Cross-State Open Access Solar PPAs in India 2026: Charges, Risks, Landed Cost

Cross-state open access has moved from a niche procurement route to a serious sourcing option for large Indian C&I electricity buyers in 2026. The driver is simple: many industrial and commercial consumers have already exhausted easy on-site solar and now want larger contracted volumes, better generation profiles, and access to lower-cost renewable resources outside their home state. At the same time, developers are actively offering inter-state solar and hybrid structures to serve multi-location corporate demand.

But the economics are no longer as simple as comparing an inter-state PPA tariff with a state DISCOM tariff. A workable cross-state structure depends on the interaction of ISTS rules, scheduling, CSS and AS treatment at the drawal end, state transmission and wheeling at the sink bus, banking availability, RPO accounting, forecasting compliance, and the hidden cost of curtailment and change-in-law risk. For CFOs, power procurement teams, lenders and policymakers, the key question is not whether open access works in principle. It is whether a specific corridor, contract and consumer profile produces a stable landed cost over the next 12 to 18 years.

This article focuses on that exact question: how to evaluate cross-state open access solar and hybrid PPAs in India in 2026, with a practitioner lens on tariffs, charges, risks and bankable decision criteria.

Why cross-state open access is back on the table in 2026

Three market realities are making inter-state transactions more relevant this year.

First, intra-state open access in several high-demand states has become less predictable on banking and surcharge treatment. Consumers still pursue state-level procurement where viable, but many are now assessing whether importing renewable energy from resource-rich states can deliver a better contracted energy cost despite corridor and settlement complexity.

Second, project locations in Rajasthan, Gujarat and parts of Karnataka continue to offer superior solar CUF, often in the 23% to 28% range for utility-scale AC-delivered solar depending on DC-AC design, module technology and evacuation conditions. By comparison, some load-heavy consumption states offer weaker project economics due to land constraints, evacuation bottlenecks or higher local charges. For buyers with round-the-year daytime demand, access to a better resource can offset part of the transmission stack.

Third, the policy architecture under the Electricity (Promoting Renewable Energy Through Green Energy Open Access) Rules, 2022, as amended, has normalised the conversation around renewable open access. While implementation still depends heavily on state-level practice, the rules have improved the comfort level of large buyers and lenders in structuring medium- and long-tenor contracts.

A common 2026 use case is a 10 MW to 50 MW equivalent contracted requirement for a manufacturer with plants in Maharashtra, Haryana, Tamil Nadu or Uttar Pradesh, paired with a generator in Rajasthan or Gujarat. Another is a pan-India corporate buyer aggregating multiple facilities under one procurement strategy, sometimes blending solar and hybrid supply with RTC or peak support from the grid.

The tariff stack: from ex-bus PPA price to real landed cost

The biggest mistake in evaluating cross-state renewable procurement is stopping at the generator quote. In 2026, ex-bus solar tariffs for high-quality inter-state projects serving C&I buyers can still be seen in a broad band of roughly Rs 2.60 to Rs 3.30 per kWh depending on tenure, credit quality, scheduling point, curtailment allocation and quantum. Hybrid structures with some firming value can price higher, often around Rs 3.40 to Rs 4.50 per kWh depending on storage or balancing design.

That is only the starting point. The landed cost at the consumer meter can include:

• PPA energy tariff
• ISTS transmission charges, where applicable
• ISTS losses
• State transmission charges at the sink end
• State transmission losses at the sink end
• Wheeling charges and losses, depending on connection arrangement
• Cross-subsidy surcharge
• Additional surcharge, where levied
• SLDC fees, scheduling and system operation charges
• Metering and connectivity-related expenses
• Forecasting and scheduling deviation settlement exposure
• Banking charges, if banking is permitted and used
• Trading margin, if routed through a trader

For many consumers, the decision turns on CSS and AS treatment. If the imported renewable power is treated as open access supply replacing DISCOM energy, CSS usually remains a central consideration unless a specific exemption applies. Additional surcharge depends on state practice and whether stranded fixed-cost arguments are being enforced for that category and supply mode.

