Solar Strategies — Insights

Due diligence checklist: what to verify before signing any commercial solar contract

John Shaw — Wed, 19 Aug 2026 13:45:00 GMT

Most of the risk in a commercial solar project isn’t in the panels — it’s in the paperwork. A system that performs well for twenty-five years is only as good as two things. First, will the company that installed it still be around in year five, when an inverter fails? Second, does the contract you signed match the terms the installer promised verbally?

None of the checks below take long. You can do all of them yourself, before you sign anything, without paying anyone for the privilege.

This is a working checklist, not a sales pitch for using an adviser. That said, it draws on the same due diligence we run for clients through procurement and tender support. Use it on a single quote, or to compare several.

1. Confirm the installer is who they say they are

“MCS-certified” is the baseline the UK market runs on. The Smart Export Guarantee requires it, and most funders and insurers won’t touch a system that lacks it. But a badge on a website or a van is only a claim, not proof. Verify it directly:

Search the installer on MCS’s own register at mcscertified.com’s Find an Installer tool, by company name or postcode. If they don’t appear, or their status isn’t listed as currently certified, that’s a stop-and-ask moment — not necessarily a dealbreaker (some genuinely competent commercial contractors sit outside MCS at large scale), but you need the explanation before you proceed, not after.
Know where MCS’s technical standard actually stops applying. MCS’s solar PV installation standard, MIS 3002, formally covers installations only up to 50kWp. Most commercial rooftop or ground-mount systems sit well above that. That doesn’t mean accreditation stops mattering — a credible commercial installer should still hold current MCS company certification and be able to point to a track record of systems at your scale — but it does mean the job itself needs specifying, commissioning and warrantying as a bespoke commercial project, not a scaled-up domestic one.
Check any consumer-code membership for what it actually covers. Membership of the Renewable Energy Consumer Code or a similar scheme is a genuine quality signal, but these codes — and the insurance-backed guarantees that come with them — are built around protecting domestic consumers, not businesses buying at commercial scale. If your organisation is contracting as a business rather than an individual consumer, don’t assume that protection extends to you; check the contract itself instead (more on that below).

2. Check the installer’s financial standing

A twenty-five-year performance warranty is a promise from a company, not a law of physics. If that company doesn’t exist in five years, the warranty is only worth whatever’s left in the small print. That print usually names who else can honour it.

Companies House’s free register is the starting point, and it takes minutes:

Filing history and accounts. Are accounts filed on time? Persistently late filing is a genuine early-warning sign trading standards and insolvency practitioners both watch for. For a small company you’ll likely only see abbreviated or micro-entity accounts (limited detail is normal and not itself a red flag), but a pattern of overdue filings, or accounts that have gone quiet altogether, is worth a direct question.
How long the company has actually traded. A company incorporated eighteen months ago badging itself as “20 years’ experience” is either a rebrand, a change of ownership, or worth asking about directly. None of those are automatically disqualifying — but you should know which one it is.
Charges and mortgages. The register shows registered charges against the company (loans secured against its assets). A heavily leveraged installer isn’t necessarily a bad one, but it changes what “the company folds mid-warranty” actually looks like for you as a creditor.

For any contract of real size, a Companies House search is only a first pass, not the whole job. It tells you what’s been filed. It doesn’t tell you whether the company can actually deliver, or stand behind a multi-year warranty.

That’s exactly why larger commercial contracts lean on contractual protection instead of trusting the counterparty to keep existing. One option is a parent company guarantee, where the installer is part of a larger group. Another is a collateral warranty, which lets you step in or claim directly if something goes wrong. On larger EPC-style contracts, a performance bond serves the same purpose.

That said, if a bidder can’t or won’t offer any of these on a six- or seven-figure contract, take note. That refusal is a data point in itself.

3. Read the warranty stack — there are four warranties, not one

Marketers treat “25-year warranty” as a single phrase, but a commercial solar contract actually carries several separate warranties. These come from different parties and run for different lengths of time:

Warranty	Typically covers	Typical length	Who’s actually on the hook
Product warranty	Manufacturing defects in the panels	12–20 years	The panel manufacturer
Performance warranty	Output not degrading faster than the guaranteed curve	25–30 years	The panel manufacturer
Inverter warranty	The inverter itself	5–12 years (often extendable)	The inverter manufacturer
Workmanship warranty	The installation — mounting, wiring, weatherproofing	Commonly 5 years or more	The installer

In practice, the gap most buyers miss is the inverter. Manufacturers typically warranty panels for far longer than the inverter that makes their output usable. Yet the inverter is also the part of a system most likely to need replacing within the warranty period.

Ask specifically what the inverter warranty covers and whether it’s extendable. Find out, too, whether you have to buy the extension at the point of installation, or can add it later.

Ask, too, who actually delivers on each warranty when the installer isn’t the manufacturer. That’s the normal arrangement.

In practice, a workmanship warranty is only as good as the installer’s continued existence (see point 2). Product and performance warranties, by contrast, sit with the manufacturer directly. That’s one reason established panel and inverter brands are worth the modest price premium. Favor ones with a real UK or European presence over an unfamiliar brand.

4. Check for a performance guarantee — a different thing from a performance warranty

A manufacturer’s performance warranty says the panels won’t degrade faster than a stated curve. It says nothing about whether the installed system — panels, inverter, wiring, shading, orientation — will generate the output the proposal promised. That’s what a performance guarantee, written into the contract itself, is for.

On larger commercial and EPC-style contracts, a performance guarantee typically commits the installer to a minimum guaranteed annual output. If the system underperforms against that guarantee, liquidated damages become payable. This is standard practice on genuinely large commercial and utility-scale solar contracts.

UK case law has already tested how these clauses hold up when a contractor fails to deliver. In those cases, the other party calls on the parent-company guarantee.

The equivalent for a smaller commercial rooftop system might be simpler: a written commitment to a first-year yield in kWh. You can then check the actual metered output against that figure.

Either way, watch for this gap. The proposal quotes an expected annual output, but the contract is silent on what happens if the system misses it. Close that gap before you sign.

5. What a fair contract looks like versus what should make you pause

Signal	Fair contract	Red flag
Specification	Detailed — panel model, inverter model, exact capacity, expected annual yield	Vague — “premium panels,” no named equipment
Payment terms	Staged against milestones (design sign-off, delivery, commissioning)	Large deposit upfront, balance not tied to a milestone
Cancellation	Clear terms either way, agreed in writing	No exit clause, or one so one-sided it’s unworkable
Yield claims	A stated methodology (irradiance data, shading analysis, degradation assumed)	A single confident number with no basis shown
Pressure to sign	None — you’re free to take the contract away and read it	”Today only” pricing, urgency to sign on the day
Sub-contracting	Named, disclosed if any part of the work is sub-contracted	Silent on whether the signing company does the actual installation
Financial backstop	Parent company guarantee, collateral warranty or bond on larger contracts	None offered, and the question is deflected rather than answered

None of this replaces reading the actual document. It’s a filter for knowing which pages to read twice.

Where this fits

Running this checklist on one quote is useful. Running it consistently across several competing bids is more powerful still. That only works with a specification precise enough to make the quotes genuinely comparable in the first place. Do both, and due diligence becomes a repeatable process rather than a one-off worry.

We built our procurement and tender support to close exactly that gap. We write the specification, manage the tender, and check every bidder against this list. That list covers accreditation, financial standing, warranty terms and contract structure. That happens before you’re the one signing anything.

If you haven’t yet established whether solar is worth doing at your site at all, that question comes first. It’s what our feasibility studies are for.

Scotland's Section 36 consenting process for solar, explained

John Shaw — Mon, 17 Aug 2026 09:07:00 GMT

Ask a landowner in Kent how solar gets planning permission, and the answer is straightforward. An application goes to the local district or borough council, which decides it under the Town and Country Planning Act 1990. Ask the same question of an estate in Angus or the Borders. The honest answer is “it depends how big the scheme is.”

That’s because above a certain size, Scotland doesn’t use local planning permission for solar at all. Instead, it uses a different Act, a different decision-maker, and a process with no real equivalent south of the border. For any Scottish landowner or estate weighing a ground-mount scheme, knowing which regime applies matters before negotiating a lease term. Knowing what’s currently changing about the rules matters just as much.

The 50MW line: who actually decides

Scotland’s electricity generation consenting sits on two separate legal tracks, split by capacity:

50MW or under — the relevant local planning authority decides these, under the Town and Country Planning (Scotland) Act 1997. Scotland has run its own planning Act, separate from England and Wales’s, since devolution. That detail surprises people who assume “UK planning law” is one system.
Above 50MW — Scottish Ministers decide, under Section 36 of the Electricity Act 1989. The Scottish Government’s Energy Consents Unit (ECU), based in Glasgow, administers the process on their behalf. There is no local-authority decision in the ordinary sense: the local authority is a statutory consultee with a strong voice, not the decision-maker.

That single 50MW figure is the entire fork in the road. Most rooftop and modest farm-diversification schemes never come close to it and sit comfortably in ordinary local planning. But ground-mount solar has grown up fast. A single large array on a well-connected estate can clear 50MW without being an unusual project by today’s market standards.

In fact, Q2 2025 alone saw six Section 36 solar applications between 50 and 99.99MW, and one at 100MW or above. If you’re assembling a scheme of that scale, it’s worth knowing this from the outset. You’re heading into ministerial consenting, not a council planning committee.

Why Section 36 is a genuinely different process

The practical differences go well beyond “who signs the decision.” A handful of features mark Section 36 out as its own regime:

Deemed planning permission. A Section 36 consent doesn’t run alongside a separate planning permission. Instead, Scottish Ministers can direct that the same consent also grants deemed planning permission, under the 1997 Act. There’s one decision, not two.
The local authority is a consultee, not the decision-maker. The council where the scheme sits can submit views and evidence. Historically, an objection from the authority could trigger an automatic public inquiry — a rule the government is reforming in 2026 (see below).
Environmental Impact Assessment is built into the process, not a bolt-on, for any scheme likely to have significant environmental effects. Most schemes at this scale meet that bar.
Community consultation is mandatory before you even apply. Distinctively, Scotland requires this regardless of scheme size, not only for Section 36 projects. A developer has to present proposals to the local community before lodging any application.
Applications go to the ECU directly — via energyconsents.scot, by email, or by post to the Glasgow office — rather than to a planning portal.

None of this is a technicality. It changes the advisers you need, the evidence base you assemble, and the timeline you plan around. It also changes who you’re negotiating with if the scheme runs into local objection.

What the process looks like, stage by stage

Following gov.scot’s good-practice guidance on Section 36 and 37 applications, a Section 36 case broadly runs through:

Pre-application — initial engagement with the ECU, the local authority, and statutory consultees (SEPA, NatureScot and others depending on the site), plus the mandatory community consultation.
Environmental Impact Assessment — screening and, where required, a full Environmental Statement covering landscape, ecology, hydrology and cumulative effects.
Submission — the formal application to the ECU, with supporting technical and environmental documentation.
Processing and consultation — the ECU circulates the application to the local authority and other consultees for comment.
Public Local Inquiry — held where unresolved objections warrant it (the government is also reforming this stage — see below).
Decision — Scottish Ministers decide, including whether to grant deemed planning permission alongside consent.

There’s no fixed statutory clock on the whole journey, unlike a routine local-authority planning application. A scheme with a contested public inquiry can run considerably longer than one that clears consultation cleanly. That’s exactly why early, honest engagement with the local authority and community matters more here than in a standard planning application.

Reform is already under way — and it isn’t finished

Two things are moving at once. A scheme timed for 2026–2027 needs to track both, rather than assume today’s rules are fixed.

The Planning and Infrastructure Act 2025 received Royal Assent on 18 December 2025. It amends the Section 36/37 process itself, and most changes took effect roughly two months after Royal Assent. The headline items, per Brodies’ summary of the reforms:

The judicial-review challenge window for onshore electricity consents shortens from three months to six weeks. That brings it into line with offshore consenting.
A local authority objection no longer automatically triggers a Public Local Inquiry. Instead, a Scottish Government reporter now decides what process is proportionate.
Ministers gain a regulation-making power to set mandatory pre-application requirements (information, screening, fees). The detailed regulations, though, were still pending as this reform bedded in.

Separately, the 50MW threshold itself is under review. On 30 December 2025 the Scottish Government opened a consultation on raising the 50MW threshold. The change would push more onshore schemes — including solar — down into local-authority planning rather than Section 36.

That consultation closed on 27 March 2026. The change is likely to progress through 2026. At the time of writing, no one has confirmed a revised figure, so 50MW remains the operative threshold.

That said, any Scottish scheme sized or timed around the Section 36 line should check the current position. Ask the ECU or a specialist adviser before assuming the historic figure still applies by the time you lodge an application.

How this compares with England and Wales

	England & Wales	Scotland
Governing planning Act	Town and Country Planning Act 1990	Town and Country Planning (Scotland) Act 1997
Large-scale route	Nationally Significant Infrastructure Projects (NSIPs) — above 100MW in England (raised from 50MW by the Infrastructure Planning (Onshore Wind and Solar Generation) Order 2025, in force 31 December 2025)	Section 36, Electricity Act 1989 — above 50MW
Decision-maker (large schemes)	Secretary of State, via the Planning Inspectorate	Scottish Ministers, via the Energy Consents Unit
Local authority’s role (large schemes)	Statutory consultee	Statutory consultee
Deemed planning permission	Not automatic in the same way	Can be directed alongside Section 36 consent
Community consultation	Required for NSIPs	Required for every scheme, regardless of size
Recent/pending threshold changes	Threshold already raised 50MW→100MW (in force 31 December 2025)	50MW threshold under consultation, not yet changed; judicial review and inquiry reforms already enacted

The broad shape sends smaller schemes to local planning and larger ones to a national-level process. That will look familiar to anyone who has taken a scheme through England’s Nationally Significant Infrastructure Projects regime. However, the Act, the department, the deemed-permission mechanics, and the blanket community-consultation rule are genuinely Scottish. Assuming an England-based rule of thumb carries over often leads people to underestimate a Scottish scheme’s timeline.

What this means for a Scottish estate weighing solar

For most farm-building rooftop schemes and smaller diversification projects, none of this changes anything. You’re in ordinary local planning. In fact, Scotland’s separate removal of the rooftop permitted-development size cap for non-domestic buildings has made that route even simpler.

