Alectrona
Commercial guideThere is no single best solar cell technology. The one that earns its place on your roof depends on the geometry, the temperature it runs at and the funding route, which is a modelling question rather than a spec-sheet headline.
These are representative example reviews, not yet-collected customer feedback. They are written to illustrate the kind of feedback Alectrona aims to earn and are shown as design placeholders while we gather and verify reviews from our first commercial clients. Alectrona is the commercial solar trading brand of RVTC LTD.
What set Alectrona apart was the documented design pack. We had quotes from three installers, but only Alectrona handed us a full set of drawings, a single-line diagram and a design referencing BS 7671 and the G99 connection process. The whole thing read like an engineering submission rather than a sales brochure. Our M&E consultant reviewed it and signed it off without a single query. That gave the board the confidence to release the capital.
Other firms priced our roof off a satellite image and a desktop guess. Alectrona flew an in-house drone survey, fully insured and flown by a qualified commercial drone pilot, and built a 3D model of the actual roof. It picked up plant, vents and a parapet line that a flat aerial photo had completely missed, which changed the panel layout. I would rather find that out at design stage than on the day the scaffold goes up. The accuracy of that survey is the reason I trusted everything that followed.
As a finance director I was wary of being oversold a system bigger than we could use. Alectrona modelled the array against our actual half-hourly consumption data rather than an annual total, so it is sized to what we genuinely draw on site during the day. They were honest that exporting surplus is worth far less than self-consumption, and built the design around that. The capital case stacked up because the engineering was honest, not because the numbers were inflated.
We were undecided between buying outright, leasing and a PPA. Alectrona laid out all three side by side with the pros and cons of each against our balance sheet, instead of pushing the one that pays them best. They were clear about where a PPA makes sense and where capex wins, and pointed us at our own accountant for the tax treatment. The survey and design took a little longer than I expected, but the thoroughness was worth the wait. Genuinely consultative.
The install crew were tidy and well run, and worked to a clear CDM 2015 plan with a proper site induction and RAMS. What impressed me most was the handover. We received a full commissioning pack with the IEC 62446-1 test results, certification, O&M documentation and an as-built record for our maintenance team. As the people who have to live with this asset for the next twenty years, having that paperwork in order matters enormously. Nothing was left loose.
I expected the usual hard sell and got the opposite. After surveying our site Alectrona told us one roof section was not worth covering because of shading, and that a smaller, well-sited array was the better investment than filling every square metre. There was no commission-driven upselling and no pressure. For a six-figure capital project, that straight talk is exactly what you want from the people advising you. We will be using them again on our second site.
There is no single best solar cell technology for a commercial roof. PERC, TOPCon and HJT are three generations of silicon cell, each with a real engineering case, and the one that earns its place on your building depends on the roof geometry, the shading, the temperature it runs at and the funding route, rather than on a spec-sheet headline.
PERC is the p-type cell that carried the last decade of solar. TOPCon is the n-type cell that has become the volume default for new commercial modules, with a passivated contact that lifts efficiency and softens annual degradation. HJT is the n-type heterojunction cell that tends to lead on temperature behaviour and bifaciality, at a higher cost per watt. We size every array around the module that gives the best modelled kWh per kWp for your roof, then name its bankability scheme, grade and quarter and re-verify it before contract.
PERC stands for Passivated Emitter and Rear Cell, a p-type design that added a rear reflective layer to the older cell and became the industry workhorse. It is mature, well understood and widely second-sourced, which keeps it financeable and straightforward to support over a long asset life.
Two engineering limits matter on a commercial roof. A p-type cell is prone to light-induced degradation in its early life, and its temperature coefficient is typically weaker than the n-type cells, so it loses a little more output on a hot roof. New commercial modules have largely moved to n-type, so PERC reads today as the outgoing baseline the newer cells are measured against rather than the cell we reach for first on a new array.
TOPCon stands for Tunnel Oxide Passivated Contact, an n-type cell that adds an ultra-thin oxide layer and a passivated contact to cut the electrical losses where the cell meets its wiring. In practice that tends to mean a higher cell efficiency than PERC, a gentler first-year and annual degradation, a stronger temperature coefficient and a higher bifaciality factor, so a TOPCon module on the right roof returns more kWh per kWp of installed capacity over its life.
It has become the volume technology for new commercial modules, which means broad bankable supply and competitive cost per watt. The exact efficiency, degradation and temperature figures belong to the specific module datasheet, and the yield gain on your building is the number the PV*SOL model returns, rather than a figure we carry in from another site.
