The Battery Market Is Thriving. Your Project Might Not Be.

That analysis is not wrong. It is just written from the wrong end of the problem.

Financing sophistication does not determine whether a BESS project works. Grid position does. Revenue architecture does. The relationship between the rated storage capacity on the spec sheet and what the network will actually allow you to use — that determines whether the project is viable. Everything else is downstream.

This is the gap we are navigating with almost every commercial project that comes through our door right now.

What we are actually seeing

In the last month, nearly every commercial solar project we have assessed has included a request to co-locate battery storage alongside the solar installation. The appetite is real and it is accelerating. Landowners, developers, and C&I occupiers all want solar and storage at the same time, in the same place. The logic is sound. The execution is where it gets expensive.

The most persistent mistake we encounter is this: a client receives a quote for a commercial-scale BESS — say, 500 kWh or above — and assumes that the rated capacity on that quote is the usable capacity they will have access to, and that the charging rate will be fixed and predictable. Neither assumption holds in practice.

Battery manufacturers quote nameplate capacity. What the network will allow you to import to charge that battery — and at what rate, at what time, and at what cost — is determined by your grid connection, your import capacity, your DNO's local network conditions, and the contract you hold. A 500 kWh battery connected to a site with a constrained import limit is not a 500 kWh battery in commercial terms. It is a partially utilisable asset with a payback period that no one has modelled correctly.

This is not a niche technical problem. It is a commercial miscalculation that is being built into project costings, landowner agreements, and investor cases across the sector right now.

The grid context nobody is talking about clearly enough

The scale of the UK's grid access problem provides the backdrop to all of this.

Factor	What the market assumes	What is actually happening
Grid connection availability for BESS	Open and accessible	153 GW removed from queue; no new standalone BESS connecting before 2035
Rated battery capacity vs usable capacity	They are the same figure	Import limits, network constraints, and DNO conditions determine real usability
Revenue certainty	Improving as market matures	Cannibalism pressure building; ancillary prices compressing as installed capacity grows
Co-located BESS as a workaround	Optional enhancement	Now the primary viable route for most new projects
Planning engagement timeline	Something to address later	A front-loaded requirement that determines everything downstream

As of December 2025, the UK grid connection queue had grown to over 700 GW of generation and storage projects — approximately four times what Britain actually needs to deliver its energy targets. 153 GW of BESS projects were removed or deprioritised through the queue reform process, with no realistic prospect of new standalone transmission-connected BESS securing a connection before 2035. Grid constraint payments are projected to exceed £1.8bn in 2025, up from £1.5bn in 2024. The grid is not a neutral backdrop to these projects. It is the project.

What the revenue picture actually looks like

The financing narrative in the Scotsman piece focuses on what lenders need to get comfortable. But comfort at the lender level does not protect against revenue underperformance at the asset level.

In the US, where the BESS market is further developed, the signal is instructive. In ERCOT, average BESS revenues fell from $182 per kilowatt-year in 2023 to $52 per kilowatt-year in 2024 — a 71% decline in a single year — with battery cannibalism accounting for at least 30% of that drop. As more batteries dispatch during peak windows, they compress the very prices they were built to capture. The top-performing asset in that market still generated double the average return, which tells you that asset position, optimisation capability, and revenue stack architecture matter enormously. The market average is not a reliable planning assumption.

The UK is on the same trajectory. Ancillary services — particularly FFR and DC products — have seen significant price erosion as deployed BESS capacity has grown. Projects that were modelled on 2022 or 2023 revenue assumptions are facing a material gap between projection and delivery. The clients who are best placed are those who built their revenue stack around multiple income streams — capacity market, BM optimisation, behind-the-meter arbitrage, private wire — rather than assuming one dominant revenue source would hold.

What co-location actually solves — and what it does not

The co-located model — solar and BESS on the same site, connected to the same grid interface — has genuine commercial logic. It reduces the grid connection complexity for the storage element, can reduce peak import demand, enables self-consumption optimisation, and in private wire configurations, can deliver material value without touching the public grid at all.

What it does not solve is poor project economics dressed up in a more palatable structure. We have seen co-located proposals where the BESS has been sized against the solar generation profile without accounting for the site's actual demand pattern, the available import capacity, or the export constraints. The battery is there because the client wanted a battery, not because the modelling said it was the right size, in the right place, configured correctly.

The question we ask before anything else is: what problem is this battery actually solving? Is it peak shaving? Self-consumption? Revenue generation? Grid services? The answer determines the sizing, the configuration, the grid connection requirements, and the revenue architecture. It changes the project significantly.

The planning and grid engagement sequencing problem

Our strong advice to any developer or landowner pursuing a co-located BESS project is to engage with both the planning authority and the DNO earlier than feels necessary. Not when you have a scheme ready to submit. Before you have committed to a layout.

Grid strengthening works further up the network — works the DNO is already planning — can materially change your connection costs, your connection timeline, and in some cases, your connection viability. This information is not always visible from a standard connection enquiry. It requires active engagement and technical assessment. Developers who discover this at the point of connection offer acceptance are facing costs and delays that should have been identified twelve months earlier.

The same applies to planning. Battery storage at commercial scale is not a simple permitted development matter in most configurations. The relationship between the planning application and the grid connection application — which comes first, what evidence each requires, how they interact — is a sequencing problem that eats project timelines when it is not managed from the front end.

Where the real opportunity is sitting right now

The clients we want to talk to are landowners and site operators who are looking at an existing grid connection — a pole-mounted transformer at the edge of a field, a substation on their land, an industrial building with a sizeable import capacity — and asking whether that infrastructure can be used more productively.

