A textile manufacturer in Surat paying ₹8.50/unit for industrial grid power has two paths to solar: spend ₹1.2 Cr to own a 500 kW rooftop system (Capex model), or sign a 20-year Power Purchase Agreement (PPA) with a solar developer at ₹4.50/unit and let someone else own the system (Opex model). The financial outcomes are dramatically different—and the right choice depends on the manufacturer’s balance sheet, tax position, and appetite for asset ownership. For EPCs serving C&I customers in India, understanding the Opex model is not optional: it is the deal structure that converts “too expensive” prospects into signed projects.
The solar Opex model is a financing and ownership structure where a third-party developer owns, installs, and maintains a solar system at the customer’s site, and the customer pays only for the electricity generated—typically at ₹3.50–₹5.50/unit under a Power Purchase Agreement (PPA) versus ₹7–₹10/unit grid tariff. The customer pays zero capital, the developer recovers their investment through 15–25 years of electricity sales, and the customer captures 30–55% immediate savings on per-unit energy cost. For EPCs, Opex projects require detailed BOQ and SLD engineering that satisfies both the developer’s bankability requirements and the customer’s DISCOM interconnection—a scope that Heaven Designs delivers as a turnkey engineering package.
This guide uses the PPA Lifecycle Engineering (PLE) Framework — Heaven Designs’ structured approach to the five engineering and documentation stages that make an Opex/PPA solar project bankable, DISCOM-approved, and operational within a predictable timeline.
What Is the Solar Opex Model? The Core Mechanics
The term “Opex model” comes from financial accounting: Opex (Operating Expenditure) is money spent on day-to-day operations—electricity bills, rent, salaries—while Capex (Capital Expenditure) is money spent to acquire long-term assets—equipment, buildings, vehicles. The Opex solar model transforms what would be a Capex asset purchase into an Opex electricity tariff, with the asset owned by a third party.
The mechanics work as follows:
Ownership: A solar developer (also called an ESCO—Energy Service Company, or IPP—Independent Power Producer) owns the solar system, which is installed on the customer’s rooftop or land.
Payment: The customer pays only for the electricity the system generates, at a per-unit tariff specified in the PPA. The customer does not pay for the panels, inverters, structure, installation, maintenance, or insurance—the developer bears all these costs.
Revenue recovery: The developer recovers their capital investment, operating costs, and profit through 15–25 years of electricity tariff payments from the customer.
Risk allocation: Performance risk (does the system generate what it promised?) sits with the developer. The customer’s only risk is that the developer fails to honor the PPA—which is mitigated through developer creditworthiness due diligence and PPA contract terms.
Definition. A Power Purchase Agreement (PPA) is a long-term contract between a solar developer (the seller) and an electricity consumer (the buyer) that specifies the volume of solar electricity to be sold, the tariff per unit, escalation clauses (how the tariff changes over time), duration (typically 15–25 years), performance obligations, and termination provisions. PPAs are the financial instrument that enables the Opex model—they give the developer the contracted revenue stream needed to raise project finance and give the customer the price certainty that justifies removing grid power from their budget.
In India, the Opex model is most commonly used for C&I (Commercial and Industrial) rooftop solar projects above 100 kW—factories, warehouses, shopping malls, educational campuses—where the energy bill is large enough to justify the legal and structuring overhead of a PPA. The model is also used for utility-scale projects where SECI or state DISCOMs are the PPA offtaker. According to Mercom India’s C&I Solar Report 2025, the Opex/PPA model accounted for approximately 35–40% of Indian C&I rooftop solar additions in FY25, up from 20% in FY22—driven by increasing CFO familiarity with PPA structures and improved developer access to project finance. For a detailed framework comparing all three ownership models from a CFO’s perspective, see Capex vs Opex vs RESCO: the CFO decision framework. The IREDA financing schemes page provides current interest rates and DSCR requirements for Opex solar project loans—key inputs for developer financial modeling. For a reference to a large-scale PPA structure, consider Acme Solar’s 300 MW project in Rajasthan, executed under a 25-year PPA with SECI at ₹3.05/unit with waived transmission charges—a structure that illustrates the long-term cost certainty that PPA offtakers value.
