From 1 April 2026, CERC’s DSM Regulations tighten the revenue-neutral tolerance band for solar and wind-solar sellers to ±5%. CERC then issued a final order on 31 March 2026 setting the “X” trajectory: X remains 100% in FY2026-27, then declines by technology before reaching zero from 1 April 2031.
Key Takeaways
- CERC’s 2024 Deviation Settlement Mechanism Regulations apply to grid-connected regional entities and inter-state transactions, and use commercial settlement to encourage schedule adherence.
- The final regulations reduce the solar and wind-solar hybrid tolerance band from ±10% to ±5% from 1 April 2026; wind moves from ±15% to ±10%.
- After its 2025 consultation, CERC’s final order dated 31 March 2026 fixed differentiated X trajectories for solar/hybrid and wind sellers; FY2026-27 remains at X = 100%.
- CERC’s separate March 2026 removal-of-difficulty order deferred a DAS Pool deficit-allocation change until 5 October 2026. That deferral is separate from both the ±5% seller band and the final X order.
- C&I PPAs should allocate forecasting, scheduling, QCA, telemetry, curtailment and DSM cash flows explicitly. This is general information, not legal advice.
What is final from 1 April 2026?
CERC’s DSM Regulations, 2024 create the central mechanism for computing and settling differences between scheduled and actual injection or drawal. They apply to grid-connected regional entities and inter-state purchase and sale, making them relevant to ISTS-connected renewable projects and counterparties.
For a wind-solar seller, the final Regulation 8 framework created source-specific tolerance bands. CERC’s later draft order in Petition 9/SM/2025 accurately recited the already-notified step: from 1 April 2026, the revenue-neutral band is ±5% for solar and wind-solar hybrid stations and ±10% for wind stations. The prior bands were ±10% and ±15%, respectively.
A narrower band means a forecast error enters a less favourable tier sooner. It does not mean every error inside 5% has no consequence, nor cap liability at 5%. Charges depend on deviation direction and size, source category, applicable contract or normal rate, and the time-block formula.
What did the final “X” order decide?
CERC’s 2025 document was a consultation proposal, but that was no longer the latest status on 11 July 2026. After considering stakeholder submissions, CERC issued its final order in Petition 9/SM/2025 on 31 March 2026. The order keeps X at 100% for both technology groups in FY2026-27, so the denominator remains entirely available capacity for that year. It then sets separate transition paths:
| Financial year | Solar/wind-solar hybrid X | Wind X |
|---|---|---|
| FY2026-27 | 100% | 100% |
| FY2027-28 | 90% | 95% |
| FY2028-29 | 75% | 85% |
| FY2029-30 | 55% | 65% |
| FY2030-31 | 30% | 35% |
| From 1 April 2031 | 0% | 0% |
As X falls, scheduled generation receives more weight in the denominator, increasing exposure for a given absolute error when schedule is low. The final order is subject to pending court proceedings; project counsel should also check any party-specific interim relief. The 2025 draft’s study of 41 weeks of data from 16 stations remains useful context, but its proposed common 80/60/40/20 path was not the final differentiated trajectory. The solar PPA guide offers a general change-in-law framework.
What did CERC defer in March 2026?
CERC’s 30 March 2026 order in Petition 2/SM/2026 addressed Regulation 9(7), which allocates a regional Deviation and Ancillary Service Pool Account deficit when other regional surpluses are insufficient. The regulations had contemplated moving on 1 April 2026 from an allocation based equally on ISTS-periphery drawal and GNA to one based on shortfall in reserves allocated by NLDC.
Grid-India/NLDC reported implementation issues around quantifying, declaring, measuring, dispatching and settling reserves. CERC therefore continued the existing sub-clause until 4 October 2026 and moved the new sub-clause’s start to 5 October 2026, unless otherwise notified.
This was a DAS Pool deficit-allocation deferral, not a deferral of the ±5% solar and hybrid deviation band. Mixing the two dates can produce an incorrect PPA memo and an understated generator risk budget.
