes a while. Several of the largest end up at privately held platforms that most people wouldn't be able to identify without doing the same work.

What I don't know yet is whether that matters.

If you can't find out who's building the thing at the end of your road, does the opposition get harder, and by how much. I've got the ownership data. I haven't settled the design.

So, two asks. If you've run a structural equation model on community acceptance, I'd like ten minutes of your time. And if you know where scheme level objection data sits, please tell me.

All three carry Capacity Market contracts.

The seller was Eku Energy. Two weeks before that, Eku had bought a 300MW/600MWh project at Didcot from TBC Partners, its first transmission-connected battery in the UK, due to connect in 2028.

Same business, one fortnight, roughly 107MW of finished assets out and 300MW of consented development in. That's capital recycling, it's an ordinary infrastructure model and I'm not implying anything else about it. Eku is jointly owned by a Macquarie Asset Management fund and British Columbia Investment Management Corporation.

None of it shows up at project level, though. Maldon is still Maldon, same site, same CM contract, same planning file.

What moved was who collects the revenue.

If you were running counterparty checks on a UK battery site this month, where would you actually look to find out who you're dealing with?

Or more importantly, would you even think to look?

Your credit assessment was done against an owner who might not be there any more. Your parent company guarantee could be pointing at a parent that's left the structure. And signing authority moves, which you usually find out about when procurement centralises and your renewal turns into a tender.

Meanwhile your contact is the same person, the letterhead is the same, the pipeline is the same, and the name in your CRM hasn't moved.

I've spent three weeks tracing ownership on large UK energy projects through Companies House. Britain's largest consented battery has had three eras of control since January 2023, behind a company rename that's filed as an amendment to details. A 400MW solar scheme sold in February resolves one step up to a Dutch entity and then stops, which isn't evasion, it's just the design limit of the register.

Everything is filed. Almost none of it is readable at the point somebody needs to make a decision.

I also corrected something I got wrong in the first article of this series.

Full piece here.

DESNZ dates the first major grid-scale battery storage project in the UK to 2017. The year before, National Grid awarded 201 MW of Enhanced Frequency Response across eight projects. So the sector is nine years old. The requirements I keep seeing sit at five to seven years, which sounds modest until you count backwards. Seven years from now means you were in it before August 2019, inside the first two and a half years. Five years means before August 2021.

Annual output from UK batteries went from 0.5 GWh in 2017 to almost 2,300 GWh in 2025. Nearly everyone working in British storage today arrived after a seven year filter closes. That filter is not selecting the best people in the sector, it is selecting the earliest ones, and those are different populations.

Data centres are not the same problem, and lumping them together is where most commentary on this goes wrong. That sector is decades old. Its constraint is throughput, not age. Uptime Institute found 46 per cent of operators struggling to find qualified candidates in 2025, with operations management overtaking junior roles as the biggest gap as experienced people retire, and about a quarter of leavers simply moving to a competitor.

Then there is the awkward bit. Van Iddekinge and colleagues meta-analysed 81 samples in Personnel Psychology and found prior experience correlates with job performance at 0.06, and with staying in the job at 0.00. Under half a per cent of variance explained. Harvard and Accenture asked 2,250 executives about it and 88 per cent agreed their own processes screen out qualified people for missing exact criteria.

So the years-in-sector line is filtering hard on something that predicts almost nothing, in sectors that cannot supply the years anyway.

If you have been ruled out of one of these roles, the filter that removed you was not measuring whether you could do the work. That is not me being kind, it is what the evidence says. Keep going.

If you write these specifications, what would you put in that line instead, and would your panel actually trust it?

More detail available in the linked article below.

This week, the thread that matters if you carry a revenue number. Picture a sales director building next year's plan. The CRM shows fifteen live prospects across those projects. Fifteen relationships, fifteen probability weightings, fifteen doors. Now lay the ownership map over it. Those fifteen projects resolve to roughly ten ultimate decision-makers, and three of them (Macquarie, CIP, EDF) hold multiple positions each. The prospect list is the same length it was yesterday. The customer count is not.

None of this is a forecast, it has already happened, it just happened below the visibility of the market maps everyone sells from. The early signs are there if you look. Sungrow has supplied BW's storage platform in Sweden, then at Bramley, then a 1.4GWh order at Hams Hall, the relationship travels with the platform rather than the project. Macquarie's pivot of Island Green Power from selling projects to keeping them turns a fifteen gigawatt pipeline into one owner's procurement function.

Other industries have walked this road before us. Groceries ended up with a statutory code and a regulator. Car making restructured its entire supply base into tiers. The full argument, including the honest counter-forces, is in the article below.

A question for anyone running revenue in this supply chain: have you ever re-cut your pipeline by ultimate owner rather than by project name, and if you did, what happened to the number?