Opex vs Capex vs RESCO: Understanding the Three Ownership Models
Indian solar procurement operates across three distinct ownership models. Understanding the differences is essential for EPCs advising customers and developers structuring deals.
| Dimension | Capex Model | Opex/PPA Model | RESCO Model |
|---|---|---|---|
| Who owns the system | Customer | Third-party developer | RESCO (specialized company) |
| Customer upfront payment | Full system cost (₹50–₹80 lakh/500 kW) | Zero | Zero or nominal |
| Customer pays per unit | No (generation is free after Capex) | Yes (₹3.50–₹5.50/unit PPA tariff) | Yes (typically similar to PPA) |
| Who handles O&M | Customer (or paid O&M contract) | Developer | RESCO |
| Who claims depreciation | Customer | Developer | RESCO |
| Who claims DISCOM net-metering credits | Customer | Shared / developer (contract-specific) | RESCO |
| ITC / government incentive capture | Customer | Developer | RESCO |
| Asset on balance sheet | Yes (improves fixed asset base) | No (off-balance-sheet) | No |
| Best for | Cash-rich businesses, high tax bracket | Cash-constrained businesses, conservative CFOs | Same as Opex; RESCO structures more complex |
| Payback period | 4–7 years | Not applicable (NPV comparison vs grid tariff) | Not applicable |
Field tip. For a customer choosing between Capex and Opex, the financial pivot is the customer's effective tax rate. A business in the 30%+ tax bracket benefits substantially from Capex: the 40% accelerated depreciation on solar assets under Schedule II of the Income Tax Act 1961, plus GST input credit on the system purchase, can reduce the effective Capex cost by 25–35%. A business with low taxable income or loss carryforwards captures minimal benefit from depreciation—making Opex's zero-capital-outlay more attractive. EPCs who ask about their customer's tax position before recommending a structure close more deals.
How a Solar PPA Is Structured: Key Commercial Terms
A PPA is a legal and financial document as much as an engineering one. EPCs need to understand the key commercial terms to interpret what they are engineering for and to explain the deal structure to their customers.
Tariff and escalation clause: The PPA tariff is the per-unit price the customer pays for solar generation. Most Indian C&I PPAs are structured with either a fixed tariff for the full term (price certainty for the customer) or a tariff with an annual escalation of 2–4% (which indexes partially to inflation while remaining well below projected grid tariff escalation). The escalation rate is the primary negotiation variable in most PPA deals.
Capacity and minimum offtake: The PPA specifies the system capacity (e.g., 500 kW) and may include a minimum offtake provision—a minimum annual kWh the customer agrees to pay for, regardless of actual consumption. This protects the developer against demand reduction scenarios. EPCs need to model the customer’s load profile carefully before the PPA is signed to confirm that the contracted minimum offtake is achievable.
Performance guarantee: The developer guarantees a minimum annual generation level (typically 95% of the PVsyst P90 yield). If generation falls below this threshold, the developer compensates the customer or reduces the tariff. This shifts the performance risk clearly to the developer, which is one of the Opex model’s key attractions. For the engineering team, this means the PVsyst yield model must be bankable and defensible—a P90 estimate that turns out to be optimistic creates warranty claims.
Term and termination provisions: Indian C&I PPAs typically run 15–25 years. Early termination by the customer typically involves a buy-out payment covering the developer’s remaining investment, which can be substantial in years 1–10. EPCs who help customers understand this termination risk—and design systems that meet the contracted term without major component replacements—create durable customer relationships.
System transfer provisions: Many PPAs include a right-to-purchase clause where the customer can buy the system at a pre-agreed price (typically based on remaining book value) at year 10, 15, or 20. This gives the customer an eventual path to Capex ownership at a fraction of the original cost once the system is partially depreciated.
₹4.50/unit
Typical C&I PPA tariff (India, 2026)
vs ₹7.50–₹9/unit industrial grid tariff
15–25 years
Typical India C&I PPA term
Lock-in period for tariff certainty
30–55%
Customer per-unit cost savings under PPA
PPA tariff vs grid tariff differential, 2026
Zero
Customer capital investment in Opex model
Developer funds 100% of system cost
The PPA Lifecycle Engineering (PLE) Framework
Every bankable Opex/PPA solar project moves through five engineering stages, each with specific deliverables and quality gates. EPCs who understand the full PLE Framework win more projects because they can quote accurate engineering costs and timelines for the entire lifecycle—not just the installation scope.
