Cross-State Open Access PPAs in India 2026: ISTS, CSS, Losses and Landed Cost

India’s open-access market in 2026 is no longer just a choice between third-party and captive structures. For many commercial and industrial buyers, the more decisive question is whether power should be sourced within the consumption state or across state borders. Cross-state renewable PPAs can unlock better resource quality, stronger developer competition and larger project pipelines, but they also introduce a different stack of transmission charges, losses, scheduling obligations and regulatory risk.

For CFOs and energy heads, the headline tariff from a solar, wind or hybrid project in another state is often misleading. A bid at Rs 2.85/kWh from an interstate generator can land above Rs 5.50/kWh after ISTS treatment, state wheeling arrangements, losses, balancing costs and surcharges at the drawal end, depending on consumer category and state rules. In other cases, the same interstate structure can beat local procurement by 40-90 paise/kWh if the project qualifies for waiver benefits and the consumer’s demand profile aligns with generation.

This article focuses on the practical economics of cross-state open access PPAs in India in 2026: where the savings come from, where they disappear, and what buyers, lenders, utilities and policymakers should examine before assuming interstate renewable supply is cheaper.

Why cross-state open access is back in focus in 2026

Interstate procurement has moved back into active consideration for three reasons.

• Resource quality remains uneven across India. Solar CUF and wind PLF still vary materially by location.
• Large C&I buyers with multi-state loads want bigger portfolios than many intrastate markets can reliably supply.
• Developer competition is often deeper in high-resource states, improving tariff discovery and contract flexibility.

A Maharashtra or Haryana consumer may be offered lower ex-bus tariffs from projects in Rajasthan, Gujarat or Karnataka than from constrained local options. Wind-solar hybrid and FDRE-style products are also more feasible when the generation base can be sourced from resource-rich states with stronger evacuation.

However, 2026 procurement decisions are occurring in a stricter economic environment than the early interstate boom years. The easy-era assumption that central transmission waiver alone makes interstate supply attractive is no longer sufficient. Buyers need a full delivered-cost comparison against local open access, utility green products and even plain DISCOM supply under revised time-of-day tariffs.

The 2026 regulatory lens: ISTS waiver helps, but only within limits

The central enabler for cross-state renewable procurement remains the interstate transmission system charge waiver framework for eligible solar, wind and hybrid projects, subject to commissioning windows and prevailing policy conditions. But three realities matter in 2026.

First, not every project qualifies equally. Eligibility depends on technology, commissioning timeline, connectivity path and applicable notification conditions. Buyers should not treat “ISTS-waiver eligible” as a brochure line item; it must be evidenced and contractually backed.

Second, waiver of transmission charges does not mean zero transmission cost. Losses, state-end charges, scheduling charges, SLDC/RLDC fees and balancing impacts still remain. In many cases, losses alone can add 4% to 9% effective energy cost, depending on injection and drawal arrangement.

Third, the value of the waiver can be diluted if the consumption state continues to levy cross-subsidy surcharge, additional surcharge or restrictive open-access conditions for the end consumer category. For a non-captive buyer in a high-surcharge state, savings from an interstate tariff advantage may vanish quickly.

A practical 2026 screening rule used by many advisers is simple:

• If the consumer is evaluating third-party interstate supply into a state with high CSS and active AS recovery, the project must have a very meaningful ex-bus tariff advantage or superior supply shape to remain competitive.
• If the buyer can structure a compliant captive arrangement and the state provides cleaner treatment on surcharges, interstate viability improves sharply.

This is why cross-state evaluation cannot be separated from consumer category, voltage level, contract demand and operating pattern.

Cost stack: what actually builds the landed tariff

The landed cost of an interstate open-access PPA is the sum of more than the generator tariff. In 2026, sophisticated buyers break the stack into at least nine elements.

