The questions people actually ask before going solar.

Photovoltaic cells in each module convert sunlight directly into direct current (DC). Strings of modules feed an inverter, which converts DC into grid-quality alternating current (AC) and pushes it into your LT or HT panel. Your loads consume that power first; only the shortfall is drawn from the grid.

In a grid-tied system the inverter continuously synchronises with the utility supply, voltage, frequency and phase, so the changeover is invisible to your equipment. Any surplus is exported through a bidirectional meter and credited or banked, depending on your state's metering rules.

On-grid (grid-tied) systems work alongside the utility supply and carry no batteries. They are the lowest cost per unit generated and the right answer for almost every commercial and industrial site, because the grid itself acts as the buffer.

Off-grid systems run independently with a battery bank, and are used where there is no reliable grid at all. Batteries add substantial capital cost and a replacement cycle, so off-grid is rarely economic for a factory.

Hybrid systems sit between the two: grid-tied, with a battery sized only for critical loads. We specify hybrid where a genuine outage-continuity requirement exists, not as a default.

Not from a standard grid-tied system. When the grid goes down, the inverter shuts off automatically, this is a mandatory safety feature called anti-islanding, and it protects utility linesmen working on the line.

If you need generation to continue through an outage, that requires a hybrid inverter with battery storage, or integration with your existing DG set so solar can offset diesel during running hours. Both are things we design for explicitly; tell us at feasibility stage.

It is set by your daytime consumption, not by your roof size or your total bill. As a planning rule of thumb in Tamil Nadu, 1 kWp generates roughly 1,450–1,600 units a year and needs about 90 sq ft of shadow-free area, and a modern module is around 550–600 Wp, so roughly two modules per kWp.

Two ceilings then apply: your usable shadow-free area, and your sanctioned load, which most DISCOMs cap solar capacity against. Our savings estimator gives you a 30-second first pass; the real number comes from your bills and a load profile.

We are a solar PV project development and consulting company with in-house EPC capability, established in 2013. In practice that means we can be engaged three ways: as a pure advisor (feasibility, structural and electrical design, yield modelling, tender evaluation), as a turnkey EPC contractor, or as the developer who builds, owns and operates the plant and sells you the power under a BOOT arrangement.

Design is never sub-contracted. The same team that models your yield signs off the drawings that get built.

indicative turnkey bands, inclusive of structure, modules, inverters, cabling, protection and commissioning:

• 100 kWp, ₹45–50 lakh
• 250 kWp, ₹1.05–1.15 crore
• 500 kWp, ₹2.0–2.2 crore
• 1 MWp, ₹3.8–4.2 crore

Per-watt cost falls as capacity rises. What moves the number is roof type (metal deck is cheaper to mount than RCC ballast), module and inverter brand, cable runs, and whether a canopy or ground structure is involved. Full cost breakdown by capacity.

On C&I grid tariffs of ₹8–11 per unit, a well-engineered CAPEX rooftop plant sized to daytime load typically pays back in 3.5–5 years, then delivers near-free power for the remaining 20+ years of module life.

The single biggest lever is self-consumption. A plant that exports half its generation into an unfavourable metering regime will not hit those numbers, which is why we size to your load curve rather than to your roof. Why most payback calculations are wrong.

Yes, under a RESCO or BOOT structure, Goggles Energy or a financing partner funds, builds, owns and maintains the plant on your site. You sign a long-term power purchase agreement and pay only for the solar units you actually consume, at a tariff below your grid rate. There is no capital outlay and savings begin in month one.

Under BOOT the asset transfers to you at the end of the term, typically after 10–15 years. Compare CAPEX, RESCO, BOOT and open access side by side.

For commercial and industrial consumers, the central rooftop subsidy schemes are generally not applicable, those are aimed at residential consumers. The incentive that matters for a business is accelerated depreciation on the asset, which materially improves post-tax IRR for a profit-making company.

State-level benefits vary, and open-access charges, banking rules and any exemptions change from year to year. We model your project on the rules in force at the time of your assessment rather than quoting a headline number, and we will tell you plainly if an incentive you have heard about does not apply to you.

Tax and subsidy treatment depends on your entity and current policy. Confirm the position with your finance team or auditor before it is built into a business case.

Under CAPEX the plant is your asset from day one and can be funded from internal accruals or a term loan; solar is a well-understood asset class for Indian lenders when the generation estimate is bankable and the O&M is contracted.

Under RESCO or BOOT, the asset sits on the developer's books during the PPA term, you buy power, not equipment, so nothing is capitalised. Which structure suits you is usually a treasury question rather than an engineering one, and we model both.

Not if the mounting system is designed for your roof rather than pulled from a vendor's default table. On RCC we prefer non-penetrative ballasted systems that leave the membrane intact. On metal deck we use standing-seam clamps or purlin-fixed brackets with the correct sealing detail at every fixing.