In practical 2026 terms, a buyer seeing an attractive ex-bus tariff of Rs 2.85 per kWh may find the all-in landed cost becoming Rs 4.20 to Rs 6.20 per kWh depending on the state, voltage level, corridor losses and surcharges. In some states and categories that result is still compelling against industrial grid tariffs of Rs 7.50 to Rs 10.50 per kWh. In other cases, especially where banking is poor and surcharges are heavy, the savings case narrows sharply.

This is why a serious evaluation must compare not just average tariff but time-matched avoided cost. If your daytime marginal avoided power cost is Rs 8.20 per kWh and demand profile aligns tightly with solar injection, a landed OA cost of Rs 5.00 may be excellent. If your plant operates heavily on night shifts and can absorb only 45% of solar generation in real time without efficient settlement, the same contract may underperform.

ISTS waiver, transmission corridor and what actually matters now

A large share of market confusion still comes from overgeneralising the ISTS charge waiver discussion. In reality, the answer depends on project type, commissioning timeline, policy conditions and the exact contracting path.

Buyers should evaluate five points instead of relying on sales pitches.

• Is the project using ISTS connectivity and does it qualify under the prevailing central policy framework for transmission charge concessions or waiver windows?
• What are the scheduled commissioning dates and what delay risk exists relative to eligibility conditions?
• If full waiver is not available for the project category or timeline, what is the expected ISTS charge pass-through on a delivered basis?
• What are the transmission losses on the relevant corridor and how are they allocated in billing and scheduling?
• Is there congestion or curtailment history at the generating node or the evacuation substation?

In 2026, some buyers assume that inter-state renewable automatically enjoys a transmission cost advantage. That is no longer a safe assumption. Even where policy support exists, one must test legal durability, commissioning risk and whether any benefit is already fully priced into the quoted tariff.

For lenders, the transmission question is really a cash flow question. If a project model assumes a delivered energy price based on concessional transmission treatment, a future policy interpretation change or commissioning slippage can materially affect DSCR. Hence, term sheets should clearly state whether transmission-related change in law is a seller risk, buyer pass-through, or shared adjustment mechanism.

Banking, settlement and profile matching: the hidden profitability lever

For solar-only cross-state PPAs, banking policy at the drawal state often determines whether the deal is merely acceptable or truly superior. This is especially true for consumers with variable weekly schedules, seasonal outages, or lower weekend consumption.

In 2026, state banking frameworks remain fragmented. Some states permit limited monthly banking for renewable open access consumers with prescribed charges and settlement rules. Others have tightened or effectively neutralised banking economics through restrictive caps, high banking charges, end-of-period forfeiture, or poor banking purchase rates for unutilised energy.

A buyer should model at least three scenarios:

• Real-time self-consumption with minimal banking
• Monthly banking with realistic drawal patterns and banked energy losses
• No banking or severely constrained banking

The difference can be significant. Consider a factory with a flat 24x7 load of 8 MW and an imported solar contract supplying roughly 18 million kWh annually. If 80% of generation can be consumed in real time and 15% can be economically banked and later withdrawn, the effective utilisation can exceed 95% after losses and charges. If the same buyer operates only one shift and banking is weak, effective use may fall below 60% to 70%, pushing the cost of consumed units much higher.

This is where hybridisation becomes commercially relevant. A solar-plus-wind or solar-plus-storage arrangement may carry a higher tariff, but if it improves coincidence with load and reduces spill or low-value settlement, the net landed cost per useful kWh can be lower than solar-only procurement. Many buyers still compare tariffs rather than useful-energy economics. That leads to poor contracting decisions.

Forecasting and scheduling discipline also matters more in cross-state structures. Deviations create direct charges and can trigger operational friction with scheduling agencies and SLDCs. Buyers should ask whether the developer has an experienced QCA or equivalent scheduling setup, how deviations are allocated, and whether curtailment due to grid conditions is transparently reported and compensated as per the contract.

RPO, carbon accounting and the utility-regulatory interface

Cross-state open access is not only a cost tool. It also sits at the intersection of compliance and sustainability reporting.