The larger ground-mount schemes are different — Scotland’s landholding pattern of substantial estates makes them more common here than in England. That’s where the Section 36 question needs answering early. The question isn’t “is this viable” in isolation. It’s “which regime will decide it, on what timeline, with which stakeholders at the table.”

That question, alongside grid capacity, Agricultural Land Classification, and land-lease economics, shapes any Scottish ground-mount case. An independent feasibility study needs to establish all of this before anyone signs a lease or issues a tender.

Sources:

Battery storage for commercial solar: is it worth the extra capital?

John Shaw — Fri, 14 Aug 2026 16:24:00 GMT

Battery storage has become the default upsell on a commercial solar quote. It’s bundled in almost automatically, and installers often pitch it with a line about “avoiding peak charges.” However, that reasoning doesn’t hold up as well as it used to.

Sometimes storage is genuinely the right call. Often, on a straight numbers basis, it isn’t. Specifically, the honest answer depends on your export tariff, your load profile, and what your network charges actually look like. It doesn’t depend on whether an installer has a battery in stock.

What a commercial battery actually costs right now

Installed cost is the first thing to get straight. It varies more by system size than most quotes make clear. Fixed costs don’t shrink at the same rate on a small system. The grid connection, controls, fire safety measures, and integration with the existing inverter cost about the same regardless of size. As a result, per-kWh pricing falls sharply as capacity rises:

System size	Typical installed cost
Up to 50kWh	£400–£800 per kWh
~100kWh	£200–£400 per kWh
200–500kWh	£300–£500 per kWh
500kWh+ (containerised)	£140–£240 per kWh

So a modest 100kWh system might land anywhere from £20,000 to £40,000. However, a 500kWh containerised unit, despite holding five times the energy, could come in under £100,000.

Site-specific factors move these figures further. A straightforward indoor installation with spare switchboard capacity is cheap. However, a site needing a new transformer, an external enclosure, or extra fire compartmentation is not.

This capital sits on top of the panels. It therefore needs its own business case, not a free ride on the solar payback.

When storage genuinely earns its keep

Storage tends to pay for itself when one or more of these apply:

Your export rate is weak relative to what you’d otherwise pay for power. Smart Export Guarantee rates vary hugely by supplier. Commonly quoted fixed rates run from around 3p to 15p per kWh, occasionally higher on bundled or conditional tariffs. If your export rate sits well below your import rate, that changes the maths. Storing surplus generation and using it later becomes worth more than selling it back at a low fixed price.
You carry real exposure to peak-time network charges. Most DNOs charge under a red/amber/green DUoS structure. The red band applies during weekday peak hours — commonly 4pm to 7pm. DNOs price it well above the green (off-peak) rate. If your site draws heavily from the grid in that window, discharging stored solar power instead of importing pays off. It’s a genuine, recurring saving.
You have a real resilience requirement. Cold storage, server rooms, security and life-safety systems, and livestock or irrigation infrastructure are the clearest cases. Here, downtime costs far more than the battery’s price. The case for resilience can stand alone, independent of the energy-arbitrage numbers.
Your load profile is mismatched with generation. A site with heavy early-morning or evening demand, paired with a midday generation peak, wastes a meaningful share of its solar output. Storage bridges that gap. Examples include some retail units, schools with after-hours use, and certain shift patterns.

When it’s usually just added cost

Storage is harder to justify when:

Self-consumption is already high. Many warehouses, factories and cold stores have heavy, steady daytime process loads. These sites may already use 70–80% or more of what the panels generate in real time. That leaves simply less surplus to store.
The export tariff is already reasonable. If you’ve secured a decent SEG rate, you’re not wasting exported power at a token price. That weakens the case for storing it instead.
Peak-charge exposure is minor. Smaller sites on lower-voltage connections can carry a much smaller DUoS red-band burden. In that case, there’s less to save by shifting consumption.
There’s no real resilience need. A short interruption to supply is an inconvenience, not a cost. In that case, you’re arguably better off spending the capital elsewhere — on a larger array, efficiency measures, or simply banking it.

A myth worth correcting: “avoiding Triad charges”

Older battery pitches still reference “Triad avoidance.” This means shifting demand away from the three half-hours of highest annual system demand, to cut transmission charges. That strategy is largely obsolete, however.

Under Ofgem’s Targeted Charging Review, most of that residual transmission charge (TNUoS) moved onto fixed, capacity-based charges rather than usage at peak times. Distribution charges followed this shift from 2022; as a result, the old Triad system effectively wound down by 2023.

If a battery quote leans heavily on Triad savings as its main financial case, that’s worth challenging. The real, still-live saving comes from DUoS red-band charges instead. These are a separate, distribution-level mechanism, and they remain genuinely time-of-use.

Running the actual numbers

However, none of the above is a substitute for modelling your own site. Several variables decide whether storage pays back. They include your half-hourly load profile, your actual export rate, your exposure to red-band hours, the battery’s round-trip efficiency, and its warranted life before capacity degrades. These all interact in ways a generic rule of thumb can’t capture.

That’s exactly what our energy and ROI modelling work does. We run the solar-only case and the solar-plus-storage case side by side, on your real consumption data. As a result, you can see whether the extra capital earns its return or whether it’s better banked.

Where the answer is genuinely marginal, a short feasibility study is usually the cheaper option. It helps you find that out before committing to either. Still, we have no battery to sell you, so the recommendation goes whichever way the numbers point — including, sometimes, “not yet.”

Dairy farms and solar: rooftop, ground-mount and grazing income compared

John Shaw — Tue, 11 Aug 2026 10:51:00 GMT

A dairy unit faces one of the more interesting solar decisions in UK agriculture. That’s because it usually has three separate options on the same holding.

First, a parlour and shed roof could carry a self-supply array. Second, spare land could host a ground-mounted system. Third, a developer may already have been in touch. If so, there may be an offer to lease that land outright for someone else’s scheme.

Very few farm types have all three options live at once. The right answer depends less on which option is “best” in the abstract. In particular, three things matter more. They are the herd’s own electricity draw, the condition of the buildings, and what the local grid will actually allow.

This piece works through that comparison for a working dairy operation. It builds on the wider picture in our South West England region guide. There, dairy and livestock farming is the dominant land use. That’s in contrast to the flat arable blocks that suit the biggest ground-mount schemes.

The parlour and shed load profile isn’t a simple daytime match

The general pitch for commercial solar is “generate when you use it,” and dairy farming only partly fits that pattern. Milking typically happens in two rounds a day, commonly early morning and mid-to-late afternoon. That schedule straddles daylight hours rather than sitting neatly inside the solar generation window.

AHDB’s guidance on dairy electricity use identifies the most energy-intensive processes on a typical unit. They are milk cooling, water heating and vacuum pumping. It’s worth separating those by how well they line up with solar output:

Bulk tank refrigeration runs continuously, day and night, to keep milk at temperature between collections. This load matches solar generation best. It draws power right through the middle of the day, regardless of what else is happening in the parlour.
Vacuum pumps and milk pumping run in short, heavy bursts during each milking round. That’s a good match if a round falls inside daylight hours, and a poor one if it doesn’t.
Water heating for plant washdown is a large, somewhat schedulable load. It’s one of the easier loads to shift toward the middle of the day if you’re trying to raise self-consumption.

The practical upshot: self-consumption tends to be strong but rarely total. A well-sized array covers the refrigeration load and a good share of daytime washdown almost automatically. However, an early or late milking round still draws from the grid unless it’s paired with battery storage.

That’s why modelling matters. A proper feasibility study models that split against the farm’s actual half-hourly consumption, not a generic livestock-sector average.

Is the barn roof actually ready?

Cubicle sheds, dutch barns and grain stores often look like an obvious solar canvas. They’re usually large, south-facing or close to it, and rarely shaded on an open farmstead. Two things are worth checking before that assumption turns into a spec:

Roof material and age. A meaningful share of older UK farm buildings have asbestos cement roofs. This is especially true for those put up between the 1960s and the 1980s. That material falls under the site’s ongoing duty to manage asbestos-containing materials under the Control of Asbestos Regulations 2012.

In practice, most installers won’t fix panel mounts directly into it. In particular, the routine solution is a combined re-roof-and-solar project. A competent contractor handles the existing sheeting under the regulations, and then new sheeting and panels go up together.

That’s not a reason to rule a shed out. It is a reason to survey the roof before costing the array, since a shed that needs re-roofing anyway changes the combined project’s economics.
Structural capacity and system scale. MCS’s small-scale standard, MIS 3002, tops out at 50kWp. Installers must specify, install and commission anything larger outside that standard. That means a genuine structural assessment of purlins, trusses and existing roof loading — not a generic per-panel assumption.

Get both right, and a shed roof is usually the cheapest, least disruptive place to start. Get either wrong, however, and it becomes the single most common reason a promising-looking roof turns out not to be viable.

Rooftop, ground-mount and grazed land-lease, compared

	Rooftop self-supply	Ground-mount, self-supply/export	Land-lease to a developer	Agrivoltaic grazing
Who pays for the kit	The farm	The farm	The developer	Usually the developer
Capital outlay for the farm	Moderate — sized to shed roof	Higher — new mounting, cabling, fencing	None	None (farm typically leases the land)
Income mechanism	Saved electricity cost + SEG export	Saved electricity cost + SEG export	Fixed, index-linked rent	Fixed, index-linked rent
Effect on farmed land	None — roof only	Takes land out of grazing/cropping	Takes land out of farm’s own use	Land stays in grazing use, typically for sheep or youngstock rather than the milking herd
Grid dependency	Lower — sized to farm’s own demand	Higher — export capacity matters	Developer’s problem to solve	Developer’s problem to solve
Tax/ownership position	Farm owns the asset, claims capital allowances	Farm owns the asset, claims capital allowances	No asset owned; rental income; land may lose Agricultural Property Relief eligibility	Same as land-lease — ownership sits with the developer

The rooftop and ground-mount self-supply routes keep the upside — and the risk — with the farm business. Sized right, they cut the electricity bill on load the farm was always going to draw anyway.

The land-lease and grazed routes work differently. They hand the capital risk to a developer in exchange for a fixed, largely passive rent. That rent comes at a cost, however — the land’s own productive use, and often its inheritance-tax treatment.

Why grazing income usually means the flock, not the herd

Sheep grazing beneath and between panel rows is now well established on UK ground-mount sites. Sheep don’t climb or lean on the structures the way cattle can, and their grazing height suits standard panel clearances. Some schemes are trialling cattle grazing under panels, while fencing, panel height and ground-pressure requirements are more demanding.

As a result, it’s rarely the lactating milking herd that ends up on a grazed solar site in practice. A herd on a twice-daily parlour rotation needs to move reliably and often, in all weather. That doesn’t sit alongside a fixed array layout.

Where dairy farms do take a land-lease or agrivoltaic route, the grazing that continues is rarely the milking herd itself. In particular, it’s far more commonly youngstock, dry cows or a sheep flock run alongside the dairy enterprise.

That distinction matters for the business case. If the milking herd needs that land for its own grazing rotation, a land-lease becomes a genuine trade-off. It works against the farm’s own stocking capacity, not as a free income stream layered on top of it.

The grid and the land question sit together

None of this happens without headroom on the local network. Any array above the smallest domestic scale connects under Engineering Recommendation G99. That means an enquiry to the local Distribution Network Operator, then a formal application. For larger systems, a technical assessment follows before the DNO issues a connection offer.

Parts of the South West saw an earlier wave of wind and solar connections. That has used up much of the local headroom there, so some substations now carry only limited spare export capacity. As a result, it’s worth checking headroom for the specific site before a roof spec or a lease negotiation goes much further.

If a developer’s land-lease offer is also on the table, read it alongside the self-supply numbers rather than in isolation. Additionally, our land lease vs on-site solar guide sets out that trade-off in full.

It includes the point most offer letters don’t mention. Specifically, land let for solar generally stops qualifying as agricultural property for inheritance-tax relief purposes. Our glossary also covers terms like ALC grade, G99 and agrivoltaics in plain English.

Getting the sequence right

For a working dairy operation, the sensible order is usually this: check the roof first (material, structural capacity, orientation). Next, model the parlour and shed load against a real self-supply array. Then weigh any land-lease or grazing offer against what that land is actually worth to the herd’s own grazing plan.

Reversing that order causes problems. Signing a lease before costing the roof is one common mistake. So is costing the roof before checking what the grid allows.

That’s how farms end up with a decision that looks good on paper. It doesn’t hold up once all three options are compared properly. Our feasibility studies service exists to run exactly that comparison before any capital or land commitment.

Ground-mount vs rooftop solar: how to decide for a commercial site

John Shaw — Sat, 08 Aug 2026 14:08:00 GMT

Most commercial solar conversations start with the roof, because that’s usually where the panels end up. But “put it on the roof” is a default, not a decision. On a meaningful share of the sites we assess, it turns out to be the wrong one.

Roof condition, available land and planning policy can all point somewhere else. So can straightforward cost. Getting the choice wrong is expensive to unwind once a specification has gone to tender.

This is the framework we use to decide between rooftop, ground-mount and a car-park canopy. It’s the middle option most people forget.

When roof condition rules rooftop out

A modern solar array adds roughly 18–25 kg per square metre of permanent dead load to a roof. That load is modest next to the wind and snow loads the original design allowed for. But it’s not negligible on a building carrying decades of wear. The questions that actually decide viability are:

Structural capacity. Look at purlin and truss condition, corrosion, and how much of the original design’s load margin is still available. That’s not the capacity shown on the drawings from when the building went up.
Roof age and remaining life. Suppose a membrane or sheet covering is due for replacement within five to ten years. That timeline changes the economics of fitting an array now. A combined re-roof-and-solar project is often the better call than solar now, re-roof later.
Covering type. Older industrial roofs sometimes used asbestos cement sheeting, which restricts direct fixing under the Control of Asbestos Regulations 2012. That usually forces a re-roof or overlay before panels can go on at all.
Usable, unshaded area. Rooflights, plant, HVAC ductwork and party-wall shading can all eat into a roof’s real capacity well before its edges do.

Any one of these can turn a roof that looks promising from the ground into a poor candidate. Or it can mean solar only makes sense bundled with re-roofing works. That’s exactly why a structural survey is the first thing we do on a feasibility study. It’s not an afterthought bolted on once someone has already assumed a system size.