How does the ±5% band affect a C&I PPA?
| Issue | Weak drafting | Better allocation question |
|---|---|---|
| Forecasting | “Seller will forecast” | Which agency, data, horizon and accuracy standard apply? |
| Scheduling | No responsible party | Who submits revisions and bears missed deadlines? |
| QCA | Cost omitted | Is aggregation mandatory, optional or shared? |
| DSM charges | All “open-access charges” passed through | Which deviations are seller-caused, buyer-caused or grid-caused? |
| Curtailment | Treated as forecast error | How are grid instructions and deemed generation handled? |
| Telemetry failure | Silent | Who maintains meters, SCADA and communication redundancy? |
| Rule change | Generic clause only | Does a changed band or formula trigger repricing? |
Buyer-driven schedule changes, load curtailment or failure to provide required approvals should not automatically become generator forecast risk. Conversely, a generator should not pass through poor forecasting, telemetry outages within its control or failure to submit a permitted revision. Grid-directed curtailment and force majeure need their own treatment.
Why does the QCA arrangement matter?
A Qualified Coordinating Agency typically coordinates forecasting, scheduling, metering and deviation settlement for generators connected at a pooling point. CERC’s 2025 draft analysis observed that aggregation can reduce net deviations because positive and negative errors across plants may offset. The result is portfolio-dependent, not guaranteed.
Due diligence should examine the QCA agreement, participating pool, allocation key, data rights, performance standards, liability caps and exit rules. Ask whether DSM is allocated by individual error, capacity, scheduled energy or another formula. A plant can benefit at pool level yet face an unfavourable internal allocation.
How should buyers model deviation risk?
Which data should be requested?
Request at least one year of 15-minute forecast, schedule, revision and actual-injection data where available, separated by season. Obtain historic DSM statements, QCA invoices, telemetry availability and curtailment logs. For a new project, use comparable-site data and disclose the proxy.
Which scenarios should be run?
Run the final ±5% band and the final X value for each financial year as the regulatory base case. Stress forecast errors, lower generation, communication outages and restricted schedule revisions. Keep the superseded 2025 draft trajectory out of the base case, and keep buyer load deviation separate from generator injection deviation.
How should invoices be controlled?
Require source statements, calculation files, dispute periods and correction mechanics. Reconcile PPA invoices to RPC or QCA statements at the same time-block granularity. Define whether later true-ups attract carrying cost.
The economics should feed into a delivered-cost model rather than sit outside it. Our solar IRR calculation guide and open-access guide explain how operating charges and state delivery costs affect the investment case.
What is the 2026 procurement checklist?
Confirm the project’s DSM category and point of scheduling. Identify the final rule, not a news summary. Review the QCA contract and historic performance. Allocate each cause of deviation. Align payment deadlines with regulatory statements. Add a specific change-in-law trigger for future X or denominator changes. Finally, preserve audit access to time-block data.
For hybrid procurement, test whether combining solar, wind and storage improves the physical shape and the settlement outcome; see solar-wind hybrid versus solar-only. Storage does not automatically remove deviation: charging schedules, efficiency, state of charge and availability introduce additional constraints.
Frequently Asked Questions
Is the ±5% solar band final?
Yes. The CERC DSM framework specifies the tighter solar and wind-solar band from 1 April 2026. Always verify later amendments for the transaction date.
Is the 2025 proposed X trajectory still the operative reference?
No. CERC’s final order dated 31 March 2026 superseded the consultation trajectory and fixed differentiated values for solar/hybrid and wind. Use the final order, subject to later amendments and applicable court relief.
Was all DSM implementation deferred to October 2026?
No. The March 2026 order deferred a specific DAS Pool deficit-allocation change, not the tighter seller tolerance band.
Can a QCA eliminate DSM charges?
No. Aggregation may reduce net error, but results depend on plant diversity, forecasts, schedules and the QCA’s internal allocation method.
Should the buyer pay every deviation charge?
That is a contractual allocation decision. Charges should be assigned by cause and control rather than passed through under an undefined label.
Does this central rule apply to every rooftop plant?
No. Its scope focuses on regional entities and inter-state transactions. State rules govern many intra-state and rooftop arrangements.
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