• Generator PPA tariff or energy charge
• ISTS transmission charges, if applicable after waiver treatment
• Interstate transmission losses
• State transmission or wheeling charges at drawal end, where applicable
• State wheeling losses or distribution losses, depending on delivery voltage and network path
• Cross-subsidy surcharge
• Additional surcharge
• SLDC/RLDC scheduling, system operation and metering charges
• Deviation, balancing, forecasting and banking-related cost impacts

A simple illustration shows why ex-bus comparisons can mislead.

Assume a solar-hybrid interstate offer at Rs 3.10/kWh ex-bus.

Case A: captive industrial consumer, 33 kV, moderate state-end charges, no CSS/AS due to structure, aggregate losses 7%, scheduling and balancing impact 12 paise/kWh.

Indicative landed outcome:

• Ex-bus tariff: Rs 3.10
• Loss gross-up at 7%: about Rs 0.23
• State-end network and operating charges: Rs 0.35-Rs 0.60
• Scheduling/balancing/miscellaneous: Rs 0.12
• Indicative landed cost: roughly Rs 3.80-Rs 4.05/kWh

Case B: third-party consumer in a state with CSS of Rs 1.20/kWh and additional surcharge of 55 paise/kWh, similar losses and operating charges.

Indicative landed outcome:

• Ex-bus tariff: Rs 3.10
• Loss gross-up at 7%: about Rs 0.23
• Network and operating charges: Rs 0.35-Rs 0.60
• CSS: Rs 1.20
• AS: Rs 0.55
• Scheduling/balancing/miscellaneous: Rs 0.12
• Indicative landed cost: roughly Rs 5.55-Rs 5.80/kWh

That difference is why interstate third-party PPAs can look excellent in procurement decks but fail on delivered economics once state-end charges are loaded.

For many C&I users, the right answer emerges only after detailed Demand & ToD analysis and state-wise landed-cost simulation rather than a generic interstate-vs-intrastate debate.

Where interstate PPAs outperform intra-state options

Interstate supply still works well in several 2026 use cases.

1. Large multi-location buyers aggregating demand

A national manufacturer or data-centre operator with loads across several states may find that a single larger project or coordinated portfolio of interstate assets delivers better tariff certainty and stronger counterparty quality than piecemeal local sourcing. Economies of scale in project size, better grid infrastructure at origin, and stronger developers can offset some transmission complexity.

2. Captive structures with surcharge efficiency

Where the corporate buyer can maintain valid ownership and annual consumption compliance, captive interstate supply can materially outperform third-party supply into surcharge-heavy states. The difference often ranges from 1.2 to 2.2 Rs/kWh depending on CSS and AS levels avoided.

3. Wind and hybrid products for evening-heavy loads

States with weak local wind resource or limited hybrid pipeline may not offer enough evening-generation coverage. Interstate supply from high-resource corridors can lower residual utility purchase during expensive time blocks. Even if the average landed tariff is only marginally cheaper than local alternatives, the portfolio value can be superior because of shape.

4. Buyers needing larger annual renewable volumes

Some state markets still face land, evacuation or approval bottlenecks for fast corporate offtake scale-up. Interstate sourcing can shorten procurement time if the project has clearer transmission access and a developer with ready capacity.

The hidden risks: where buyers lose savings

Interstate PPAs fail most often not because the tariff was high, but because assumptions were incomplete.

Scheduling and deviation risk

Cross-state delivery involves tighter operational discipline. Renewable intermittency, drawal variation and mismatch between contracted supply and actual plant load can create imbalance charges or stranded energy. This is especially relevant for buyers whose shifts vary seasonally or whose demand falls on weekends.

Curtailment and evacuation constraints

A low tariff from a remote project has limited value if curtailment risk is underappreciated. Buyers should assess state generation patterns, substation congestion history, deemed generation provisions in the PPA and compensation treatment. Lenders increasingly examine curtailment exposure in merchant-heavy and C&I-focused interstate portfolios.

Change-in-law pass-through ambiguity

Cross-state structures face both central and state-level regulatory movement. A project may benefit from central waiver policy today but still face end-state changes in surcharge methodology, loss accounting, metering treatment or open-access eligibility thresholds. PPA drafting must define pass-throughs tightly.