When land availability makes ground-mount the better fit

Ground-mount earns its place in two situations. In the first, the roof genuinely can’t take the load a business wants. In the second, a site simply has spare land that would otherwise sit idle. That could be a former yard, an unused paddock, or a buffer strip around an industrial estate.

Ground-mount also has a real technical advantage over most existing roofs. You choose the tilt and orientation from scratch. You’re not stuck with whatever pitch and aspect the building happens to have. That freedom can lift yield per kWp installed.

The catch is planning. Ground-mounted arrays above a fairly modest scale need full planning permission from the local authority. One factor surprises people who assume this is only relevant to farmland.

Agricultural Land Classification (ALC) grade matters even when the site sits next to an industrial estate or business park. ALC grades undeveloped land 1 to 5 by its soil and climate quality. That grading applies regardless of who owns the land or what’s built next door.

ALC grades a paddock or field beside a warehouse on the same basis as one in open countryside. National planning guidance treats Grades 1, 2 and 3a as “best and most versatile” (BMV) land. Planning policy then steers ground-mount solar away from BMV land and towards Grade 3b and below.

If nobody has ALC-surveyed the spare land attached to your site, get that done early. Do it before a lease, a specification or a planning application, not after.

Two other checks belong in the same early pass:

Grid connection. Ground-mount schemes above the smallest domestic scale connect under Engineering Recommendation G99. That’s the same DNO application process that applies to rooftop systems of similar size. Land doesn’t exempt you from it.
Whether developing it yourself is even the best use of the asset. The land might be BMV-graded, awkwardly shaped, or better suited to a third party’s scale of development. In that case, leasing it to a solar developer can outperform building your own array on it. That lease often comes with an index-linked rent. See our land lease vs on-site solar guide for how that comparison works in practice.

The car-park canopy: the option most people skip

Between “roof” and “field” sits an option that fits a specific gap well. It’s a solar canopy over an existing staff or HGV car park. It doesn’t depend on roof condition at all — it’s a new-build steel structure.

And it doesn’t need spare land beyond what’s already tarmacked over for parking. It also pairs naturally with EV charging, turning generation and weather-protected parking into one project rather than two.

Factor	Rooftop	Ground-mount	Car-park canopy
Typical installed cost	Baseline (roughly £700–£1,100/kWp at commercial scale)	Roughly 10–20% above rooftop — commonly £1,000–£2,500/kWp more in absolute terms, for foundations and land works	Roughly £950–£1,300/kWp, reflecting the canopy structure
Main constraint	Roof structure, age and covering	Planning, ALC grade, grid connection	Existing car park area and layout
Planning position	Usually permitted development or a straightforward consent	Full planning permission almost always required; ALC/BMV policy applies	Usually no full planning permission needed — since December 2023, Class OA permits car-park canopies via prior approval instead, subject to a 4m height limit and siting/design/glare checks
Best used when	Roof structure and area both check out	Roof is constrained and suitable land is available and lower-grade	Roof is constrained, land is limited, or EV charging is also wanted

That £1,000–£2,500/kWp premium for ground-mount over an equivalent rooftop system reflects real costs a roof install doesn’t have. These are foundations, cabling runs and land preparation. That premium isn’t a reason to rule ground-mount out where the land is right.

It is, however, a number worth modelling properly rather than assuming it. Pair it with the capex and payback figures for your system size. A canopy’s higher per-kWp cost buys something a roof array can’t offer. You get a structure independent of an ageing roof, and often a mounting point for EV charge points.

Getting the sequence right

None of these three options is inherently “better.” The right one depends on your specific site. That means roof condition, spare land and its ALC grade, and the grid position each option would connect through. The mistake that costs money is picking one before those facts are in, rather than after.

A proper feasibility study runs the structural survey, the land and planning check, and the grid enquiry in parallel. It then produces an honest recommendation. That recommendation covers which of rooftop, ground-mount or canopy — or some combination — actually fits your site. That happens before you commit any capital or specification work.

Sources: GOV.UK / Natural England — Guide to assessing development proposals on agricultural land (ALC grades & BMV); Energy Networks Association — G99 connection guide; HSE — Control of Asbestos Regulations 2012; The Town and Country Planning (General Permitted Development etc.) (Amendment) (England) Order 2023 (SI 2023/1279), Article 8 — insertion of Class OA.

Solar procurement under the Procurement Act 2023: a guide for public-sector buyers

John Shaw — Tue, 04 Aug 2026 09:33:00 GMT

Are you a procurement lead, estates manager or finance officer at a council, school, university or NHS trust? Buying solar is more than an engineering decision. It’s a regulated procurement. Get the process wrong, and it can cost you as much as getting the technical spec wrong.

Since 24 February 2025, a new statute has governed that process: the Procurement Act 2023. It replaced the Public Contracts Regulations 2015 (PCR 2015) as the legal framework contracting authorities must follow. This guide explains what actually changed. It also covers the two realistic routes to market for a solar project. And it sets out the value-for-money and audit obligations that come with each.

What the Procurement Act 2023 changed

The Act had a bumpy road to commencement. It was originally due to go live on 28 October 2024. However, the government pushed it back four months to redraft the National Procurement Policy Statement that sits alongside it.

The Act finally came into force on 24 February 2025, with transitional “saving provisions” attached. Any procurement already started under the old PCR 2015 rules finishes under those rules, rather than switching regime mid-tender. Anything you start today falls under the Act, not the old regulations.

For a public body buying solar, the practical changes that matter most are:

Two procedures instead of many. PCR 2015 offered a menu of competitive procedures: open, restricted, competitive with negotiation, and competitive dialogue. The Act collapses this to just two — the Open Procedure (a single-stage competition, no negotiation) and the Competitive Flexible Procedure. The Competitive Flexible Procedure gives you far more freedom to design your own process. You can build in a shortlisting stage, dialogue with bidders, or a technical-clarification round. Just set out the design upfront and follow it consistently, whatever you choose.
A single digital front door. All regulated notices now go through the Central Digital Platform. That includes pipeline notices, tender notices, contract award notices, contract change notices and more. It’s the enhanced Find a Tender Service that went live alongside the Act. Suppliers register once and reuse their core details across bids. Contracting authorities can’t award a contract to a supplier who isn’t registered.
A shorter, better-defined standstill period. Before you can sign a contract, unsuccessful bidders must receive an assessment summary — their debrief. You must also publish the contract award notice. You can then only sign the contract after an 8-working-day standstill period has run. That gives bidders a window to challenge the decision before it becomes binding.
Mandatory KPIs on larger contracts. For any public contract worth more than £5 million, the contracting authority must set at least three KPIs. It must publish them. Then it must report supplier performance against those KPIs. That reporting runs at least once every 12 months, for the life of the contract. This transparency requirement didn’t exist under PCR 2015.

Two realistic routes to market

Most public bodies procuring solar choose between running their own compliant tender or buying through an existing framework agreement. Neither is automatically “better.” The right choice depends on project size, in-house procurement capacity, and how quickly you need to move.

	Run your own tender	Buy via a framework (e.g. RM6314)
Route	Open Procedure or Competitive Flexible Procedure, run and published by your own organisation	Direct award or mini-competition under an existing multi-supplier framework
Speed	Slower — full notice, tender, evaluation and standstill cycle	Faster — competition already run once by the framework owner
Control over spec	Full control; you write the technical specification from scratch	Constrained to the lots and supplier pool the framework already defines
Compliance burden	You own every notice, debrief and standstill obligation	Framework provider has already run OJEU/FTS-compliant procurement; your call-off still needs its own audit trail
Best fit	Large, complex or unusual sites; portfolio-wide standardisation; where you want bespoke evaluation criteria	Single-site or straightforward projects; smaller teams without deep procurement resource

Route one: running a compliant tender yourself

Below a set financial threshold, a contract sits outside the Act’s full “covered procurement” rules and carries lighter obligations. However, the thresholds aren’t fixed. The government revises them every two years. That keeps pace with currency movements and the UK’s commitments under the WTO Government Procurement Agreement.

As of the most recent update (effective 1 January 2026), the goods-and-services threshold is £135,018 for central government departments. For the wider public sector — councils, NHS bodies, schools and universities among them — it’s £207,720. The works threshold is £5,193,000.

A single-site rooftop solar installation is very unlikely to clear the works threshold. That said, a multi-site portfolio procurement can clear it more easily than people expect. So can a design-and-build works contract that bundles structural reinforcement with the installation.

Clearing the threshold changes the procedure and notice obligations that apply. So always check the current figures on GOV.UK’s threshold guidance before scoping a tender — they move.

Above threshold, the sequence looks like this:

Pipeline and planned procurement notices (where applicable) signal the opportunity to the market early.
Tender notice, published via the Central Digital Platform, with the specification and evaluation criteria.
Evaluation, scored against the weighted criteria in the tender documents — price, technical quality, warranty terms, delivery programme and more.
Assessment summaries issued to all bidders, debriefing them on their own score and, in outline, the winning bid’s.
Contract award notice published, starting the 8-working-day standstill period.
Contract signature, once standstill has run and nobody has lodged a challenge.

Our procurement and tender support service covers this whole sequence for solar specifically. It writes an output-based specification bidders can price against consistently. It also manages the tender and bidder queries, and runs a structured, weighted evaluation. As a result, the process stays defensible if it’s ever challenged or audited.

Route two: buying through the Crown Commercial Service’s RM6314 framework

For many public bodies, the faster and lower-risk route is an existing framework. Someone else has already run the competition among suppliers once, compliantly. The relevant framework for solar is the Crown Commercial Service’s Demand Management & Renewables Agreement (RM6314).

The Crown Commercial Service awarded it in May 2023. It was one of two replacements for the previous Heat Network and Electricity Generation Assets (HELGA) arrangement. The framework spans several lots.

It gives public bodies access to suppliers for solar PV design, feasibility, installation and maintenance. That’s alongside heat pumps, battery storage and wider decarbonisation services. Solar PV projects under the framework run up to roughly £1 million in scope.

Calling off a framework doesn’t remove your compliance obligations entirely. You still need to run whatever call-off or mini-competition process the framework’s rules require. You also still need an auditable record of why you selected that supplier.

That said, the underlying market competition, supplier vetting and core terms are already in place. This is usually significantly faster than an open-market tender for a single, relatively standard site.

Value for money and audit — what you actually have to evidence

Public bodies don’t just have to buy compliantly. They also have to show, after the fact, that the process delivered value for money. Three things matter most in practice:

A documented evaluation trail. Weighted scoring against stated criteria, kept on file, turns “we chose the cheapest-looking bid” into a defensible decision. That matters if an unsuccessful bidder challenges the outcome, or if internal audit or the National Audit Office queries it.
A realistic cost benchmark to test bids against. UK commercial rooftop solar typically installs for somewhere in the region of £700–£1,200 per kWp before VAT. Larger systems benefit from economies of scale. Our commercial solar cost guides break this down by system size. If a bid sits well outside that range, in either direction, ask why before award, not after.
KPI reporting where it applies. Any solar contract that clears the £5 million works threshold now carries a statutory obligation. It must set, publish and annually report against at least three KPIs. Build that reporting cost and process into the contract management plan from day one. Don’t leave it as an afterthought once the system is already generating.

None of this is unique to solar. However, solar procurements have a specific failure mode worth naming. Installer quotes vary so much in what they actually include — panel count, inverter brand, warranty length, yield assumptions.

If a public body doesn’t write a tight, output-based specification, it ends up comparing bids that aren’t really comparable. That’s exactly the kind of process weakness an audit will find.

Where this fits

Whichever route you take — an open-market tender or a framework call-off — one thing protects you from challenge and audit criticism. You need a specification precise enough that bids are genuinely comparable. You also need an evaluation record that shows why the winning bid represented value for money.

That’s the gap our procurement and tender support service closes for public-sector solar buyers specifically. We hold no supplier relationships or product lines. So we build the specification and evaluation purely in your interest. The audit trail is already in the right shape if anyone asks.

Sources: Procurement Act 2023 (legislation.gov.uk) · GOV.UK — Central Digital Platform / Find a Tender guidance · Cabinet Office PPN 023 — 2026 threshold amounts · Crown Commercial Service — RM6314 Demand Management & Renewables Agreement

What happened to the Feed-in Tariff, and what replaced it?

John Shaw — Fri, 31 Jul 2026 11:15:00 GMT

Ask around a boardroom or an estates team, and you’ll still hear people talk about “the feed-in tariff.” They talk as if a new solar installation could sign up for it today. It can’t — that scheme hasn’t accepted new entrants for some years.

The scheme that made 2010s solar economics so straightforward closed a while ago. What replaced it, however, works on genuinely different terms. Those terms are worth understanding properly before you build export revenue into a business case.

What the Feed-in Tariff actually paid for

The Feed-in Tariff (FIT) launched in April 2010. It paid small-scale renewable generators — solar PV among them — in two separate parts. A generation tariff paid a set rate for every kWh generated. This applied whether you used the power on site or not.

An export tariff paid a further, smaller rate for the portion exported to the grid. Suppliers metered this directly on larger sites. For smaller installations without an export meter, though, they deemed it at a flat 50% of generation. Together, these two payments made early commercial solar paybacks look so good.

You earned money simply for generating power. On top of that, you also avoided the electricity costs of using that power yourself.

Why it closed, and what that actually meant

The FIT scheme closed to new applications from 1 April 2019, under the Feed-in Tariffs (Closure, etc.) Order 2018. A narrow grace period allowed exceptions for installations already in progress. That closure, however, applied only to new accreditations — it changed nothing for systems already accredited under FIT. Those installations keep receiving their generation and export payments for the rest of their eligibility period.

That period normally runs 20 years (25 years for systems accredited before 1 August 2012). The tariffs rise each year in line with inflation. If your organisation has an existing FIT-accredited array, that income continues on its original terms. The closure doesn’t touch it retroactively.

What closed was the option for any new solar installation to earn a generation payment at all. That’s the detail that trips people up. The scheme that replaced FIT didn’t replace the generation tariff at all. Instead, it replaced only the export element, and on a fundamentally different basis.

What replaced it: the Smart Export Guarantee

The Smart Export Guarantee (SEG) launched on 1 January 2020. Under SEG, licensed electricity suppliers with a large enough customer base must offer eligible generators a tariff. This pays for the electricity they export to the grid — but there’s no generation payment at all. Your chosen supplier pays you only for what you send back to the network, at whatever rate they’re offering.