HJT, heterojunction technology, sandwiches a crystalline silicon wafer between thin amorphous-silicon layers, which passivates the cell extremely well. The engineering signature is a very low temperature coefficient, so an HJT module sheds less output as the roof heats through the day, a high bifaciality factor, and a low annual degradation rate. Those properties tend to favour HJT where a roof runs hot or a rear-side yield is available.
The trade-off is cost. HJT uses more silver and a different process, so it usually carries a higher cost per watt than TOPCon, and the case for it rests on whether the extra modelled yield pays for the premium on your specific roof. We confirm that in the model rather than assume it.
Passivated Emitter and Rear Cell, the mature p-type design that carried the last decade of solar. Widely second-sourced and straightforward to support, but largely superseded on new commercial arrays.
Tunnel Oxide Passivated Contact, the n-type cell that has become the volume technology for new commercial modules, with broad bankable supply and competitive cost per watt.
Heterojunction technology, an n-type cell that passivates extremely well and leads on temperature behaviour and bifaciality, at a higher cost per watt.
A cell datasheet does not pay back a commercial system; modelled kWh per kWp on your roof does. Two effects decide whether a higher cell efficiency or a better temperature coefficient turns into real generation.
The first is heat. A commercial roof can run far above the 25°C laboratory test condition on a clear day, and a stronger temperature coefficient holds more output through that heat, which is where TOPCon and HJT separate from PERC. The second is the rear side. A bifacial module earns extra yield only from light reflected off the surface behind the array, so the gain is governed by the surface reflectance, or albedo, and by how the array is mounted and tilted. A light-coloured flat roof with an air gap under a tilted array can present a real rear-side gain; a dark membrane with modules laid close to it presents very little. We model the bifacial contribution for your roof and its mounting in PV*SOL rather than apply a generic uplift.
The mounting method shapes which cell technology pays, because it sets the roof temperature the cells run at and the rear-side light a bifacial module can collect.
On a pitched metal roof, a non-penetrative clamp that grips the standing seam fixes the array without piercing the sheet, which protects the weather warranty; the modules sit close to an often dark surface, so any bifacial gain is modest and the cell choice turns on efficiency and temperature behaviour. On a flat roof, a ballasted, weight-held system holds the array down with weight rather than fixings and lifts it to a tilt, which opens an air gap and a rear-side view of the roof surface, so a bifacial n-type cell on a light deck can earn its premium. The structural survey confirms what your roof can carry before any ballast or fixing is specified, and the PV*SOL model confirms the yield each option returns.
The cell technology sets two numbers that decide how much energy the array still makes years from now: the first-year power loss and the linear annual degradation that follows it. A p-type PERC cell carries light-induced and light-and-elevated-temperature-induced degradation in early life, so it tends to start with a larger first-year drop and a steeper annual slope. The n-type cells avoid the boron-oxygen mechanism behind that early p-type loss, so TOPCon and HJT generally start higher and fade more gently, with HJT usually quoting the lowest annual figure of the three. Those are the headline reasons an n-type module can out-generate a higher-nameplate p-type one over a twenty-five to thirty-year asset life.
The figures only matter if they are warranted, and a performance warranty is the maker's commitment to a minimum retained output at year one and at end of term. The standard reference for how PV modules are tested for these characteristics is the IEC 61215 design-qualification series, with IEC 61730 for safety; a bankable datasheet states the standards the module is certified to, and we read the certified figures rather than the marketing curve. The replacement-risk side is the product warranty, the years the maker will repair or replace a failed module, which is a separate term from the performance warranty and often the one that varies most between brands. We weigh both when we shortlist, which is the bankability logic set out in our guide to bankable Tier 1 panels, and we name the scheme, grade and quarter of the specific module and re-verify that status before contract.
It can, because the cell type changes the module's electrical character at the array's working temperature, and the string design is built around those numbers. The temperature coefficient of open-circuit voltage decides how far a string's voltage rises on a cold, bright morning, which is the worst case the design has to stay inside the inverter's maximum input voltage. HJT and TOPCon tend to hold a gentler voltage coefficient than older PERC, which can change how many modules sit in a string and how the strings are grouped onto the inverter's trackers. We size the string length from the specific module's datasheet against the inverter window and the local design temperatures, rather than from a rule of thumb.
Bifacial n-type modules add a second consideration, because the rear-side yield lifts the current the system has to carry, so the inverter, the DC cabling and the protection are rated for the combined front-and-rear output rather than the front nameplate alone. None of this rules a technology in or out; it means the module and the balance-of-system are designed together. Where the modelled array output runs ahead of the connection the network will allow, the design may also need export limitation, which we cover in the grid connection queue guide, and the feasibility read that ties the module choice to the connection is set out in our feasibility study page.