A field with a redundant connection, a roof with available capacity, a site with demand that creates arbitrage opportunity: these are not abstract investment propositions. They are physical assets with a grid interface already in place, which in the current environment is one of the most valuable things a project can have. A protected or existing grid connection changes the entire feasibility picture. The queue reform process has made existing infrastructure significantly more valuable than it was two years ago.

If you have land or a site with existing grid infrastructure, the question is not whether there is an opportunity. The question is whether the opportunity has been properly assessed.

The map the industry needs

A regional heatmap of the UK showing constraint-heavy zones, areas where DNO capacity is available, and the regional BESS quota position under the connections reform process would reveal something that no national market narrative captures: the opportunity is not evenly distributed. Scotland is heavily constrained and effectively closed for new BESS. Parts of the Midlands and southwest England have available solar capacity in the 2025–2030 queue. The picture is local, and the project economics follow that local reality.

National market growth projections do not tell you whether your specific site, in your specific network zone, with your specific connection, has a viable project. That requires a different kind of analysis.

The commercial question underneath the market story

The Scotsman article is correct that the UK BESS market has strong long-term fundamentals. The financing infrastructure is developing. Lenders are building familiarity with the asset class. The policy direction is clear.

None of that tells you whether your project works.

We are carrying out independent feasibility assessments, grid strategy reviews, and revenue stack modelling for commercial solar and co-located BESS projects across the UK. We use no products, have no vendor relationships, and have no interest in a project proceeding that does not stack up. If you have land, an existing grid connection, or a co-located project in development and you want an independent view on whether the commercial fundamentals are sound — that is the conversation we are here for.

If you are looking at land with existing grid infrastructure and want to understand whether a co-located solar and BESS project is genuinely viable, speak to us before you commit further resource.

Commercial Solar Reality Co-Located BESS

What every developer and landowner needs to know before they commit

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The market is growing. That does not mean your project works.

The UK battery energy storage market is expanding. Investment is moving. Financing structures are maturing. Every headline says so. What the headlines do not say is that 153 GW of BESS projects have just been removed from the UK grid connection queue, that standalone new-build BESS has no realistic transmission connection window before 2035, and that the gap between nameplate battery capacity and commercially usable storage is costing developers real money on projects that were never properly assessed.

This brief is for landowners, developers, and C&I operators who are being asked to make decisions about co-located solar and BESS — and who want a clear-eyed view of what the risks actually are.

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The capacity assumption that breaks project economics

When a developer or installer quotes you a 500 kWh BESS system, they are quoting nameplate capacity. That is the figure on the manufacturer's data sheet. It is not necessarily the figure you will be able to use in practice.

What governs your actual usable capacity is your grid connection — specifically your available import capacity, your DNO's network conditions, any constraints on your connection, and the rate at which you are contractually permitted to draw power from the network to charge the battery. On a constrained site, a 500 kWh battery may function commercially as a 200 kWh battery. The payback period changes. The revenue model changes. The project may no longer stack.

This is the single most common miscalculation we see in commercial BESS proposals right now. It is not a small rounding error. It is a structural flaw in how the project has been assessed.

Before you agree to a battery specification, ask your consultant: what is the usable capacity based on our actual grid connection? If they cannot answer that, the project has not been assessed.

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The grid connection timing problem

The second mistake is sequencing. Developers who engage with the DNO and planning authority late — after layouts are fixed, after landowner heads of terms are signed, after budgets are set — are the ones who absorb cost overruns that should never have existed.

Grid strengthening works further up the network can materially change your connection cost and timeline. These works are often already planned by the DNO and are visible to anyone who asks the right questions at the right time. The developers who discover this at connection offer stage are facing surprises that are no longer manageable within the project budget.

Engage the DNO before you fix your layout. Engage the planning authority before you submit. The sequencing is not a formality — it is where project viability is won or lost.

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The revenue stack reality

Co-located BESS projects are being sold on revenue projections that often rely on a single dominant income stream. In the current UK market, that is an increasingly fragile assumption.

Ancillary service revenues have compressed as more BESS capacity has come online. The assets that are outperforming are those with diversified revenue architectures — capacity market, BM optimisation, behind-the-meter arbitrage, private wire value — rather than those dependent on one market mechanism holding its price.

Revenue modelling needs to be stress-tested across multiple scenarios, not presented as a single number with a single assumption set. If the project only works in the base case, it does not work.

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Where the opportunity genuinely sits

The projects with the strongest current fundamentals are those with an existing grid connection already in place — a site with available import capacity, a field with a transformer, a building with a connection that has not been fully utilised.

In the current queue environment, an existing grid connection is a commercially valuable asset. Projects with protected connection positions or available distribution-level capacity are in a materially different position from those starting from scratch. If you have existing infrastructure on or near your land, that infrastructure needs to be properly assessed — not assumed to be either an automatic advantage or an irrelevant detail.

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The three questions to answer before you proceed

One: What is the usable battery capacity based on the actual grid connection, not the nameplate specification?

Two: What does the revenue stack look like across multiple market scenarios, not just the base case?

Three: What are the DNO's network plans for your area, and how do they affect your connection cost and timeline?

If you cannot answer all three, the project has not been adequately assessed.

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We carry out independent feasibility assessments and grid strategy reviews for co-located solar and BESS projects. We have no vendor relationships and no products to sell. Our only interest is whether the project is commercially sound.

If you have land with existing grid infrastructure, or a co-located project in development, speak to us before you commit further capital.