The practical mechanics, per Ofgem’s SEG guidance:

	Detail
Eligible technologies	Solar PV, wind, hydro and anaerobic digestion up to 5MW total installed capacity; micro-CHP up to 50kW
Who must offer a tariff	Suppliers with 150,000+ domestic customers (“mandatory SEG licensees”) must offer a SEG tariff and cannot opt out; smaller suppliers may participate voluntarily
Tariff floor	Every SEG tariff must be set above zero — Ofgem sets no other minimum, so rates vary widely between suppliers
Metering	Payment is based on metered export readings — the installation needs a meter capable of recording exports, with half-hourly export data increasingly the norm
How you apply	Directly to your chosen SEG licensee — you don’t have to buy your electricity from the same supplier you export to

This is quite different in character from FIT. FIT rates were government-set and identical regardless of supplier. SEG rates, by contrast, are entirely commercial. Each licensee sets its own tariff, structure and contract terms, provided the rate clears zero.

How SEG actually works for a commercial exporter

For a commercial site, most of the mechanics above are straightforward. Sites already on a metered supply usually have, or can readily get, the export-capable, half-hourly metering SEG payments rely on. Your installer’s MCS certification is the standard baseline most SEG licensees expect for the installation itself. You’ll already need that certification for insurance and funder purposes anyway, regardless of SEG.

The part that actually needs deciding is which licensee to export to, and on what terms. That choice is entirely commercial — unlike the fixed rate FIT once guaranteed.

A few things specific to commercial exporters are worth flagging:

You are not tied to your import supplier. A generator can export to one supplier’s SEG tariff while buying its electricity from a completely different one — so a strong import contract elsewhere doesn’t rule out shopping around on export.
Self-consumption still usually beats export. SEG rates sit well below what most commercial tariffs charge to import electricity, so a system sized and used to maximise on-site self-consumption will typically deliver a better return than one sized to maximise export volume.
Some tariffs bundle import and export. A handful of suppliers offer a premium SEG rate only if you also buy your import electricity from them — worth weighing against a standalone export deal with a different supplier, on the combined economics rather than the headline export rate alone.
Contract terms vary by supplier, not by regulation — length, whether the rate is fixed or tracks a wholesale/market index, and notice periods to switch are all set by the individual licensee, not Ofgem.

How to compare SEG tariffs properly

Ofgem sets no fixed rate and no standard contract structure. As a result, comparing SEG tariffs is closer to comparing business energy contracts than to checking a published government rate. Before signing anything, it’s worth working through:

Fixed versus variable. A fixed rate is predictable for modelling; a variable or index-linked rate can outperform it if wholesale prices rise, but adds uncertainty to a payback calculation.
Contract length and exit terms. Some tariffs run rolling monthly, others lock in for a year or more — check the notice period before you’re free to move if a better rate appears elsewhere.
Whether it’s tied to your import supply. Work out the combined cost of import plus export under a bundled deal against the best standalone export tariff you can get elsewhere; the headline export rate alone can mislead.
Metering requirements and who pays for them. Confirm the supplier’s metering requirement and whether your existing meter already qualifies, or whether an upgrade is needed and who covers that cost.
Whether the supplier is a mandatory or voluntary licensee. Ofgem publishes the current list of SEG licensees; mandatory suppliers are guaranteed to offer a tariff, but that doesn’t mean their rate is the most competitive one on the list.

Rates move with the market, and suppliers add or change tariffs regularly. Because of that, check the current Ofgem list of SEG licensees at the point you’re ready to sign. Don’t rely on a rate quoted in an article that may be months old by the time you read it.

Where this fits

Export revenue is one input into a much larger set of numbers — self-consumption, tariff avoidance, capex and payback. It’s easy to either overstate its contribution, or leave it out of a model altogether. Are you weighing a new commercial installation? If so, you’ll want the export assumption tested properly against your own consumption profile, not a generic estimate.

That’s exactly the kind of detail our energy and ROI modelling service is built to get right. For the wider terminology — G99, DNOs, capital allowances and more — our glossary has plain-English definitions. It covers the terms that come up alongside SEG in most commercial solar conversations.

Agrivoltaics in the UK: grazing and cropping alongside solar

John Shaw — Mon, 27 Jul 2026 16:42:00 GMT

“Agrivoltaics” sounds like a lab experiment. In practice, on UK farms, it’s usually something familiar: sheep grazing between rows of solar panels. From a hedge line away, the farm looks much as it always has.

The idea is simple: combine solar generation with continued food production on the same land, rather than choosing one or the other. In just a couple of years, this has moved from a niche pilot to a recognised part of national solar policy. It’s now one of the most useful tools a farm or landowner has when weighing up a ground-mount solar scheme.

This piece explains how agrivoltaics works physically. It also covers why it matters for planning, and what to check before committing land to it.

What agrivoltaics actually means

At its simplest, agrivoltaics is any arrangement that keeps land in agricultural use — grazing or cropping — while solar panels also generate power on it. Rather than choosing one use or the other, the land does both jobs at once.

In the UK, this overwhelmingly means one of two models. The first is livestock grazing beneath and between conventional or elevated panel rows. The second is arable cropping in wider rows, with the panels mounted high enough, and spaced far enough apart, to let machinery and enough light through.

A smaller but growing third category uses tracking or vertical bifacial panels designed specifically to share light with a growing crop. These remain far less common on UK farms than the grazing model, however.

Solar grazing means running sheep to manage vegetation on and around an array, instead of mowing it. It’s by some distance the most established and most widely deployed form of agrivoltaics in the UK. In fact, most existing UK solar farms already use some form of it — even where nobody involved calls it “agrivoltaics.”

How it works physically: grazing versus cropping

The two models need genuinely different engineering. It’s worth understanding this before assuming a site can simply do either one.

	Grazing (sheep)	Arable cropping
Typical panel clearance	0.8–1.2 m below the panel’s lower edge on a standard ground-mount frame	2.5–4 m above ground, on elevated steel posts, to let machinery pass beneath
Row spacing	Standard commercial spacing; sheep move freely between and under rows	Wider inter-row spacing, sized to the farm’s own combine, sprayer or drill width
Structure	Conventional fixed-tilt or single-axis tracker frames	Taller, more expensive elevated frames, or vertical bifacial panels between crop strips
Livestock/crop choice	Hardy, low-stature breeds — Welsh Mules, Romneys, Shetlands and Suffolk crosses are common, chosen so animals don’t rub cabling or damage frames	Shade-tolerant crops perform best; UK and international trial work has found maize, Swiss chard and beans among the crops that tolerate the partial shading well, and reduced evaporation under panels can improve water efficiency
Site management	Grazing replaces mechanical mowing — a genuine maintenance saving for the solar operator, not just a farming add-on	Requires the array’s row layout and mounting height to be designed around the crop and machinery from the outset, not retrofitted

The grazing model is cheaper and simpler. That’s because it uses standard ground-mount hardware — the panels don’t need to sit any higher than a conventional array already does. The cropping model asks more of the design: taller posts, wider rows, and a layout planned around specific machinery. All of this costs more to build. It also reduces panel density — and therefore generation — per hectare, compared with a solar-only scheme.

That trade-off means giving up some generating capacity in exchange for keeping the land in full arable production. A feasibility study needs to work through this calculation before a landowner commits, because the right answer depends on the land’s grade, its existing use, and what a developer is actually prepared to build.

The planning case: answering the BMV objection

This is where agrivoltaics earns its place in the conversation, not just as an environmental nicety. National planning policy steers ground-mounted solar away from Grade 1, 2 and 3a farmland. This land is officially termed “Best and Most Versatile” (BMV) land, and policy instead favours Grade 3b and below. The reasoning is straightforward: the country’s best food-producing land shouldn’t be permanently taken out of production. As a result, a solar-only scheme on strong farmland is one of the more common grounds for planning refusal or objection.

A well-evidenced agrivoltaic scheme answers that objection directly. The land demonstrably stays in agricultural use, rather than being lost to it — and that’s no longer a fringe argument. In particular, the UK government’s Solar Roadmap, published in June 2025 explicitly recognises dual-use and agrivoltaic solar as part of the route to the government’s 45–47 GW solar target for 2030.

Separate University of Sheffield research published in February 2025 went further. It concluded that the UK has enough agrivoltaic potential to meet its 2030 solar ambitions several times over, without permanently sacrificing farmland. The researchers named Cambridgeshire, Essex and the wider East and South East of England as particularly well suited, thanks to their flat land, existing arable base, grid connectivity and solar resource.

None of that guarantees consent on any specific site. The underlying Agricultural Land Classification (ALC) grade still matters. A credible agrivoltaic scheme also has to be genuinely evidenced — a real grazing or cropping plan, not a token gesture. Still, on land that struggles against the BMV policy test, agrivoltaics is one of the few design choices that can change the planning odds.

A UK example: Bracks Solar Farm, Cambridgeshire

The Bracks solar farm in East Cambridgeshire is a useful real-world reference point, rather than a hypothetical one. The 30.1MW site has allowed local farmers to graze sheep on the land since 2024, alongside hedgerow planting and nest-box provision for birds and bats. It sits on exactly the kind of large, flat East Anglian arable land that the Sheffield research flags as well suited to agrivoltaics. As a working example, it shows that a large ground-mount scheme and continued farming can go together.

Practical considerations for a landowner

Before treating agrivoltaics as the answer to a difficult planning position, it’s worth working through a few questions. These determine whether it will actually work on your land:

Who manages the livestock or crop, and under what agreement? Options include a developer-run grazing licence with a local grazier, a direct arrangement with the landowner’s own flock, or a share-farming arrangement for cropping. Each option carries different income, liability and management implications.
Does the frame height and spacing suit your actual equipment or stock? A cropping scheme designed around someone else’s machinery width is no use if it doesn’t match what you run.
What happens to Basic Payment Scheme successor payments or Sustainable Farming Incentive (SFI) eligibility on the leased area? Agri-environment scheme rules and eligibility criteria change fairly often, so check this against the current scheme rules for the specific land. Don’t assume it from an older scheme’s terms.
How is the land classified, and has that been surveyed recently? An ALC survey done years ago, or an assumption based on soil type alone, isn’t a substitute for a current assessment. This matters especially where BMV status is contested.
What’s the decommissioning and reinstatement position? As with any ground-mount lease, the agreement should specify who returns the land to full agricultural condition, and when, at the end of the term.
Does the income and structure fit alongside — or instead of — a land lease? Agrivoltaics is one design choice within a wider land-use decision, not a separate product.

Where this sits in the wider land decision

Agrivoltaics answers a planning question — it isn’t, on its own, a financial one. Whether continued grazing or cropping alongside a solar array is the right structure for your land still depends on the same fundamentals as any other scheme. These include the site’s grid connection, its ALC grade, the lease or licence terms on offer, and how the income compares with farming the land conventionally or leasing it outright.

If you’re weighing an agrivoltaic proposal against a straightforward land lease or self-supply, our land lease versus on-site solar guide sets out that broader comparison in detail. And where a feasibility study is the right next step for a specific site, that’s exactly the assessment our agriculture and land advisory work is built around.

SECR and ESG reporting: how solar evidence actually fits in

John Shaw — Wed, 22 Jul 2026 08:27:00 GMT

A finance director signs off a solar installation. The panels go up. Six months later, someone in sustainability gets asked to “just add the solar numbers” to the SECR disclosure.

That request is where many otherwise sound projects come unstuck. The panels work fine. The real problem is planning. Nobody decided, up front, what evidence the generation needed to produce — or which report it needed to support.

This isn’t a compliance technicality. SECR is a binding legal requirement with a specific format. Above it sit the ESG frameworks that investors, lenders and increasingly regulators actually read.

Getting the evidence right matters. It’s the difference between a line item that survives audit and one that gets quietly removed the year someone asks a hard question about it.

What SECR actually requires

The Companies (Directors’ Report) and Limited Liability Partnerships (Energy and Carbon Report) Regulations 2018 introduced the Streamlined Energy and Carbon Reporting (SECR) framework, effective for financial years starting on or after 1 April 2019. It’s not voluntary for the organisations it covers. It isn’t the same thing as a general ESG statement, either — it’s a specific set of disclosures required in the directors’ report.

You’re in scope if your company or LLP is quoted, or if it’s “large”. “Large” means meeting at least two of: turnover above £36 million, balance sheet total above £18 million, or more than 250 employees. Where you meet those thresholds, the official Environmental Reporting Guidelines require you to disclose, each year:

UK energy use — at minimum, electricity, gas and transport fuel
Associated greenhouse gas emissions (Scope 1 and Scope 2, as a minimum)
At least one intensity ratio, so a reader can compare emissions against a business metric such as revenue or floor area, not just an absolute total
A narrative on the energy efficiency actions taken during the year

Organisations using 40 MWh or less of energy a year can claim the low-energy-user exemption. But they still have to state that they’re claiming it, rather than simply omitting the disclosure. There’s no threshold at which a company in scope can just leave the section blank.

Two developments make 2026 a genuinely different year to get this right. First, the Department for Business and Trade published the final UK Sustainability Reporting Standards — UK SRS S1 and S2 — on 25 February 2026. These adapt the ISSB’s global IFRS S1/S2 standards for UK use.

Second, in its response to the consultation that produced them, government committed to review how SECR interacts with UK SRS “with a view to reducing unnecessary duplication.” That’s a review commitment, not a confirmed phase-out date. As a result, SECR’s specific disclosure format still stands, and shouldn’t be treated as already redundant. If you’re in scope for SECR this year, report it properly — watch for government to clarify the interaction, but don’t assume the outcome now.

How on-site generation should actually be evidenced

The mistake we see most often isn’t a fabricated number — it’s an unsupported one. A generation figure quoted from a supplier’s brochure, or a rough annual estimate, doesn’t survive an auditor or an investor’s due-diligence team asking “show me.” You build a defensible figure from a specific evidence chain. Set that chain up before you switch the panels on, not after the first report falls due.

Evidence tier	What it establishes	Where it comes from
MCS commissioning certificate	Links a specific system, at a specific address, to a stated capacity	Your installer, on handover
Half-hourly metered generation data	The actual output over time, not a modelled estimate	Inverter monitoring platform or smart meter
Renewable Energy Guarantees of Origin (REGO)	One certificate issued per MWh of renewable output, administered by Ofgem	Ofgem’s REGO register, tied to your metered generation
Self-consumption vs export split	What was actually used on site (offsetting grid draw) versus sold back	Your metering and, where applicable, Smart Export Guarantee records

Metered data beats a modelled estimate every time someone challenges a reporting figure. An MCS certificate plus your own meter readings gives you a stronger position than relying on an installer’s projected annual yield.