For obligated entities, renewable procurement can support RPO pathways, subject to prevailing state and regulatory treatment. However, teams should not assume that every MWh under an inter-state corporate PPA automatically translates into straightforward internal compliance credit without reviewing the applicable commission orders, contractual energy accounting and reporting architecture.

The buyer should verify:

• Which RPO category the contracted energy supports under current norms
• Whether any separate environmental attribute treatment is specified in the PPA
• How generation, scheduling and consumption data will be documented for audit and compliance
• Whether the consumer's state regulator has any specific procedural requirement for recognising open access renewable consumption

For utilities and policymakers, the growth of cross-state procurement raises a familiar issue: preserving system cost recovery while enabling competitive renewable sourcing. High surcharges can protect near-term DISCOM revenue but may also suppress economically efficient industrial procurement and weaken state competitiveness for manufacturing investment. Conversely, fully unrestricted migration without transition design can strain incumbent utility economics.

The practical policy path is not rhetorical. It is transparent and predictable surcharge design, clear banking rules, time-bound OA approvals, and settlement systems that minimise discretionary delays. In 2026, investor confidence still depends less on headline policy intent and more on whether approvals, meter integration and invoices happen on schedule.

A due-diligence checklist for buyers, developers and lenders

Before signing a cross-state PPA, every party should work through a quantified diligence matrix. At minimum, it should include the following.

• Source state, sink state and voltage-level route map
• Connectivity status, evacuation readiness and substation loading
• Historical curtailment data for the project area or proxy assets
• Applicable ISTS charges and losses under the actual commissioning timeline
• State transmission and wheeling charges at the drawal end
• CSS and AS applicability by consumer category and contract structure
• Banking rules, charges, caps and settlement period
• Deviation charge allocation and scheduling responsibility
• Change-in-law mechanics for taxes, duties, transmission charges and surcharges
• Payment security package, LC structure and rebate for timely payment
• Minimum offtake, deemed generation and curtailment provisions
• RPO and sustainability attribute treatment
• Exit rights, assignment rights and consequences of plant shutdown or load reduction

For large C&I buyers, we recommend a landed cost model with monthly granularity rather than annual averages. The model should map injection profile, drawal pattern, losses, banking assumptions, expected curtailment and all regulatory charges. A contract that appears to save Rs 2.00 per kWh on annual averages may save only Rs 0.80 in realistic plant operations. The reverse can also be true where a higher nominal tariff performs better because settlement mechanics are stronger.

Developers should also resist under-quoting and over-promising on state charge assumptions. Sophisticated buyers and lenders now ask for scenario tables. A credible proposal should show base case, downside and sensitivity views for surcharges, banking and transmission treatment. That improves closure rates and reduces post-signing disputes.

What a good 2026 cross-state deal looks like

A strong cross-state open access transaction in India today usually has six features.

• Resource-rich project location with proven evacuation
• Clear transmission and surcharge visibility at the drawal state
• Load profile that absorbs a high share of renewable generation
• Limited dependence on fragile banking assumptions
• Tight scheduling and settlement capability
• Balanced change-in-law and curtailment clauses that remain financeable

As a rough screen, many industrial buyers should proceed to full diligence only if the expected landed renewable cost is at least 15% to 25% below their avoided grid energy cost in the base case, and still retains a meaningful saving under a prudent downside scenario. For high-credit buyers with multi-site aggregation, even smaller base-case savings may work if the structure delivers scale, decarbonisation targets and tariff visibility over a long horizon.

The core takeaway is straightforward. Cross-state open access in 2026 is neither a universal bargain nor a regulatory trap. It is a transaction-heavy procurement route where project location, sink-state rules and operational fit determine value. The winners will be buyers and developers who model delivered economics honestly, contract for policy volatility, and align energy shape with plant demand rather than chasing the lowest quoted tariff.

If your organisation is evaluating cross-state open access solar or hybrid procurement, contact Growthifye's advisory desk for a state-by-state landed cost model, policy diligence review and bankable transaction support.