PLE Stage 1 — Pre-Feasibility and Yield Modeling
The developer needs a bankable PVsyst P50/P90 yield model before they can structure PPA economics and approach lenders. This stage includes site-specific irradiance data from Meteonorm or Solargis, shading analysis from a 3D model, and conservative degradation assumptions based on the proposed ALMM module's technology type. The P90 yield figure becomes the performance guarantee baseline in the PPA. An optimistic P90 creates warranty claims in years 3–5; a conservative P90 undermines the developer's IRR. Heaven Designs' yield models are calibrated for Indian site conditions and accepted by IREDA and PFC lending teams.
PLE Stage 2 — IFC Engineering Design
Issued-for-Construction (IFC) drawings are the complete engineering documentation set that the lender's Independent Engineer reviews and that the DISCOM requires for net-meter application. For an Opex C&I rooftop project, this includes: General Arrangement drawing (GA), Single Line Diagram (SLD), structural assessment and rooftop load calculation per IS 875 Part 3, ALMM-compliant BOQ with module model numbers, inverter specifications, mounting hardware specifications, and cable schedule. Incomplete or non-compliant IFC documentation is the most common cause of DISCOM application rejection and lender due diligence delays.
PLE Stage 3 — DISCOM Approval and Net-Meter Application
For the developer to legally export surplus generation to the grid under net metering (and for the PPA economics to work), the DISCOM must approve both the interconnection and the net meter installation. The SLD and GA from Stage 2 are submitted with the net-meter application. DISCOM processing timelines range from 7 days (Gujarat's progressive DISCOMs) to 45 days (states with slower processing). In states requiring CEIG approval on electrical drawings (Maharashtra, Karnataka), an additional 15–30 days is needed for electrical inspector clearance.
PLE Stage 4 — Construction and Commissioning
This is the EPC execution phase: module delivery verification (EL imaging of received lots), mounting installation, wiring, inverter commissioning, and data logger setup. For an Opex project, the commissioning report must document achieved generation against the PVsyst model for the initial operating period—this is the first data point against the PPA performance guarantee. Any initial shortfall triggers an engineering investigation of shading discrepancies, inverter configuration, or module lot performance variation.
PLE Stage 5 — O&M and Performance Monitoring
The developer's O&M obligation under the PPA requires systematic generation monitoring, soiling loss management (panel cleaning schedule), inverter health monitoring, and annual EL imaging for microcrack detection. Annual generation reports against the PPA performance guarantee baseline are shared with the customer and lender. EPCs who provide ongoing O&M services as part of the Opex project scope create recurring revenue streams that outlast the installation margin.
Watch out. A PPA performance guarantee based on an optimistic PVsyst P50 rather than P90 will trigger warranty claims in most years because actual generation will fall below the guaranteed level. The difference between a P50 and P90 yield estimate for a rooftop system in western India is typically 4–8%. A developer who signs a PPA with P50 as the performance baseline is effectively guaranteeing that the system will underperform in half of all years—creating a structural liability in the contract. Insist on P90 as the performance guarantee baseline and P50 as the financial model basis.
How Opex Projects Work: A Worked Financial Example
A 500 kW C&I rooftop Opex project in Gujarat illustrates the financial structure:
Customer perspective:
- Current grid tariff: ₹8.50/unit (HT industrial tariff)
- PPA tariff agreed: ₹4.75/unit (2% annual escalation)
- Monthly consumption: 60,000 kWh
- Solar generation at 500 kW (4,800 peak sun hours/year): approximately 55,000–58,000 kWh/month
- Monthly savings: (₹8.50 − ₹4.75) × 57,000 kWh = ₹2,13,750/month = ₹25.65 lakh/year
- Capital outlay: Zero
- PPA term: 20 years (with right-to-purchase at year 10)
Developer perspective:
- System cost: ₹2.40 Cr (₹480/Wp fully installed, C&I rooftop)
- Annual PPA revenue (year 1): approximately ₹31.5 lakh (57,000 kWh/month × ₹4.75 × 12)
- Annual O&M cost: ₹3.5–₹4.5 lakh
- Debt service (70% debt at 9.5%, 12-year tenor): ₹18.5 lakh/year
- Developer DSCR (Debt Service Coverage Ratio): 1.5–1.6 — bankable for IREDA project finance
- Developer project IRR (20-year): 14–17% equity IRR
- System transfer option at year 10: Customer can buy at approximately ₹48–₹60 lakh (20% of original cost)
According to Mercom India’s C&I Solar Market Report 2025, the C&I rooftop segment in India added approximately 2.8 GW of new capacity in FY25, with the Opex/PPA model accounting for roughly 35–40% of that volume—up from 20% in FY22. The growth reflects increasing CFO familiarity with PPA structures and growing developer capacity to structure and finance Opex projects at smaller sizes (100 kW and above).