Solar often sits alongside a green tariff or purchased renewable certificates elsewhere in your energy mix. When it does, keep the two clearly separated in your reporting. On-site generation you can evidence physically is a different, stronger claim than a certificate bought to cover grid-supplied power — and conflating them is exactly what a sustainability auditor learns to spot.

The mistake: solar as the whole answer

Solar is visible, it’s popular with staff and customers, and it produces a genuinely good number for a report. That combination is precisely why it gets over-claimed. We regularly see one of two versions of the same error:

Solar presented as “our net-zero plan” rather than one measure among several — with no parallel evidence of efficiency improvements, procurement changes or demand reduction to back up a broader decarbonisation narrative.
Generation output confused with genuine carbon reduction, without adjusting for the fact that most commercial arrays only offset a portion of total consumption — the rest still comes from the grid, at the grid’s carbon intensity that year.

A single rooftop array, however well specified, is one lever. The SECR “energy efficiency actions” narrative expects a portfolio of measures, and so does any credible ESG statement — generation, but also efficiency retrofits, controls and metering improvements, and procurement decisions. State each one’s contribution separately and honestly.

A report that leans entirely on one solar figure invites trouble. Without a clear efficiency and procurement story alongside it, a board or investor tends to ask one question. It’s the question that unravels an overstated claim: “what else have you actually done?”

Where this connects to the ESG frameworks that matter

SECR is a UK statutory floor. Above it sit the frameworks a board or an institutional investor actually cares about. They ask for the same underlying evidence, just in a different — usually more demanding — shape:

UK SRS S1 and S2 — the newly published UK adaptation of the ISSB’s global sustainability and climate disclosure standards, expected to become mandatory for around 500 listed companies from 1 January 2027 under proposals the FCA is consulting on, per ICAEW’s summary of the publication. S2 in particular expects Scope 1, 2 and material Scope 3 emissions, not just the Scope 1/2 minimum SECR sets.
Investor and lender due diligence — banks and institutional investors increasingly ask for the same energy and carbon data as part of financing terms, and they ask the same “show me the metering” question an auditor would.
Customer and supply-chain requirements — larger customers increasingly push Scope 3 reporting requirements down their supply chain, meaning your generation and consumption evidence may end up feeding someone else’s disclosure, not just your own.

The practical implication is straightforward: build the evidence chain once, to the highest standard any of these frameworks will ask for. Don’t produce a rough SECR figure this year and then scramble to substantiate it properly when UK SRS or an investor’s due-diligence team comes asking. Metered data, an MCS certificate, and REGOs held against your own generation clear that bar. That holds true regardless of which framework is reading it.

Getting solar’s contribution right, before the report is due

None of this is a reason to avoid solar. It’s a reason to plan its evidence and its place in the wider story from the outset. Don’t retrofit a narrative once the panels are already on the roof.

That’s exactly what sits inside our net-zero strategy service: placing on-site generation honestly alongside efficiency, storage and procurement. It also means producing the carbon and cost evidence in a form your finance and sustainability teams can defend. That evidence needs to hold up under SECR today, and under UK SRS or investor scrutiny tomorrow.

Sources: legislation.gov.uk — Companies (Directors’ Report) and LLPs (Energy and Carbon Report) Regulations 2018; GOV.UK — Environmental Reporting Guidelines, including SECR; GOV.UK — UK SRS S2: Climate-related Disclosures; ICAEW — Government publishes UK Sustainability Reporting Standards; Ofgem — Renewable Energy Guarantees of Origin (REGO).

Solar farm land leases: how much are landowners actually being paid in 2026?

John Shaw — Fri, 17 Jul 2026 13:59:00 GMT

If you farm or own land in the UK, you may already have a letter from a solar developer. If not, one may be on its way. The pitch usually leads with a number — “we can offer you £X per acre.” Developers frame this as guaranteed, inflation-proofed income for little more than signing an option agreement.

Some of these numbers are genuinely in line with the market. Others are opening bids designed to look generous against a rent you’ve never had reason to benchmark. This piece sets out what independent rural surveyors say landowners actually earn in 2026. It also covers what moves that figure, and the tax dimension that rarely makes it into the developer’s letter.

What the market actually pays

Two of the UK’s established rural advisory practices publish figures worth anchoring to. Use these instead of relying on whatever a single developer’s letter claims:

Source	Reported rate	Basis
Savills Research	~~£2,500 per hectare/year (~~£1,010 per acre)	Industry-quoted return for large-scale solar PV leases
Strutt & Parker	In excess of £1,000 per acre/year	Recommended minimum for a 25-year lease with no extension or renewal rights
Typical Farm Business Tenancy (FBT)	£150–£200 per acre/year	For comparison — ordinary arable or grazing rent

Both figures land in the same broad range. Both also sit five to seven times above ordinary rent. That’s what the same land would earn under a normal Farm Business Tenancy. That gap is the whole commercial logic of a solar lease.

A developer can afford to pay well above agricultural rent. That’s because the land, once connected and consented, generates revenue at a scale farming could never match.

Treat these figures as a starting point for negotiation, though, not a fixed market price. The rent a specific site actually commands can move a long way from that midpoint in either direction. A competent adviser earns their fee in that negotiation, not by accepting the first offer.

What actually moves the number

The headline “£1,000-plus an acre” hides real variation. In practice, the rent a developer will pay depends on:

Grid proximity and headroom. A site close to a substation with spare capacity saves the developer a six- or seven-figure reinforcement bill. As a result, they’ll pay more to secure it. A site further out, or in a constrained part of the network, starts from a weaker negotiating position.
Site size and shape. Larger, regularly shaped, unshaded parcels cost less per megawatt to build and cable. Developers reflect that saving in the rent they’re prepared to offer.
Agricultural Land Classification (ALC). National planning guidance treats land graded 1, 2 or 3a as “best and most versatile” (BMV). It steers large ground-mount schemes away from that land. A Grade 3b or lower site is a stronger, faster-consenting planning proposition. That can mean a better rent, not a worse one. It removes planning risk from the developer’s side of the deal.
Lease term and structure. Most solar leases run 25 to 40 years. They’re index-linked, so the rent doesn’t erode against inflation over that span. That said, the indexation mechanism itself is worth scrutinising. A fixed-percentage annual uplift and a full RPI or CPI link can diverge meaningfully over three decades.
Whether there’s real competitive tension. A single developer with no rival bidder has little reason to move off their opening number. A developer who knows you’re comparing offers, or that you’ve taken independent advice, has much more reason to negotiate.

Grid connection is the constraint behind the price

Every one of those factors ultimately traces back to the same bottleneck: headroom on the local electricity network. Ground-mounted schemes of any scale fall under Engineering Recommendation G99. That’s the framework governing how generation connects to a DNO’s network.

That process starts with an initial enquiry and a formal application. For larger arrays, it also requires a full technical assessment before the DNO issues a connection offer.

In rural areas, spare grid capacity is often scarcer than the land itself. A site with a strong connection nearby can command meaningfully more rent. However, a field two or three miles from the nearest substation earns less.

Reinforcement costs, or a place in a connection queue, eat into what the developer can afford to pay you. “We have a connection offer” is a claim worth verifying before signing anything exclusive. It’s not a detail to take on trust.

The inheritance-tax catch the rent figure doesn’t show

Here’s the part almost no offer letter volunteers. Land farmed in-hand, or let on a Farm Business Tenancy, has generally qualified for Agricultural Property Relief (APR). This APR shelters it from inheritance tax.

But once someone leases that land for solar, it’s no longer in agricultural use. As a result, the land generally loses APR eligibility. That’s a point Savills’ own research on renting land for renewables makes plainly.

That matters more than it used to. From 6 April 2026, reforms to APR and Business Property Relief take effect.

Under these reforms, each estate gets a combined allowance for qualifying agricultural and business assets. The first £2.5 million of that combined total stays free of inheritance tax. That threshold is up from an originally proposed £1 million cap.

The government revised it after representations from the farming sector, and confirmed the change on 23 December 2025. Above that £2.5 million allowance, relief drops to 50%. That gives an effective 20% inheritance-tax rate on the excess, rather than the standard 40%.

Spouses and civil partners can also transfer the allowance between each other. As a result, a couple can shelter up to £5 million between them (GOV.UK — inheritance tax reliefs threshold to rise to £2.5m).

Here’s the practical effect for a landowner weighing a solar lease. Take land that would sit inside your £2.5 million agricultural-relief allowance while farmed. Once you let it for solar, though, that same land can fall outside any relief at all.

That’s because it’s no longer agricultural property for APR purposes. As a result, that value falls into the taxable part of your estate. That’s true no matter how generous the new threshold is. That doesn’t make leasing the wrong decision, though.

It makes leasing something to model against your own estate and succession position before you sign. Weigh it alongside the rent itself, not after.

Agrivoltaics — the one option that can protect both

Where grazing continues beneath or between the panels — agrivoltaics — the land can, in principle, remain in genuine agricultural use. This is worth raising directly with the developer at heads-of-terms stage, rather than waiting for them to offer it. It also tends to strengthen the planning case on better-quality land. That’s because a scheme that keeps grazing viable is easier to defend against BMV land policy.

Whether it changes the APR position for your specific arrangement is a question for your own tax adviser. There’s no general rule here. But it’s the strongest card available if keeping some agricultural status matters to you.

Weighing the offer properly

A land-lease offer and an on-site self-supply system solve different problems. The right answer for your holding depends on your appetite for capital risk and your succession plans. It also depends on what you actually need the land to keep doing. We set out this comparison in full in our land lease vs on-site solar guide.

Suppose a lease looks like the right route for your site. Our energy and ROI modelling service compares the rent on offer, the lease structure, and the tax position. It weighs all three against the alternative. That way, you can test the number in the letter properly before you sign anything.

G99 explained: the grid connection process for commercial solar

John Shaw — Mon, 13 Jul 2026 10:36:00 GMT

Every commercial solar system big enough to matter has to clear a hurdle most people ignore until it slows their project down. The local electricity network operator has to agree, in writing, that you can connect it. For anything above the smallest rooftop scale, that hurdle has a name: Engineering Recommendation G99. Understanding how it works is one of the most useful things a facilities manager, developer or finance director can do before committing capital.

What G99 is, and why it applies to your project

G99 is the Energy Networks Association standard for connecting generating equipment “in parallel” with the public electricity distribution network. In plain terms, it covers how a solar system that can push power back onto the grid gets signed off. That sign-off comes from the company that owns the local wires and substations — your Distribution Network Operator (DNO).

The dividing line between the simple and less-simple routes sits at the boundary with G99’s smaller sibling, G98. G98 covers the smallest, fully type-tested installations — up to 16A per phase, around 3.68kW single-phase or 11kW three-phase. Below that threshold, installers can largely notify the DNO after the work is done.

Step above that threshold, and you’re in G99 territory. Almost every genuinely commercial system does. In that case, a formal application has to be approved before you connect, not after.

Retained UK regulation classifies generation by size and connection voltage into four categories — Type A, B, C and D — under the Requirements for Generators framework. For a Great Britain connection point below 110kV, Type A runs from 0.8kW up to 1MW. Type B and above cover everything from 1MW upward.

In practice, that split maps neatly onto how the ENA organises its own guidance. It publishes a dedicated guide for Type B–D generation aimed squarely at “commercial, industry, developers and farms” — the audience this article is written for.

Category	GB capacity band	Typical commercial example	What it means in practice
Type A	0.8kW – under 1MW	Most rooftop systems from around 100kW up to just under 1MW	Standard G99 application; the DNO’s assessment is usually more contained
Type B, C, D	1MW and above	Large rooftop, ground-mount, multi-building estates	A full technical assessment of network impact is standard, not exceptional

The process, stage by stage

Skip the acronyms and the G99 journey breaks down into four stages that repeat, in some form, on every project:

Initial enquiry and feasibility check. Before anything is submitted formally, it’s worth asking your DNO an informal question: is there headroom at the nearest substation for a system of this size? Every DNO now publishes some form of network capacity map for exactly this reason. A five-minute check here can save months later.
Formal application. The generator (or their adviser) submits the DNO’s standard application form. It includes inverter details, MCS certification where relevant, single-line diagrams and the site’s electrical layout. This is the point the clock formally starts.
Technical assessment. For anything beyond the smallest systems, the DNO runs its own study of what your connection would do to the local network. It checks voltage, fault levels, protection, and whether the existing infrastructure can absorb the extra generation without reinforcement. This is the stage that decides whether your connection is straightforward or expensive.
Connection offer and acceptance. The DNO issues a formal offer setting out the terms, any required network works, and their cost. You then have a defined window to accept it before it can lapse.

None of this is exotic. The same sequence applies whether the applicant is a 250kW warehouse roof or a 5MW ground-mount array. But the stakes of stage three rise sharply with system size — and that’s exactly where rural sites tend to run into trouble.

Why rural headroom is the quiet risk in this process

The single biggest practical risk in G99 isn’t the paperwork. It’s discovering — after design work, and sometimes after a tender has already gone out — that the local network doesn’t have room for your system. That often means upgrading a piece of infrastructure the developer never sees or controls.

Engineers designed rural and semi-rural networks to move power outward from substations to dispersed, relatively light demand. They never had to absorb large amounts of generation flowing back the other way. As a result, a site a short distance from a well-loaded substation can face a materially different — and more expensive — connection outcome. A near-identical building on a better-connected part of the network might not, simply because of where the cables happen to run.

That’s why we treat the DNO enquiry as a feasibility-stage question, not a procurement-stage one. Check headroom before you sign a lease, issue a tender, or specify a system size for a farm building’s roof. That way, you price any reinforcement cost into the decision from the start. You won’t discover it as an unwelcome addition once you’re already committed.

Realistic timelines

DNOs work to a statutory response window once a complete application lands. But “complete” is doing some work in that sentence: an application missing detail doesn’t start the clock. Instead, the DNO sends it back for more information.

Beyond the formal response period, timelines vary widely. From a first enquiry to a usable, accepted connection offer, the practical range commonly runs from a few months — where headroom is already available — to the best part of a year, where a technical assessment flags reinforcement. Where reinforcement works are required, construction of them adds further time again before energisation.