Approval sequencing risk

Interstate PPAs often require more careful sequencing across CTU/STU connectivity, trading or direct OA pathways, scheduling arrangements, drawal permissions and metering alignment. Delay at one node can hold up commissioning economics for months. Strong Open-access approvals management is therefore not an administrative add-on; it is a core value lever.

Contract shape mismatch

A flat annual energy commitment can be wrong for a consumer whose utility tariff savings are concentrated only in specific time blocks. An interstate hybrid PPA at an apparently competitive average price may underperform if excess daytime injection receives poor value while evening shortfall remains exposed to high utility tariffs.

A practical screening framework for 2026 buyers and lenders

Before issuing an RFQ or signing a term sheet for interstate renewable procurement, stakeholders should test five questions.

1. Is the tariff advantage real after all losses and end-state charges?

Do not compare only ex-bus tariff versus local PPA tariff. Compare delivered cost at consumer meter, month by month where possible, with realistic losses and all applicable surcharges.

2. Is the consumer structurally suited for captive or only third-party?

If the buyer cannot support captive compliance in a durable manner, interstate economics may collapse in certain states. This should be decided upfront, not after preferred bidder selection.

3. What percentage of utility procurement is actually displaced?

Many buyers overestimate displacement. Due to losses, shape mismatch, outages, must-run constraints and open-access scheduling realities, actual bill reduction may be materially lower than contracted renewable volume suggests.

4. Are ToD tariffs changing the benchmark?

Several states are moving toward sharper time-differentiated retail tariffs and demand-linked cost recovery. The reference case is no longer a single average DISCOM tariff. Interstate renewable supply should be benchmarked against avoided tariff by block, not only annual blended tariff.

5. Does the developer’s project status justify the policy assumptions?

Waiver eligibility, substation readiness, grid studies, module sourcing assumptions, commissioning schedule and payment security must all be stress-tested. Interstate savings disappear quickly if COD slips beyond eligibility windows or if project design assumptions change.

This is where disciplined Sourcing strategy and Competitive developer selection matter. The cheapest term sheet is often not the cheapest delivered-power option.

What policymakers and utilities should note

From a policy perspective, interstate open access remains important for efficient renewable integration and national market development. But uneven surcharge practices and approval frictions continue to distort outcomes.

Three policy themes stand out in 2026.

• A transparent, stable treatment of CSS and AS is critical if market signals are to reflect actual system costs rather than procurement deterrence.
• Harmonisation of metering, scheduling and settlement practices would reduce transaction cost for serious C&I offtakers.
• Better coordination between central transmission incentives and state-level open-access execution is needed; otherwise, central waiver policy creates only theoretical access, not practical competitiveness.

Utilities, meanwhile, should recognise that many large consumers are not evaluating interstate PPAs solely to reduce headline tariff. They are seeking long-term cost visibility, renewable compliance support, and better portfolio resilience across time blocks. DISCOM green products and bilateral structures will compete more effectively if they address these needs rather than only resisting migration.

The 2026 bottom line on cross-state PPAs

Cross-state open-access PPAs are neither automatically cheaper nor automatically risky. They are highly selective instruments. For captive buyers, high-load-factor industrials, and corporates seeking wind or hybrid resource from stronger states, interstate structures can still produce compelling landed economics. For third-party buyers in surcharge-heavy states, however, a low ex-bus tariff can be a trap.

The decision in 2026 should come down to delivered cost, supply shape, regulatory durability and execution readiness. Buyers that model all four dimensions usually reach clearer conclusions than those relying on benchmark tariffs or generic market narratives.

If your organisation is evaluating interstate renewable procurement, contact Growthifye’s advisory desk for a practical assessment of charges, losses, supply shape and approval pathway before you take an RFQ or PPA decision.

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This analysis connects directly to our advisory practice: Demand & ToD analysis · Sourcing strategy · Competitive developer selection · PPA structuring & negotiation.