Blackstone does originate one of the biggest schemes outright, its campus in Northumberland. EDF is the more striking case. It already owns UK solar capacity, and it isn't quietly sitting on an overlap. It has signed a memorandum of understanding to build a 1 gigawatt data centre powered by new nuclear reactors, on the site of its own decommissioned coal station, in partnership with Tritax Big Box, a FTSE 250 property company, with the Energy Secretary's name on the announcement.

So it isn't five funds quietly owning both sides. It looks more like two separate markets, mostly obscure private ownership at the very top of one, and the rare fund that does move into power doing it in the open, at government level, rather than through a structure you'd need to trace.

Which is harder to keep an eye on: the pattern nobody's watching, or the strategy nobody's bothered to add up?

Everyone assumes concentration arrives the way it does elsewhere, developers buying developers, deals that make the trade press. Standing in the bramble patch it occurred to me that it does not need to. Nearly every big renewable project in Britain is its own company. So the market can concentrate one project at a time, quietly, and the number everyone watches, the count of independent developers, never moves.

Brambles look like dozens of separate plants. They are usually one plant, connected under the soil. You only find out by digging. So I spent the weekend digging, through Companies House, into fifteen of the largest consented solar and battery projects in Britain, about 8,800MW.

What I found: the named developer is materially misleading for at least ten of the fifteen. The largest battery project in the country, listed everywhere as a Scottish storage firm, traces through three group companies to Washington DC private equity (with, curiously, the UK's National Wealth Fund as a minority investor in a structure it does not control). And in case after case the sale follows within a year of planning consent. Consent is the trigger.

By capacity, around 20 percent of these projects remains in genuinely UK-independent hands. I have started calling it the bramble thesis. The full fifteen, the method, and the honest counter-examples are in the article linked below.

Whose job should it be to make this visible?

Britain has decided what energy system it wants faster than it can build it. Everything interesting in the sector right now happens in that gap, and every mechanism I've written about is really an answer to the same question: while we wait for the wires, who pays?

Constraint payments are the gap priced annually, over £1bn a year, consumers paying wind to stop and gas to start in the same hour. The LDES scheme is an attempt to pay once for an asset that absorbs the gap instead (7,645MW provisionally selected, the floor structured as insurance rather than subsidy). The connections queue, cut from 700GW to a 283GW prioritised pipeline, turned grid access from a formality into a rationed asset with holding costs. And April's residual charge increase showed what happens when a charge designed around yesterday's behaviour meets customers who adapt.

The key points here are probably that the technology arguments are mostly settled and the capital is mostly available. What decides winners now is mechanism design, the fine print of who holds which risk when the assumptions drift.

So here's the question I'd put to both sides of the market. If you're deploying capital, are you underwriting the asset or the mechanism it sits inside? And if you're designing the mechanisms, which of your calibration assumptions would survive the market adapting to them?

Here is the part I keep coming back to. There is an old idea in economics, Goodhart's law, that any measure you turn into a target stops measuring what it used to, because people start managing the number itself. Agreed capacity was a fair enough proxy for how much network you lean on, until the charge on it grew big enough to be worth optimising. So some sites now run forensic half-hourly analysis to show their real peak sits under their agreed capacity, then apply to drop an ASC band. Others are fitting behind-the-meter batteries purely to shave that peak so the band comes down anyway, which is really a bet that the charge keeps rising (NESO's own trajectory says it will), so the market is already pricing where this goes.

To be fair, not all of this is gaming. You cannot drop a band on paper, you have to actually release the capacity or you breach and pay for it, so some of what is happening is over-declared headroom being handed back, which is efficient and probably overdue.

From the regulator's point of view, the bands were set around the capacity that the firms had already booked, on the quiet assumption those bookings would stay put. But make the charge big enough and people rebook, so the ground the whole thing stands on starts to move.

So which is it. A charge doing its job, finally flushing out capacity that was never really needed. Or a charge sold as unavoidable, slowly proving it was nothing of the sort. I would love to know which way the people who set the bands would call it.

The structural shift underneath is the more interesting story.

Connections reform did three things at once. It rationed grid access, cutting over 700GW of applications down to a prioritised pipeline of 283GW of generation and storage. It made new entry uncertain, NESO has removed the target date for the next application window and signalled it will be limited by technology and location. And it attached holding costs to the positions that survived, with progression milestones and non-delivery charges in force since January.

Put plainly, a Gate 2 position is now a scarce, dated asset that must be actively defended with capital and delivery capability. Assets with those characteristics do not stay evenly distributed for long.