It’s also a moving target. In April 2025, Ofgem approved a package of grid connection reforms intended to replace the historic “first come, first connected” queue. The new “first ready, first connected” model prioritises projects that are actually deliverable over ones simply holding a place in the queue.

The reform mainly targets the transmission-level backlog rather than routine rooftop G99 connections. However, it signals the direction DNOs are heading. It’s worth checking whether your DNO’s published timescales have moved since you last looked.

Building G99 into the decision, not around it

None of this changes whether solar is worth doing on a given site. But it does change when you find out. A DNO capacity check costs nothing and takes a phone call or a web form. Discovering a six-figure reinforcement bill after a board has approved a project costs a great deal more.

Our feasibility studies build the grid-connection question into the same early assessment as roof structure and shading. That way, the G99 answer arrives alongside everything else you need to make the call — not months into a project that has already spent money assuming the connection would be straightforward.

Independent solar advisor vs installer survey: what's actually different

John Shaw — Wed, 08 Jul 2026 15:11:00 GMT

Search “independent solar advisor” and most results are installers describing their own sales process as advisory. That’s not dishonest exactly — a good installer’s site survey is genuinely useful engineering. But it’s a different thing from independent advice, and the difference matters more than the terminology suggests. One has a system to sell you; the other doesn’t.

What an installer’s “free survey” actually is

A free survey exists to produce a quote. The surveyor measures your roof or land, checks orientation and shading, and notes anything obviously wrong. Then they return with a proposed system size, an installed price, and a savings projection.

That’s a real and necessary step in buying solar. But it sits inside a sales process. The incentives that come with it are worth being clear-eyed about:

The company only earns if you say yes. A survey that concludes “this site isn’t worth developing” costs the installer a sale and their time. There’s no commercial reason to volunteer that finding. There’s every reason to find a way to make the numbers work.
The specification is usually theirs to set. The system size, panel choice and inverter are typically whatever that installer sells. That’s not necessarily the configuration best suited to your load profile, roof condition or budget.
Savings projections often lean optimistic. Which?’s consumer guidance on buying solar panels flags this pattern as a market-wide red flag. The red flags include very optimistic savings figures, short payback claims, and salespeople quoting over specialist surveyors. So are pressure to decide quickly and one-off “today only” discounts.
Accreditation isn’t independence. MCS certification is a genuine and useful quality standard. It certifies that an installer’s design, workmanship and equipment meet a set benchmark. It’s also what makes a system eligible for the Smart Export Guarantee. But it certifies competence, not impartiality. An MCS-certified installer is still the party selling you the system.

None of this makes a free survey worthless. It’s the right tool once you know solar makes sense for your site. It also works once you roughly know what you want to buy.

But it’s the wrong tool for the earlier question: should we do this at all, and on what terms?

What genuine independent advice looks like

The structural test is simple: does the adviser have a system to lose by telling you no? A consultancy has no hardware to sell, no installation arm, and no commission tied to a “yes.” So it has no reason to shade a recommendation either way. That’s the whole basis of our about page: “our feasibility work can recommend against a scheme, our procurement is run purely in your interest, and our numbers are built on your own data rather than a supplier’s optimistic defaults.”

	Installer’s free survey	Independent advisor
Who pays them	Nobody, directly — cost is built into the eventual system price	You, for the advice itself
Can it recommend against the project	Rarely, in practice — no commercial upside to doing so	Yes — that’s the point of the engagement
Who sets the specification	The installer, from their own product range	An output-based spec you can put out to any bidder
What you get back	A quote and a savings estimate	A feasibility assessment, business case, or tender you can defend to a board
Accreditation	MCS-certified installer (competence standard)	No hardware to certify — independence is structural, not a scheme membership
Grounded in	The installer’s assumptions and product range	Your site data, your tariff, your capital position

Why this shows up most clearly in commercial procurement

On a domestic roof, a slightly optimistic survey costs a few thousand pounds either way. Take a commercial site — a 250kW warehouse roof, a multi-building estate, or a farm considering a ground-mount array. The same asymmetry applies, but now the decision is worth six or seven figures. And it compounds through two further stages most guides skip:

Specification. If the first installer you speak to writes the spec, every other bidder quotes against their configuration. That’s not a neutral baseline, so “competitive” tenders end up far less comparable than they look on paper.
The go/no-go call itself. Some sites simply aren’t worth developing. The roof might not take the structural load, or the grid connection might have no available capacity. Or the payback might not clear the business’s hurdle rate. An installer’s survey is structurally unlikely to reach that conclusion for you; an independent feasibility study is built to.

This “independent” question also comes up with land, not just roofs. Picture a farm or landowner weighing two options. They could lease ground to a solar developer, or build and own an array outright. That choice reveals exactly how skewed “free advice” can be.

A developer proposing the lease and an installer proposing the build both have a stake in which way you answer. We’ve set out the trade-offs neutrally in our guide to land lease vs. installing solar.

A simple way to tell the two apart

Before you act on any solar advice — commercial or agricultural — it’s worth asking three questions:

Does this person or company sell or install solar hardware? If yes, their survey is a sales tool, however useful.
Do they earn more if I proceed than if I don’t? If yes, treat any “yes, this works” conclusion as one input, not the final answer.
Could they credibly tell me not to do this? If the honest answer is no, you haven’t had independent advice yet — you’ve had a quote.

None of that means installer surveys are worth skipping. Once a project is genuinely viable and specified, you need several of them, run competitively, to buy well. It’s the order that matters: independent advice first, to establish whether and how a project should proceed. Installer quotes come second, against a specification you control.

Where this fits with us

Say you’re at the “should we even do this” stage. Maybe you’re deciding whether a site is worth developing. Or maybe you’re trying to get several installer quotes that actually compare like-for-like.

That’s precisely what our feasibility studies and procurement and tender support are built for. Neither service exists to sell you a system, because we don’t have one to sell.

Agricultural Land Classification and solar: what farmers need to know before signing a lease

John Shaw — Fri, 03 Jul 2026 09:48:00 GMT

A developer’s option letter rarely mentions the one number that matters most: the field’s Agricultural Land Classification (ALC) grade. However, that single grade often decides whether a ground-mounted solar scheme has a realistic path through planning.

It’s easy to see why ALC gets skipped over. Land agents lead with the rent figure and the lease term instead. By the time ALC comes up, developers often frame it as a formality they’ll sort out during the survey stage.

Still, landowners should treat it as far more than that. The grade of the land on offer is one of the biggest single influences on whether the scheme gets built at all. It also shapes how hard the developer has had to fight for planning approval. That’s exactly the leverage a landowner should understand before signing heads of terms, not after.

What ALC actually measures

The Agricultural Land Classification system grades farmland from Grade 1 (excellent) down to Grade 5 (very poor). Natural England runs the system, using factors like climate, site conditions and soil characteristics. These factors determine how versatile and productive the land is for growing crops.

Grade 3 splits into 3a (good) and 3b (moderate). This distinction matters a lot for planning. National policy classifies Grades 1, 2 and 3a as “Best and Most Versatile” (BMV) land. Grades 3b, 4 and 5 are not.

ALC grade	Description	BMV land?	Typical position for ground-mount solar
Grade 1	Excellent quality	Yes	Strongest planning objection; a solar-only scheme rarely succeeds without a strong agrivoltaic or exceptional-circumstances case
Grade 2	Very good quality	Yes	Same high bar as Grade 1
Grade 3a	Good quality	Yes	Still BMV; developer must justify why poorer land nearby wasn’t used instead
Grade 3b	Moderate quality	No	The de facto “sweet spot” most developers target
Grade 4	Poor quality	No	Preferred by developers where available, all else equal
Grade 5	Very poor quality	No	Least agricultural-land conflict, but often marginal, remote sites with weaker grid access

The gov.uk / Natural England guide to assessing development proposals on agricultural land sets out the survey methodology in detail. A genuine ALC assessment involves soil pits, and climate and site-condition data specific to the parcel. It isn’t a desk-based estimate read off a national soil map. That distinction is worth knowing, because a developer’s early-stage screening often relies on the latter.

The planning position, and why it isn’t quite a blanket ban

It’s tempting to describe BMV land as “off limits” for solar. That overstates the position. The precise policy wording has actually moved around in the last two years. It’s worth understanding that shift rather than skating over it.

In May 2024, the government issued a written ministerial statement specifically targeting solar development on BMV land. That statement used tougher language than the general planning framework. The current National Planning Policy Framework has since superseded it, folding the position back into its general policy on agricultural land (policies N1 and N2). That policy requires decision-makers to “take into account the quality of agricultural land (including that classified as best and most versatile agricultural land, and its grade).” Where significant development of agricultural land is necessary, it also requires them to prefer land of poorer quality where it’s available.

In practice, that’s still a real and functioning presumption against large ground-mount schemes on Grade 1, 2 and 3a land. It just isn’t a solar-specific rule anymore, and it isn’t absolute. Planning authorities can still approve a scheme on BMV land where the planning balance favours it. That balance weighs several factors: grid position, landscape impact, and the absence of suitable lower-grade alternatives locally. Increasingly, it also weighs a credible continuing agricultural use.

For a landowner, this therefore means something concrete. A developer proposing BMV land takes on more planning risk than one working with 3b or below. That extra risk should show up in the option and lease terms — not just in the headline rent.

Government policy since has, if anything, reinforced this direction of travel rather than relaxed it. Defra published the Land Use Framework for England in March 2026.

This framework explicitly commits to safeguarding BMV land from long-term change of use. Additionally, it steers new solar towards lower-grade land and towards dual use — co-locating generation with continued grazing or cropping. This dual-use approach is the preferred way to square food production against clean-power targets.

Agrivoltaics as the answer to the BMV objection

This is where agrivoltaics stops being a nice-to-have and starts being a genuine planning strategy. Sheep grazing between and beneath the panel rows is now the established, low-friction version of agrivoltaics in the UK. Where that grazing continues, the land arguably never leaves agricultural use at all.

That’s a materially different planning argument than a solar-only scheme makes. A solar-only application asks a planning committee to accept the loss of BMV land. An agrivoltaic application argues, in contrast, that the land stays productive, alongside generation.

It isn’t automatic, though, and it’s worth being clear-eyed about that. A grazing plan bolted onto the application as an afterthought still carries little weight. What strengthens a case on better land is a credible, evidenced scheme.

That means real stocking rates, panel height and spacing designed around continued grazing. It also means a management plan the applicant can actually be held to. Solar Energy UK’s own factsheet on solar farms and agricultural land makes the same point. Its position is that dual use answers the food-security objection, not that it exempts BMV land from scrutiny altogether.

What this means for your lease negotiation

None of this is abstract for the landowner. It should shape the deal itself, not just satisfy curiosity about planning risk. Do a few things before signing anything:

Get your own ALC read on the specific parcel, not the developer’s screening estimate. National soil maps are indicative only; the grade that actually goes to the planning authority is based on a site-specific survey, and it can differ from a desk assessment in either direction.
Ask directly which grade the developer believes the site to be, and what their fallback position is if a formal survey comes back higher than expected. A developer confident of 3b should have no difficulty answering this before an option agreement, not after.
Treat BMV land as a reason to negotiate harder, not to walk away. Higher planning risk is a real cost to the developer. Reflected fairly, it should show up as a shorter option period, a higher rent to cover the risk, or firmer break clauses if consent is refused.
Raise agrivoltaics explicitly at heads-of-terms stage if your land is BMV and grazing is realistic — don’t wait for the developer to volunteer it. A grazing tenancy running alongside the solar lease can also preserve some Agricultural Property Relief exposure. A solar-only lease typically forfeits this relief, so it’s worth raising with your own tax adviser alongside the rent figures.
Check the rent reflects the land, not a generic benchmark. Industry figures put ground-mounted solar rents in the region of £2,500 per hectare a year (Savills). Strutt & Parker separately cites rentals nearer £950 an acre, against £150–£200 an acre for a typical Farm Business Tenancy. However, a lower-grade, well-connected site with straightforward planning should command a stronger rent than one carrying real BMV risk, not the same figure regardless.

If leasing your land and generating your own power both look plausible for your site, our land lease vs on-site solar guide sets out that broader decision in full. Our Agriculture & Land sector page covers the grid-connection and income side alongside planning. For a short definition, our glossary also covers ALC and BMV land briefly.

Getting an independent read before you sign

A developer’s option letter is not an independent assessment of your land. Neither, for that matter, is their in-house planning summary. The party with an interest in the deal proceeding writes both.

Commission an independent feasibility study before committing to an exclusivity period or heads of terms. It can establish the site’s real ALC position, grid headroom and planning risk on its own merits. As a result, the negotiation starts from facts about your land, not the developer’s.

Solar for warehouses and logistics: why the biggest roofs pay back fastest

John Shaw — Mon, 29 Jun 2026 11:23:00 GMT

Picture designing the ideal building for commercial solar from scratch. You’d end up with something close to a modern distribution warehouse. It has a vast, unshaded, low-pitch roof with almost nothing on it. Beneath that roof sits a business that draws serious power all day, every working day.

A huge roof paired with heavy daytime power use is a winning combination. It gives warehousing and logistics the fastest payback of any UK commercial property type. That’s also why we treat it as its own sector, not a subset of “industrial.”

The economics are simple: a big roof spreads fixed installation costs over far more panels. Those costs include scaffolding or access equipment, cabling runs, project management and commissioning. That’s a large part of why per-kWp pricing falls as systems get bigger. See our commercial solar cost guide for the bands.

Heavy daytime demand adds to that advantage. Refrigeration, conveyor and materials-handling plant, and HVAC across a large floorplate all draw power non-stop. As a result, the site uses a high share of what the panels generate immediately. That happens at the price you’d otherwise pay the grid, not the lower rate you’d get for exporting it.

Self-consumption, not export, is what actually drives return on a commercial site. Logistics buildings are about as good as it gets on that measure.

But “the roof is huge” is the start of the conversation, not the end of it. Three things decide whether a specific warehouse or distribution centre can actually take the system its roof area suggests. The first is what the roof structure will bear.

The second is how old the roof covering is, and what type it is. The third is whether the local grid has room for the connection. Get any of those wrong, and a strong-looking site turns into an expensive lesson.

Structural loading and roof age

A modern solar array typically adds around 18–25 kg per square metre of dead load to a roof. That’s modest next to the snow and wind loads engineers originally designed the structure to carry. But it isn’t nothing, and it’s not something to assume away on an ageing building.