Where penetrations are unavoidable, they are detailed, sealed and documented so your waterproofing contractor can honour the warranty. We record every fixing in the as-built drawings.

A framed rooftop array typically adds in the region of 12–20 kg per square metre of covered area as dead load; a ballasted system on RCC adds more, because the ballast is what resists uplift. Those are planning figures, not a design input.

The number that decides feasibility is not the dead load on its own, it is dead load plus wind uplift, checked against the residual capacity of your structure. That is a structural assessment, and we do it before anything is ordered.

Every mounting system we design is checked to IS 875 (Part 3) for the basic wind speed at your location, with the terrain, topography and importance factors that actually apply to your site, plus the edge and corner zones of the roof, where uplift is highest and where generic designs fail first.

Coastal Tamil Nadu sites carry higher basic wind speeds than inland ones, and the design reflects that rather than averaging it away. What a real structural assessment checks.

Yes, and it is much cheaper if the first phase anticipates it. Where you tell us expansion is likely, we size the AC infrastructure, cable routes, earthing and DISCOM sanction for the eventual capacity, then populate the roof in phases.

Retro-fitting capacity onto a plant designed only for phase one usually means re-doing the interconnection and re-applying to the DISCOM, which costs more than the panels.

Shading is modelled in 3D at design stage, from parapets, water tanks, cooling towers, ducting, adjacent blocks and trees, across the year, not just at noon. The output is an hour-by-hour loss map, which decides the layout.

Where shading is unavoidable on part of the array, module-level electronics (optimisers or micro-inverters) stop one shaded module from dragging down its whole string. We use them where the yield gain justifies the cost, not as standard.

Net metering uses a bidirectional meter that records both what you import from the grid and what you export to it. You are billed on the net difference, so a unit exported at noon offsets a unit imported at night.

Two variants change the economics substantially. Under gross metering, everything you generate is sold to the utility at a fixed feed-in tariff and everything you consume is bought at the retail tariff, so the spread, not your own consumption, sets the return. Under net billing, exported units are credited at a rate lower than the retail tariff, which strongly rewards self-consumption.

Which applies to you depends on your state, your consumer category and your capacity. Net metering and banking for C&I consumers in Tamil Nadu.

Yes. Regulatory liaison is part of our scope, not an extra: net- and gross-metering applications, technical feasibility clearance, meter testing and installation, CEIG / electrical inspectorate approval of the installation, and where relevant open-access registration and contracting.

We manage it from application to energisation and keep you informed of where the file sits, DISCOM timelines are the most common cause of schedule slip on an otherwise clean project, so we plan around them from day one.

Open access lets you source power from a solar plant located somewhere else and wheel it to your facility over the utility network, paying wheeling and related charges. It is how a site scales past what its own roof can hold, captive, group captive or third-party.

Whether it beats a rooftop plant depends entirely on your state's open-access charges, banking provisions and your load profile, and those move. It suits multi-MVA consumers; it rarely suits a site whose whole demand fits on its own roof. Open access compared with CAPEX and RESCO.

A typical 200 kWp – 1 MWp rooftop runs 8–14 weeks from contract to commissioning. Multi-MW plants run 16–20 weeks. Roughly: two to three weeks of detailed design and approvals in parallel with procurement, three to six weeks on site, then metering and inspectorate clearance.

Work is sequenced around your production schedule, most of our industrial rooftops are built without stopping the plant below.

Solar has no moving parts, so maintenance is mostly cleaning and inspection. A standard programme is monthly module cleaning, more often on dusty or high-pollution sites, less in monsoon, quarterly thermographic inspection to find hot cells and loose terminations, and annual I-V curve testing to catch degradation early.

All of it sits under an in-house O&M contract with remote monitoring, so a string that stops performing raises an alert in days rather than showing up as a disappointing annual number.

Three layers, and they are different things. Module product warranty covers manufacturing defects, typically 10–12 years. Module performance warranty guarantees a minimum output over time, commonly around 25 years to roughly 80–85% of rated output, depending on the manufacturer. Inverter warranty is usually 5–10 years, extendable.

On top of the equipment warranties, we provide a workmanship warranty on the installation, and a bankable O&M contract can carry a generation or performance-ratio guarantee. Exact terms are stated in your proposal, we will not quote a warranty we cannot put in the contract.

Every plant we commission is monitored at string level. You get a dashboard showing generation against the modelled expectation and a performance ratio benchmark, the honest measure, because it normalises for irradiance and temperature so a cloudy month doesn't look like a fault.

Deviations trigger alerts to our team. You receive a periodic performance report you can hand straight to finance or to your sustainability reporting.