Capex vs Opex: Which Is Right for Your Customer?
CHOOSE OPEX WHEN THE CUSTOMER...
- Has constrained capital or prefers to preserve cash for core operations
- Has low taxable income (cannot capture depreciation benefit)
- Wants zero maintenance responsibility
- Needs price certainty on energy cost for budget forecasting
- Is willing to sign a 15–20 year commitment
CHOOSE CAPEX WHEN THE CUSTOMER...
- Has capital available and is in the 25–30% tax bracket (captures depreciation)
- Wants asset ownership and balance sheet improvement
- Plans to sell or vacate the property within 10 years
- Prefers free generation after payback with no ongoing tariff
- Can manage or outsource O&M effectively
Verdict. For most Indian C&I businesses paying HT industrial tariffs above ₹7/unit, the Opex model delivers immediate per-unit cost savings with zero capital at risk—which is why CFOs across manufacturing, logistics, retail, and hospitality sectors are signing PPAs at an accelerating rate. The Capex model wins when the customer is a high-tax-bracket entity that can fully deploy the depreciation benefit and plans to hold the property long-term. EPCs who can structure both options for their customers win the advisory relationship; EPCs who only know how to sell Capex lose Opex projects to developer-backed competitors.
Things to Know Before Structuring an Opex Project
Developer creditworthiness: The customer’s main risk in an Opex project is developer default or abandonment. Evaluate the developer’s balance sheet, project portfolio track record, lender relationships (IREDA or bank debt), and warranty insurance arrangements. A developer funded by a reputable PE firm or NBFC is materially lower risk than a startup funded only by equity.
Roof ownership and license: The developer needs a legal right to occupy the roof for the PPA term. Roof license agreements—separate from the PPA—must be notarized and reflect the full 15–20 year term plus an option period. Properties with unclear ownership, inherited from family disputes, or under mortgage restrictions require legal due diligence before PPA execution.
Grid tariff trajectory: The Opex model’s economics improve over time as grid tariffs rise while the PPA tariff stays fixed (or escalates modestly at 2–4%). In states with high historical grid tariff escalation (Maharashtra, Tamil Nadu—8–12% average annual increase over the past decade), the long-term savings from an Opex project are substantially higher than a simple year-1 comparison suggests. According to the CEA’s electricity tariff analysis, average industrial electricity tariffs in India have risen at approximately 6–8% annually over the past decade—a trajectory that dramatically improves Opex model NPV calculations modeled against a fixed or modestly escalating PPA tariff. Model the 20-year NPV of savings against projected grid tariff escalation to communicate this to customers.
DISCOM’s third-party PPA framework: Some states have restrictions on third-party PPA structures for rooftop solar—requiring wheeling and banking agreements or specific open-access status for the developer-customer relationship. Gujarat’s distributed generation regulations, for example, are relatively permissive; some other states require additional regulatory approvals for third-party PPA structures. An EPC who understands the state-specific regulatory framework avoids the situation where a PPA is signed but the DISCOM refuses interconnection because the third-party structure was not pre-cleared.
Need bankable engineering documentation for your Opex project?
Download Heaven Designs' sample project deliverables — PVsyst yield summary, IFC-grade GA and SLD, and BOQ with ALMM module specification. Used by developers and EPCs on 100 kW to 10 MW Opex projects.
Get the sample pack →How Heaven Designs Supports Opex/PPA Project Engineering
Every stage of the PLE Framework requires specific engineering deliverables. Heaven Designs delivers the complete engineering stack for Opex C&I rooftop and utility-scale projects, with outputs accepted by IREDA, PFC, DISCOM interconnection teams, and independent engineers.
- Solar Rooftop Detailed Engineering Design — IFC-grade GA, SLD, structural load assessment, ALMM BOQ, and DISCOM net-meter application drawings. Accepted by DISCOMs in all major states and by lender IE review.
- Solar Ground Mount Design — utility-scale ground-mount layouts for Opex projects, including PVsyst P50/P90 bankable yield, tracker vs fixed-tilt comparison, and civil/structural design.
- Solar 3D Pre-Design — 48-hour pre-feasibility 3D shading model and yield estimate for any rooftop. The pre-design output supports developer bankability screening before IFC design investment.
- Site Survey & Land Feasibility — pre-PPA site assessment: shading analysis, structural feasibility, DISCOM feeder capacity, and soiling loss estimate. Identifies technical constraints before PPA terms are set.