Engineers built portal-frame sheds decades ago to the loading standards and steel specifications of their time. Since then, purlins, fixings and the roof membrane itself have degraded. That’s why a structural survey is the first thing we do on any warehouse feasibility study.

It checks purlin and truss condition and corrosion. It also checks the actual spare load capacity, not just the capacity shown on the original drawings.

This step matters. A roof can look perfect from the ground and still turn out not to be viable as-is. That’s the single most common reason a warehouse roof fails to qualify.

Roof covering matters as much as the frame underneath it. Many industrial buildings built before the UK’s full ban on asbestos in November 1999 used asbestos cement roof sheeting. That ban came via the Asbestos (Prohibitions) (Amendment) Regulations 1999. The Control of Asbestos Regulations 2012 tightly control fixing anything to that material.

HSE guidance treats drilling into it as licensable-adjacent work requiring trained operatives and proper controls. As a result, many installers simply won’t fix directly to it at all. Where that’s the case, two practical routes exist.

The first is a combined re-roof-and-solar project: replace the covering, then fit the array to the new deck. The second is an overlay that creates a safe new fixing surface without disturbing the asbestos beneath. Either route adds cost and time to the programme.

That’s exactly why it needs pricing into the business case at feasibility stage. It shouldn’t come as a discovery after a specification has already gone out to tender.

None of this makes an older warehouse a bad candidate. It makes roof condition, not roof area, the number that should drive the go/no-go decision.

Grid capacity: the other gating factor

The second constraint is electrical, not structural. Anything above the smallest domestic-scale system connects to the network under Engineering Recommendation G99. That’s the Energy Networks Association’s standard for connecting generation. The process runs through three stages: an initial enquiry to the local Distribution Network Operator, then a formal application.

For larger commercial systems, a technical capacity assessment follows before the DNO issues a connection offer. In practice, this can take anywhere from a few months to the best part of a year. It depends on the DNO, local network headroom and system size. It’s worth flagging early, rather than after a tender has gone out.

Logistics corridors add a wrinkle worth naming directly. The Midlands’ so-called “Golden Triangle” is the dense cluster of distribution sheds around the M1/M6/M42 junctions. Developers chose that spot because it puts around 90% of the British population within a four-hour drive. The area has seen sustained warehouse construction.

In a recent year, the East Midlands alone accounted for roughly a fifth of national warehouse-construction spend. That’s part of a multi-billion-pound annual total. That scale of development has added real new electricity demand to the regional network over the same period. It has also created considerable rooftop solar potential on those same warehouse roofs.

As a result, grid headroom can vary sharply between two sites in a corridor like the Golden Triangle. That’s true even when they look identical from the road. It depends on which substation each site sits behind. See our Midlands region page for more on how that corridor’s growth interacts with local grid capacity.

Checking DNO headroom is a feasibility-stage task everywhere. But in a fast-growing logistics cluster, it’s a genuinely live risk, not just a formality.

Car-park and yard canopies, where the roof isn’t enough

Some sites have more electrical appetite than their roof can supply. In other cases, structural or grid constraints won’t let the roof reach that capacity. Distribution centres and depots often have the answer sitting in the yard. Staff and HGV car parks are frequently large enough to host a solar canopy.

That trades a modest amount of parking-space efficiency for a second generation asset. It also adds shaded, weather-protected parking as a genuine staff benefit.

Factor	Rooftop array	Car-park canopy
Typical installed cost	Roughly £600–£850/kWp at warehouse scale (falls further above 500kW)	Roughly £950–£1,300/kWp, reflecting the steel canopy structure
Structural question	Existing roof and frame condition	New-build structure — no dependency on an ageing roof
Space used	Existing roof, no loss of usable land	Reduces net parking spaces by a modest amount per bay
Added benefit	None beyond generation	Weather-protected parking; natural mounting point for EV charge points
Best used when	Roof condition and area both check out	Roof is constrained, already committed elsewhere, or EV charging is also wanted

Canopy costs run higher per kWp than a straightforward rooftop system. That’s because you’re building a structure as well as fitting panels. EV charge points add further cost per socket on top of that.

Take a site where the roof can’t handle the full load a business wants. Or picture one where fleet electrification is already on the agenda.

There, a canopy converts an otherwise wasted yard asset into both power and infrastructure in one project. It’s rarely an either/or decision against the roof. The strongest logistics sites we assess often end up specifying both.

Getting the sequence right

The pattern that catches sites out isn’t a lack of roof or a lack of demand. Those are usually the easy part of a warehouse feasibility study. The real problem is committing to a system size too early. That happens before the structural survey and the DNO enquiry have both reported back.

Sites then discover the roof needs reinforcing, or that the grid connection needs a costly upgrade. By then, a tender has already gone out. Structural loading, roof age and covering, and grid headroom all need answers in parallel, and early. Answer them for the specific building in question, not by assuming from its roof area alone.

For a single site, that’s the job of a proper feasibility study. Structural assessment, yield modelling and grid enquiry run together. That produces an honest go/no-go before anyone commits any capital.

For an estate with several distribution centres or logistics sites, the same logic applies across the whole portfolio. Some sites will have stronger roofs, better grid positions or heavier loads than others. Portfolio optimisation ranks them properly and sequences capital to the strongest sites first. That beats working through the estate in whatever order sites happen to come up.

Sources: HSE — Locations of asbestos and taking the right action; HSE — Control of Asbestos Regulations 2012; Asbestos (Prohibitions) (Amendment) Regulations 1999; Energy Networks Association — G99 connection guide; ONS — The rise of the UK warehouse and the golden logistics triangle.

What does a commercial solar feasibility study actually involve?

John Shaw — Wed, 24 Jun 2026 16:05:00 GMT

“Feasibility study” gets used loosely in commercial solar. Sometimes it means a proper independent assessment. Sometimes it means the free site visit an installer runs before they quote. The two are not the same thing.

An installer’s survey exists to produce a sale. It checks enough to design a system and price it, then stops there.

By contrast, a genuine feasibility study has no such incentive. It exists to answer one question honestly: is this site worth developing, and on what terms? Sometimes the honest answer is no.

This is what actually happens between instructing a feasibility study and receiving the report. It covers the desktop review, the structural survey, and the grid application. It also covers the standards everything gets checked against. Finally, it details what a defensible go/no-go recommendation looks like when it lands on your desk.

The sequence, step by step

Every credible commercial feasibility study follows roughly the same order. Each stage exists to catch the failure that would make the next stage pointless.

Desktop review. Aerial imagery, existing EPC data, any structural drawings on file, and — where available — 12 months of your half-hourly electricity data. This is cheap to do and quickly rules out sites with an obvious problem (heavy shading, a roof clearly too small, no usable land).
On-site structural survey. A physical inspection of purlin and truss condition, roof membrane age, and the dead-load capacity available for panels, ballast or penetrative fixings. This step usually confirms or rules out a promising-looking site.
Shading and orientation study. Using the site’s actual pitch, aspect and nearby obstructions to model realistic annual generation — not a generic per-kWp assumption pulled from a brochure.
Grid-connection review. An initial DNO enquiry (and, where warranted, a formal application) to establish whether the local network has capacity, and what a connection would cost and take.
Indicative capex and payback. A cost range and payback estimate built on the site-specific yield and grid position established above, not a generic system price.
The go/no-go report. A written recommendation stating the viability conclusion, the assumptions behind it, and the risks that could still change the answer.

The structural survey usually comes first for a reason. A corroded steel frame or a tired membrane is the most common reason a promising-looking roof turns out unviable. It’s far cheaper to catch this early, before you commission a shading study or open a grid enquiry, than after.

The structural survey: what’s actually being checked

Roof structural loading is a genuine go/no-go gate, not a formality. Engineers design every commercial roof to carry a specific combination of loads. Dead load covers its own weight plus fixed services. Live load covers wind, snow, and maintenance access.

Solar hardware — panels, mounting rails, and either ballast blocks or penetrative fixings — adds permanent dead load. That load has to fit inside the margin the original design allowed. If it doesn’t, the structure needs strengthening before anything goes on it.

A surveyor checks:

Purlin and truss condition, and any visible corrosion, deflection or previous repair
The roof covering’s age and remaining service life — a membrane due for replacement in three years changes the economics of fixing solar to it now
Whether the original structural design has any spare load margin, and how much
Fixing method — penetrative bolted fixings versus non-penetrative ballasted systems, which load the structure differently
Access and maintenance routes, and any rooflight or plant obstructions

Where original structural drawings exist, this step is faster and cheaper. Where they don’t — common on older industrial buildings — a structural engineer assesses load capacity from first principles. That adds time, but it isn’t optional. Guessing at load capacity on an ageing roof is exactly the shortcut a feasibility study exists to avoid.

The G99 grid application: process and realistic timeline

Anything larger than the smallest domestic-scale array falls under Engineering Recommendation G99. This is the Energy Networks Association’s standard for connecting generation to the local electricity distribution network. It’s the natural next gate after structural viability. A site can pass the roof survey but still fail if it can’t get a usable grid connection.

The process runs in stages:

Initial enquiry. A preliminary check with the local Distribution Network Operator (DNO) — the regional company that owns the wires and substations the site would connect into — on whether headroom looks available in principle.
Formal application. A completed application on the DNO’s standard G99 form, with the technical detail of the proposed system.
Technical assessment. For larger commercial systems, the DNO studies local network capacity, fault levels and any reinforcement the connection would require. Only then can it issue a firm offer.
Connection offer. A formal offer stating the connection terms and any reinforcement cost. Often the part that surprises buyers most is the connection date itself — it can land well after both sides agree the technical work, if the site needs reinforcement.

DNOs work to a statutory response window for that technical assessment. But the full path runs from first enquiry to a usable, accepted connection offer. That commonly takes a few months to the best part of a year. It depends on the DNO, local network headroom, and system size.

A well-connected site near a substation with spare capacity moves quickly. A site further from the network can take much longer. The same is true where local generation already uses up available headroom. That can mean a material reinforcement cost too.

Ofgem’s ongoing grid-connections reform package aims to speed this up over time. For now, though, the practical advice hasn’t changed: get the enquiry in early, as part of feasibility. Don’t wait until after a tender has gone out on the assumption that grid capacity isn’t a problem.

The standard everything gets specified against: MCS MIS 3002

Any UK-accredited installer designing, installing and commissioning solar PV work does so against MCS’s MIS 3002 standard. This is the technical benchmark covering system design, structural fixing, electrical safety and handover documentation. It underpins MCS accreditation and most funders’ and insurers’ requirements.

One detail is worth getting right, because it’s easy to misstate. MIS 3002 formally applies to installations up to a maximum DC output of 50kWp. Most commercial rooftop systems worth a proper feasibility study sit well above that threshold.

In practice, MIS 3002 still functions as the reference point for competent design and installation practice. That covers structural sign-off, electrical safety, and documentation. But a system above 50kWp isn’t a routine MCS job scaled up.

It needs specifying, commissioning and warrantying as a genuine bespoke commercial project. Referencing the relevant standard precisely in the specification is what lets you compare installer tenders like-for-like later, at procurement stage.

How long it actually takes

A single-site feasibility study, from instruction to a written go/no-go report, typically takes two to four weeks. That covers the desktop review, structural survey, shading study and an initial grid enquiry. It doesn’t include a full formal G99 application, which runs separately and longer.

It stretches beyond four weeks in three cases. First, a structural engineer may need to assess load capacity from first principles when no drawings exist. Second, a more detailed grid enquiry adds time when headroom looks tight. Third, assessing several sites together — as with a portfolio review — takes longer too.

Sometimes the study opens a formal G99 application, not just an initial enquiry. When that happens, its connection-offer stage runs on its own multi-month timeline in parallel. It doesn’t hold up the rest of the report.

What a real go/no-go recommendation looks like

This is what separates a feasibility study from a sales survey. A defensible go/no-go report states:

The conclusion — proceed, don’t proceed, or proceed with a named condition (e.g. “viable if roof reinforcement is included in scope”)
The site-specific numbers behind it — usable roof or land area, modelled annual generation, structural loading margin, grid position
Indicative capex and payback range, stated as a range with the assumptions attached, not a single misleadingly precise figure
The risks and assumptions that could change the answer — an unresolved grid reinforcement cost, a roof condition finding still pending specialist sign-off, a planning constraint
What the specification needs to cover at procurement stage, so bids can be compared like-for-like

A report that only ever says “yes, proceed,” regardless of what the survey finds, isn’t independent. It’s a sales document with extra steps. Paying for a study rather than accepting a free survey has one real value: “no” is a genuinely available answer. And when the answer is “yes,” numbers back it, built for board or investment-committee scrutiny, not a supplier’s optimistic defaults.

Where this fits

A feasibility study is the first, cheapest gate in a commercial solar decision. It exists to stop weak projects before you commit to design fees, tenders or site visits from installers.

If you’re weighing whether a specific site is worth taking further, our feasibility studies service covers exactly this process. It includes the structural survey, grid review, indicative numbers, and a written recommendation for your board or investment committee. And we run it independently of any installer with a system to sell you.

The tax mistake solar salespeople make about "Full Expensing"

John Shaw — Fri, 19 Jun 2026 08:52:00 GMT

Ask three commercial-solar salespeople how the tax relief works. There’s a fair chance at least one will tell you your system qualifies for “100% Full Expensing.” It’s a confident, specific-sounding claim. It’s also wrong — and HMRC’s own manual says so in one sentence.

The claim, and why it’s false

Full Expensing is a real UK tax policy. It delivers a 100% first-year deduction against taxable profits, with no cap. The government introduced it for main-rate plant and machinery in the Spring 2023 Budget.

It became permanent from April 2024. It’s generous, uncapped, and genuinely a big deal for the assets it covers.

Solar panels are not one of those assets.

Since 1 April 2012, HMRC has classified solar panel spending as “special rate” expenditure, not main-rate plant and machinery. HMRC’s Capital Allowances Manual, CA22335 sets this out explicitly, and Full Expensing, by law, excludes special rate assets. So the two facts sit together plainly: solar is special rate, and special rate assets don’t get Full Expensing. There’s no ambiguity here — it’s a classification, not a judgement call.

Where the confusion actually comes from

The mistake is understandable, even if it’s still a mistake. Most solar buyers do end up with a genuine 100% first-year deduction on their system — just not via Full Expensing. The relief that actually delivers it is the Annual Investment Allowance (AIA).