The cell technology has little direct bearing on maintenance, because a commercial PV array of any cell type is a low-intervention asset: there are no moving parts in the modules, and the recurring work is inverter monitoring, occasional cleaning where soiling is heavy and periodic electrical inspection. What the cell type does shape is the energy the array delivers across that maintenance life, through the temperature behaviour and degradation already described, so the running-cost question is really a lifetime-yield question. Our commercial solar maintenance guide sets out the recurring regime, which is broadly common across the technologies.
Two cell-specific points are worth naming. A bifacial layout that earns real rear-side yield can carry a slightly higher cleaning and inspection consideration, because the rear glass and the surface that feeds it both affect output, and a dual-glass module is heavier, which is a structural input the survey checks rather than a running cost. And because HJT and the better n-type modules degrade more slowly, the array holds more of its rated output later in life, which is where the lifetime generation difference between the technologies actually shows up. We model that lifetime profile for your roof, and the capital side is survey-led, which we explain in our commercial solar cost guide rather than quoting a figure here.
A cell datasheet does not pay back a commercial system; modelled kWh per kWp on your roof does.
Our own insured pilot flies your roof and captures the real geometry and shading, so the design starts from your building instead of a satellite guess.
Booked to suit your operating hours
We model the array in bankable-grade software, size it around your daytime load, and set out generation, savings and payback across three funding routes.
Modelled, not promised
Designed and installed to BS 7671, commissioned to IEC 62446-1, connected under G99 and run under CDM 2015. Alectrona is typically the Principal Contractor.
Outside MCS, assured by the non-MCS stack
A 12-month defects period backed by an Insurance-Backed Guarantee, then ongoing operations and maintenance so the asset keeps earning for its full working life.
Kept performing, year on year
Last updated July 2026
We do not publish a from-price or a per-kWp figure for any of the three technologies, because a genuine number needs the drone survey and the PV*SOL design for your specific roof. The survey establishes what the roof can carry, the model shows which cell returns the best kWh per kWp for your building, and the price follows that design as one fixed figure. Our commercial solar cost guide sets out how that figure is built.
The cell technology rarely drives the programme; module availability does. TOPCon is the volume default, so it is usually the most readily sourced, while a specific HJT module, or a particular module format, can carry a longer lead time. The dominant timeline factors are the structural survey, the network connection and procurement, rather than the cell type. We confirm the specific module's availability before contract; our installation timeline guide sets out the full programme.
There is no single best cell technology. PERC, TOPCon and HJT each have a genuine engineering case, and the right one depends on your roof temperature, shading, geometry and funding route. TOPCon is the volume default on most new commercial modules, HJT leads where a roof runs hot or a rear-side yield is available, and PERC is now the outgoing baseline. We model each option in PV*SOL and specify the one that returns the best kWh per kWp for your building.
PERC is a p-type cell; TOPCon and HJT are n-type. The n-type cells are not prone to the early light-induced degradation that affects p-type, and they tend to hold a stronger temperature coefficient and a higher bifaciality factor, so they shed less output on a hot roof and can pick up more rear-side light. The exact figures belong to the specific module datasheet, and the yield difference on your roof is what the PV*SOL model returns.
TOPCon usually offers a higher efficiency, gentler degradation, a stronger temperature coefficient and a higher bifaciality factor than PERC, and it has become the volume technology for new commercial modules, so supply is broad and bankable. Whether that turns into a better return on your roof is a modelling question rather than a given. We confirm the kWh per kWp gain for your geometry before specifying, rather than assume it.
It depends on the roof. HJT carries a very low temperature coefficient and a high bifaciality factor, so it can lead on yield where a roof runs hot or offers a reflective rear surface, but it tends to carry a higher cost per watt than TOPCon. The case rests on whether the extra modelled yield pays for the premium on your building, which we test in PV*SOL rather than assume.
Only the model can tell you, because the rear-side gain depends on the surface reflectance behind the array and how the array is mounted and tilted. A light flat roof with a tilted array that opens an air gap can present a real rear-side contribution; a dark membrane with modules laid close to it presents very little. We model the bifacial contribution for your specific roof and mounting in PV*SOL rather than apply a generic uplift.
It matters more, because at this scale the trust signal is engineering and bankability rather than a domestic certification. A system above 50 kWp sits outside the MCS scheme, so RVTC LTD assures it through the structural survey, the PV*SOL model and CDM 2015 duties, and specifies a bankable module with its scheme, grade and quarter named and re-verified before contract. The cell technology is chosen on modelled yield for your roof rather than on a headline.
A guide can only take you so far. The figure you get is modelled from your own half-hourly load and a system sized from the on-site drone survey. No obligation, and systems this size sit outside the domestic MCS scheme, so the assurance is the engineering stack.