- MW-Scale PMC — owner’s engineer services for developers who need independent oversight of EPC contractor execution on larger Opex projects.
- Download sample deliverables — see a complete Opex project engineering package before engaging.
Contact Heaven Designs for an engineering scope estimate for your next Opex/PPA project.
FAQ
What is the difference between the Opex model and the Capex model for solar?
In the Capex model, the customer purchases the solar system outright—paying ₹50–₹80 lakh upfront for a 500 kW rooftop installation—and owns the asset. After the 4–7 year payback period, all generated electricity is effectively free. In the Opex model, the customer pays zero capital; a third-party developer owns the system and the customer pays a per-unit electricity tariff (typically ₹3.50–₹5.50/unit) for 15–25 years. Capex is better when the customer can capture the depreciation benefit and has available capital. Opex is better when capital is constrained or when the customer prefers to keep the asset off the balance sheet. For a detailed comparison framework, see our guide on Capex vs Opex vs RESCO solar models.
What is a typical PPA tariff for C&I rooftop solar in India in 2026?
C&I rooftop PPA tariffs in India in 2026 typically range from ₹3.50/unit to ₹5.50/unit, depending on system size, location, developer financing cost, and negotiated escalation rate. Projects above 500 kW with good rooftop quality (low shading, sound structural condition) typically achieve tariffs at the lower end of this range. Smaller projects (100–300 kW) or those with complex structural requirements command higher tariffs to compensate the developer for higher per-unit installation cost. Compare the PPA tariff against your state’s prevailing HT industrial grid tariff—typically ₹7.50–₹9.50/unit in manufacturing states—to calculate the per-unit savings.
Who is responsible for solar system maintenance under the Opex model?
Under the Opex/PPA structure, the developer is responsible for all operations and maintenance (O&M) of the solar system—including panel cleaning, inverter servicing, monitoring, and any repair or replacement of faulty components. This is explicitly stated in the PPA and is one of the model’s primary attractions: the customer’s energy cost is predictable and their operational team has no system responsibility. From an engineering perspective, the developer typically engages an O&M contractor (often the original EPC) on an annual maintenance contract that specifies cleaning frequency, performance ratio targets, and inverter response time SLAs.
Can a small C&I business with a 100 kW rooftop use the Opex model?
Yes, but the transaction costs of PPA structuring (legal, lender due diligence, third-party monitoring setup) make the economics marginal for projects below 200 kW. Most developers have a minimum project size of 150–200 kW for Opex deployment. For projects of 100–150 kW, the Capex model with institutional financing (IREDA’s MSME solar loan, SIDBI green energy loans) often delivers better economics than Opex because the developer margin built into the PPA tariff is a larger percentage of a smaller transaction. EPCs serving small C&I customers should present both options with a financial comparison before defaulting to Opex.
What happens to the solar system at the end of the PPA term?
Most Indian C&I PPAs include provisions for system transfer at PPA term end. Common outcomes: (1) the customer purchases the system at its residual book value (typically near zero after 20 years of depreciation); (2) the PPA is extended at a renegotiated tariff; or (3) the developer removes the system. In practice, most customers exercise the purchase option at term end because a 20-year-old solar system still has 5–10 years of useful generation life and its replacement cost is borne entirely by the customer in the new Capex scenario. EPCs who help customers understand this end-of-PPA scenario create a natural re-engagement opportunity for system evaluation and potential upgrade design.
How does the Opex model affect a company’s ESG reporting?
Under Scope 2 emissions accounting (GHG Protocol), electricity purchased from a solar developer under a PPA can typically be reported as renewable energy consumption—and in some jurisdictions requires a Renewable Energy Certificate (REC) or bundled PPA attribute. According to IRENA’s guidance on corporate renewable energy procurement, PPAs are the primary mechanism used by multinational corporations to achieve Scope 2 renewable electricity targets in markets like India where retail green tariffs are not yet widely available—reducing the company’s reported grid emissions intensity. This is increasingly material for: (1) companies in global supply chains where customers or investors require Scope 2 disclosure; (2) companies pursuing green building certification (LEED, IGBC Green Factory); (3) companies accessing export markets where carbon border adjustment mechanisms are being implemented. EPCs who position Opex solar as an ESG solution—not just a cost-saving measure—address a second decision-making driver that often has C-suite visibility independent of the CFO’s financial analysis.