The AIA also gives 100% relief in the year of purchase. That overlap makes it easy to round “100% relief” up to “Full Expensing.” Someone selling systems, rather than advising on tax, may not check which specific allowance actually applies. The two schemes produce a similar number for many buyers, which is exactly what keeps the wrong name alive.

The distinction stops being cosmetic once a buyer’s spend runs past the AIA’s cap. Above that point, AIA and Full Expensing behave completely differently, as the table below shows.

What actually happens to solar spend

Step	What it is	Rate	Applies to solar?
1	Annual Investment Allowance (AIA)	100%, up to a shared £1 million annual cap across all qualifying plant and machinery spend that year	Yes — this is the relief that usually covers the whole system
2	Full Expensing	100%, no cap	No — main-rate assets only; special rate expenditure is explicitly excluded
3	Special rate first-year allowance	50% on spend above the AIA cap	Yes — this is what solar gets once the AIA is used up
4	Special rate pool writing-down allowance	6% per year on the remaining balance	Yes — ongoing relief on whatever’s left after steps 1–3

Source: GOV.UK — Claim capital allowances and HMRC CA22335.

In practice, this means:

Suppose your business hasn’t used its AIA elsewhere that accounting year. A solar system priced well under £1 million then typically qualifies. It gets a genuine 100% first-year deduction via the AIA, correctly named.
Sometimes the AIA is already committed elsewhere — to a refit, new machinery, or a fleet purchase. Or the solar system itself is large enough to exceed the cap. Either way, the excess falls to the 50% special rate first-year allowance, then 6% a year after that. That’s a materially slower relief profile than an uncapped 100% deduction.
The gap between “AIA covers it” and “Full Expensing covers it” only shows up once you’re above the cap. That’s exactly the scenario where getting the name wrong costs the most.

The 2026 Budget changed the wrong pool

Adding to the confusion, the Autumn 2025 Budget introduced two changes to main-rate plant and machinery. These took effect from January and April 2026. The first is a new permanent 40% first-year allowance. The second cuts the main pool’s writing-down allowance from 18% to 14% (Deloitte Taxscape — capital allowances, Autumn Budget 2025).

Both changes apply to the main pool. Solar sits in the special rate pool.

Neither change touches solar’s treatment at all. But a headline about “new first-year allowances” can land in the same news cycle. That makes it easy to fold into a sales pitch without anyone checking which pool it actually applies to.

Why the distinction is worth insisting on

None of this makes solar a bad investment. The AIA, correctly applied, still gets most single-site commercial systems to a genuine 100% first-year deduction. However, a business case built on the wrong allowance name can go wrong in two specific ways. First, it can overstate the relief on a large system that blows through the AIA cap.

That understates the true payback period to a board or finance committee — and they’ll spot the error later. Second, it can simply be the first domino in a wider sales conversation. From there, people round numbers up rather than checking them properly.

Either way, if a quote or information pack cites “Full Expensing” for a solar system, that’s worth noticing. It’s a fair signal to ask what else in the numbers no one has checked against the primary source.

We cover these definitions in full in our glossary entries for the Annual Investment Allowance and the special rate pool. The sourcing there matches what’s above. It’s worth bookmarking, so you have the precise wording next time someone quotes you a tax figure — not a paraphrase.

Getting the real number for your business

Three things decide which allowance actually applies. They are your accounting year, what else you’ve bought that year, and the size of the system itself. Together, they also determine how much of your spend falls into each step of the table above. That’s a modelling question, not a rule of thumb.

It’s exactly what we build into every business case before a client commits capital.

We work out the real, net-of-tax payback using the allowance that genuinely applies. That’s not always the one that sounds best in a sales deck. If you want that calculation done against your own numbers, our energy and ROI modelling service is where it happens.

PPA vs outright purchase vs lease: the full comparison

John Shaw — Mon, 15 Jun 2026 14:37:00 GMT

There are three ways to put solar on a commercial roof. Almost every conversation we have with a finance director starts by conflating them.

You can buy the system outright, lease the equipment, or sign a power purchase agreement (PPA). Under a PPA, you simply buy the electricity the system produces, rather than owning it.

Each option moves capital, tax relief, risk and balance-sheet exposure to a different place. The right answer depends on your cost of capital and your appetite for owning plant. Increasingly, it also depends on what your auditor will let you keep off the balance sheet.

Below is the comparison we’d actually put in front of a board, not the simplified version most sales material uses.

The three routes at a glance

	Outright purchase	Equipment lease	Power Purchase Agreement (PPA)
Upfront capital	Full cost, paid or loan-funded	Little to none	None
Who owns the system	You	Usually the lessor	The developer/funder
Capital allowances	Yes — AIA, then special rate FYA	Usually the lessor’s, not yours	None — no asset to claim on
O&M responsibility	Yours	Negotiated, often yours	Developer’s, for the contract term
Typical term	N/A — you own it	5–10 years, asset-dependent	10–25 years
Electricity price	Free once paid off, minus O&M	Free once paid off, minus rentals	Fixed or index-linked rate per kWh, usually below grid
Balance-sheet impact	Fixed asset + any loan liability	Right-of-use asset + liability (most leases, from 2026)	Depends on contract terms — see below

Outright purchase: full ownership, full tax relief, full risk

Buying the system outright gives you every pound of the return. But you only get that return in full if you can also use the tax relief.

Solar panels are “special rate” expenditure under HMRC’s capital allowances rules (Capital Allowances Manual CA22335). They are not main-rate plant and machinery, and haven’t been since 2012. That single classification point rules out the 100% “Full Expensing” first-year allowance. It also rules out the 2026 Budget’s new 40% first-year allowance and the 18%-to-14% main-pool writing-down allowance cut, because both reliefs apply only to main-rate assets.

What solar actually gets is the Annual Investment Allowance. This gives 100% relief on qualifying spend, up to a £1 million annual cap. That cap is shared across all your qualifying capital expenditure for the year.

On anything above that cap, you get a 50% special rate first-year allowance. You then write down the remaining balance at 6% a year in the special rate pool.

For most single-site commercial systems (see our cost-by-system-size guide), the whole spend sits comfortably inside the AIA cap. That’s only true, though, if the allowance hasn’t already been used elsewhere in the same accounting year. We model that interaction rather than assume it, as part of our ROI and energy modelling.

Ownership also means you carry every risk that comes with the asset. That includes inverter replacement, panel degradation, roof penetrations, insurance, and whatever the maintenance contract doesn’t cover. On the balance sheet, it’s the simplest of the three routes. It shows up as a fixed asset, depreciated over its useful life, plus any loan liability if you didn’t pay cash.

Equipment lease: low capital, but check who actually gets the tax relief

A lease looks like a halfway house: you get the system without the upfront capital. But the tax position is the detail most guides skip. Under general capital allowances rules, it’s normally the lessor, not you, who owns the asset and claims the allowances. That’s because entitlement follows ownership.

There’s an exception: the “long funding lease.” When a lease meets HMRC’s long-funding-lease tests, entitlement to claim capital allowances can shift to the lessee instead. But the lessee must elect into that treatment on their tax return. If they do, HMRC restricts the deduction they can claim for the lease rentals to compensate (HMRC Business Leasing Manual, BLM42010).

In practice, don’t assume a solar lease hands you any capital allowance at all. Check which side of that line your specific contract falls on first.

From 2026, leases also look different on the balance sheet. Under the FRC’s Periodic Review 2024 changes to FRS 102, the old operating-lease-vs-finance-lease split largely disappears. This applies to accounting periods starting on or after 1 January 2026.

Almost all leases now go on the balance sheet as a right-of-use asset and a matching lease liability. Only short-term leases (12 months or less) and low-value-asset leases stay exempt. A UK GAAP reporter could once keep an equipment lease off the balance sheet as an “operating lease.” Generally, they can no longer do that.

PPA: zero capital, but read the contract before you assume it’s off balance sheet

Under a PPA, a developer installs, owns and maintains the system on your roof or land. They sell you the electricity it generates, usually below your current grid tariff, for a fixed term. UK commercial solar PPAs typically run 10 to 25 years (Solar Energy UK — Power Purchase Agreements). The price is either a flat rate for the term or index-linked, using RPI/CPI or a fixed annual escalator.

The developer carries all the operations-and-maintenance risk for the contract’s life. You claim no capital allowances, because you own no asset. The trade-off for zero capital outlay and transferred technical risk is that all the tax relief sits with the developer. It’s priced into their tariff rather than handed to you directly.

The balance-sheet question is the one that catches boards out. A PPA structured as a genuine service contract stays off the balance sheet. Here, you’re simply buying kilowatt-hours, with no right to direct how the developer uses a specific, identified asset. The per-kWh cost runs through the P&L as an operating expense.

But both IFRS 16 and, from 2026, FRS 102 test the substance of the arrangement, not its label. If the contract effectively gives you the right to control the use of an identified system, the arrangement counts differently.

For example, you might have exclusive rights to all the output of a specific array, with no real substitution right for the developer. In that case, the arrangement counts as an embedded lease. It then lands back on the balance sheet as a right-of-use asset and liability anyway. Get a second opinion on that distinction before signing — not after your auditor raises it.

A decision framework, not a rule of thumb

The right route depends on how these five questions come out for your organisation. It’s not simply about which option is cheapest per kWh in isolation:

Do you have unused Annual Investment Allowance this year? If yes, outright purchase captures tax relief a PPA simply can’t offer you.
What’s your cost of capital versus the PPA’s implied discount rate? A PPA is, in effect, a loan at whatever rate its tariff embeds. That rate is sometimes cheaper than your overdraft, sometimes not.
How sensitive are your banking covenants to new balance-sheet liabilities? Post-2026, a lease or an embedded-lease PPA both add a new balance-sheet liability. That liability wasn’t always there before.
Do you want to own maintenance risk for 20+ years, or transfer it? Price a PPA’s fixed-term O&M cover against your own maintenance budget — don’t assume it’s free.
What happens at the end of the term? Ownership never ends. A lease or PPA needs an explicit end-of-term clause — buy-out, removal, or contract renewal. Review that clause before signature, not at year 24.

None of these has a universally right answer. A well-capitalised business with unused AIA headroom usually does better buying outright. A business that wants zero capital exposure and no O&M risk often prefers a PPA, even at a lower lifetime return.

We model all three routes against your actual tax position, cost of capital and balance-sheet appetite. We also review the heads of terms or contract before you commit, through our PPA and financing advice service. The best structure is the one that fits your business, not simply the first one pitched to you.

How much does commercial solar cost in 2026?

John Shaw — Thu, 11 Jun 2026 09:14:00 GMT

If you’re pricing a commercial solar installation in the UK in 2026, the honest answer is simple. Cost depends almost entirely on system size. Everything else matters far less than most sales material suggests.

Per-kWp cost falls sharply as scale increases. At 100kW, expect roughly £800–£1,000/kWp. At 1MW and above, that drops to £600–£720/kWp.

This happens because fixed costs — scaffolding, cabling, commissioning, project management — spread over more panels as systems grow larger. The underlying technology stays the same; only the economics of scale change.

Cost by system size

System size	Typical installed cost	Typical payback	Best fit
100kW	£80,000–£100,000	5–7 years	Offices, standalone retail, small warehouses (~500–650m² roof)
250kW	£175,000–£215,000	4.5–6.5 years	Larger warehouses, distribution units, business parks (~1,300–1,600m²)
500kW	£300,000–£375,000	4–6 years	Large distribution centres, factories, cold storage (~2,600–3,200m²)
1MW+	£600,000–£720,000+	4–6.5 years	Major logistics/manufacturing campuses, multi-building estates, ground-mount

These are installed-cost ranges, not fixed quotes. Site condition, roof type, grid connection distance, and current market pricing all move the final number. We cover each band in more detail on our commercial solar cost pages.

The tax mistake almost everyone makes

Most commercial-solar marketing tells you that solar qualifies for the UK’s 100% “Full Expensing” first-year tax relief. It doesn’t — and getting this wrong changes your real, net-of-tax payback.

Since 2012, HMRC has classified solar panels as “special rate” expenditure, not main-rate plant and machinery. This sits under its capital allowances rules (Capital Allowances Manual CA22335). Full Expensing — the 100% first-year deduction with no cap — applies only to main-rate assets. Solar doesn’t qualify.

What solar actually gets:

The Annual Investment Allowance (AIA) gives 100% relief on qualifying expenditure. The cap is a shared £1 million a year across all your qualifying capital spend. For most single-site commercial arrays, this comfortably covers the whole cost.
Above the AIA cap, the 50% special rate first-year allowance on the remainder.
The balance after that, written down at 6% a year in the special rate pool.

The 2026 Budget changed the main pool. It introduced a new 40% first-year allowance and cut the main-rate writing-down allowance from 18% to 14%. However, none of that touches solar’s special-rate treatment — those changes apply to a different pool entirely.

In practice, this often works in the business’s favour. Say your business hasn’t used its AIA elsewhere in the accounting year. A system at any of the four bands above will typically fall entirely within the £1m cap. That gets you a genuine 100% first-year deduction — just via the AIA, not “Full Expensing.”

If your business has already committed the AIA to other capital spend, the real relief looks different. It’s 50% in the first year, then 6% a year after that. This changes the payback maths meaningfully.

We model this against your actual capital programme, not a generic assumption. See our energy and ROI modelling service.

What actually drives the cost within a band

Roof type and condition. A straightforward flat or low-pitch commercial roof in good condition is the cheapest scenario. Ageing sheeting, asbestos-containing roofing, and roofs that need reinforcing before they can take the load all add cost. Assess these before you accept a quote, not after.
Grid connection. Systems above the smallest scale go through Engineering Recommendation G99. This means a DNO application and, for larger systems, a technical capacity assessment. Where local grid headroom is limited, reinforcement costs can be significant and easily underestimated, particularly in rural areas.
MCS accreditation. The MCS solar PV installation standard (MIS 3002) applies only up to 50kWp. Above that, treat every band as a genuine commercial project. Specify, commission and warranty it properly — don’t just scale up a domestic-scheme template.

Getting a number you can actually rely on

A quote is only as good as the assumptions behind it. Before you commit capital, an independent feasibility study gives you the real, site-specific numbers. That means actual roof or land capacity, realistic yield, and grid headroom. It also means capex and payback net of the capital allowance treatment that genuinely applies to your business — not a generic per-kWp rule of thumb.