The capital flows already point this way. Global energy transition deal volumes fell around 15% last year while deal value rose over 20%, fewer and bigger bets. Infrastructure funds increasingly want multi-technology platforms rather than single projects. And last month Drax agreed to acquire Bluefield, taking a 2.9GW development pipeline into a listed generator alongside 0.9GW of operating assets. The US saw the same pattern first, where approved interconnection positions became the currency driving platform consolidation.

My working view (held loosely, the developer distress data is not in yet) is that the Gate 2 process will be remembered less for the delays and more as the moment UK development stopped being a cottage industry.

If grid position is the scarce asset, who is best placed to hold it, the developers who originated it or the platforms consolidating around it?

Now run the other branch. The Eastern Green Link projects and wider B6 reinforcement are due in the early 2030s, around the time several of the shortlisted batteries commission. If the wires arrive on schedule, spreads compress, merchant revenues fall, and floors start binding, leaving consumers funding the reinforcement and topping up floors on assets whose revenue case has eroded. Awarding 7,645MW, the very top of Ofgem's guided 2.7 to 7.7GW range, makes that exposure larger rather than smaller.

Ofgem's implicit defence is that major transmission projects are rarely on time and the constraint need will outlast the plan. History supports them. But notice what that means: the scheme's economics quietly depend on the underperformance of a parallel programme the same regulator oversees.

Nobody outside the confidential bid data can check how floor levels compare with projected constraint savings. The arithmetic may well work. We're simply not shown it.

Should a consumer-funded programme of this size publish the numbers that justify it?

A battery sited behind a Scottish constraint boundary charges when wind would otherwise be curtailed, often at negative prices, and discharges when the boundary frees up or demand rises. That spread is market revenue, not support payment. If it holds, the asset earns above its floor, the floor pays out nothing, and the cap claws back anything beyond a fair return on invested capital. Consumers only pay in years the asset underperforms.

That's insurance rather than subsidy, and it isn't a novel idea either. It's the same model that financed Britain's interconnectors, applied to storage.

It also explains the durations on the 26 June minded-to list, which run from 8 to 22 hours against a merchant market that stops paying at around 4. Constraint events last days rather than minutes, and hours nine through eighteen only become financeable once somebody underwrites them. The floor is that somebody.

The whole structure rests on one assumption, though: that the constraints persist. Friday's post covers what happens if they don't.

The argument runs like this. Connection studies have treated batteries as firm at system peak in both directions. A worst case, and one that inflated reinforcement assumptions and clogged the queue. NESO has conceded the point. Its connections reform material commits to remodelling storage to reflect how batteries actually run, across transmission and distribution. Model them realistically and the network has more room than the queue suggests. On this reading, the oversupply is partly an artefact of bad assumptions.

The modelling point is right. The conclusion does not hold.

Fixing the modelling lowers connection costs. Lower costs make more marginal projects viable, not fewer. The fix feeds the queue it was meant to relieve.

And the oversupply was never measured in dispatch assumptions. It is measured in capacity. NESO expects to award connection agreements to over 80GW of battery storage by 2035, roughly three times what Clean Power 2030 implies the system needs. Remodel every battery in the queue and that ratio does not move.

So the answer to Thursday's question is yes, but not at the point most people are watching. Connecting is about to get easier, not harder. What gets harder is the revenue case. When 80GW can connect and the plan has room for a third of it, a grid offer stops being the scarce asset. The scarce asset is a problem the system is paying to solve. The right duration, in the right place.

Which puts a question to anyone opening a Gate 2 offer this summer. Is that connection agreement the thing you queued two years for, or the start of competing on price with everyone else who got one?

Constraint costs passed £1bn a year some time ago, and NESO's own projections have them climbing until the major transmission reinforcements land in the early 2030s. The wind is in Scotland, the demand mostly isn't, and the wires between them are full. Building generation faster than transmission has this as its mechanical consequence, so there's no scandal here, just arithmetic that worsens with every year the reinforcements slip.

The question worth asking is whether you can stop paying annually for the problem and instead pay once for an asset that absorbs it.

Ofgem published its answer on Friday 26 June. That's Wednesday's post.

Hold that next to Friday, where the same regulator provisionally underwrote 7.65GW of long-duration storage under cap and floor, lithium-ion included, with a consumer-backed floor.

These are not contradictory. They are one signal at higher resolution. The system does not need more storage in the abstract. It needs a particular shape: the right duration, in the right place. Short-duration batteries crowded into already-deep parts of the network have tipped into surplus. Long-duration capacity sited where wind sits stranded behind constraints is scarce enough that Ofgem will pay to guarantee it.

Most of that pumped hydro sits in northern Scotland, exactly where the surplus wind is and the grid cannot yet carry it south. That placement is the whole point.

So the question shifts. Not whether a battery connects, but whether it solves a problem the system is paying to solve, where it is paying to solve it.

Is undifferentiated BESS buildout in Britain quietly drawing to a close?