Sunsetting the Must Run: From Adolescence to Adulthood 

Background

India’s renewable energy sector has been enjoying ‘must run’ status since its inception — a policy that ensured wind and solar were dispatched ahead of conventional generation, except in rare grid-security situations. This guarantee subsequently introduced through the CERC grid code in 2010, was vital in attracting early investment and enabling rapid capacity growth. However, now Must Run has reached adolescence with renewable capacity penetration now exceeding 50% and generation exceeding 23%, operational and economic challenges are emerging. This is evident from recent market outcomes, where prices have fallen to zero during low-demand, high-solar generation periods. System operators are grappling with sharper evening ramps, localised congestion, and higher reserve requirements. Blanket priority dispatch can suppress flexibility signals, create inefficiencies, and shift system costs onto consumers.

In other mature power markets — from Germany to Australia — such rules and policies have been phased out. Priority dispatch has been replaced with market integration, transparent curtailment rules, and compensation mechanisms, supported by strong flexibility and ancillary service markets.

At 14 years age, CERC’s ‘must run’ rule has reached adolescence — old enough to stand on its own, but still in need of structure as it transitions into a market-based adulthood. India can follow a similar trajectory, but through a phased approach:

1.      Define a clear curtailment order with fair compensation for affected generators.

2.      Develop robust flexibility and system-strength products to manage variability.

3.      Grandfather legacy PPAs to protect existing investments.

4.      Strengthen forecasting, locational signals, and resource adequacy rules to improve dispatch efficiency.

Transitioning from ‘must run’ to ‘market-integrated’ renewables will better align India’s clean energy ambitions with grid reliability, cost efficiency, and long-term market stability.

Why ‘must run’ existed—and why it now bites

The original idea was that giving renewables priority helped reduce the risk for early investors, stopped coal and gas plants from unfairly blocking them, and supported government goals for more green energy and lower emissions. However, current friction points have emerged as:

 Operational: In the evenings, solar power drops fast, so other plants have to ramp up quickly. Weak grid sections and traffic jams on transmission lines force costly last-minute changes elsewhere.

Economic: Since renewables cost almost nothing to run, they can push prices to zero or below when there’s too much supply, without giving clear signals about where to build or when to use power.

Fairness: The extra costs of fixing these issues end up with consumers or non-renewable generators, not with those creating the problems.

What others did

European Union (EU)

Moved from blanket priority to conditional integration-The 2019 Electricity Regulation removed blanket “priority dispatch” for most new RE; small plants and demonstration projects retained limited priority.

On compensation and transparency front provided for compensation based on foregone market revenues to RE generators when curtailed for system reasons, and TSOs are required to publish curtailment data along with clear justifications for their actions.

Germany

Historic “Einspeisevorrang.” Priority feed-in was coupled with compensation for curtailment (“Entschädigung”) and later Redispatch 2.0, which treats RES like conventional units in congestion management, with measured data, standardized compensation, and transparency.

Outcome. Curtailment persists in congested north–south corridors, but costs are visible and increasingly targeted through grid expansion and locational signals.

United Kingdom (GB)

No must-run; market dispatch. National Grid ESO economically curtails wind/solar when constraints bind and pays constraint costs.

Reform levers. Balancing Mechanism, faster intraday trading, and proposed locational signals aim to reduce curtailment and total system cost.

United States (RTO/ISO regions)

Market first, incentives second. No federal must-run. ISOs curtail renewables for reliability/congestion; PPAs and Production Tax Credits influence bidding but do not guarantee priority.

Growing toolkit. Fast frequency response, ramping products (CAISO), and scarcity pricing (ERCOT) reward flexibility and storage participation.

Australia (NEM)

Semi-scheduled model. Wind/solar must follow AEMO dispatch targets; curtailment is routine during constraints or system-strength shortfalls.

System-strength directions & grid-forming inverters. New standards, inertia procurement, and operational demand management reduce curtailment over time.

Spain & Ireland

Spain. Priority dispatch scaled back in line with EU law; curtailment is compensated via clear market rules.

Ireland. High SNSP targets with DS3 services; wind often curtailed but compensated, while system-services markets pay for flexibility.

Common threads across jurisdictions:

1. Curtailment is allowed when least cost or for security—never arbitrary.

2. Compensation is rule-based, typically linked to lost market revenues or contract terms.

3. Flexibility and system-strength are paid products: reserves, fast frequency response, inertia, voltage control, ramping.

4. Transparency: publish curtailment volumes, locations, reasons, and costs.

5. Locational signals gradually steer buildout and grid upgrades.

Can India follow?

The answer is yes, if it reforms at right time in right sequence. From a consumer-welfare perspective, this approach lowers the total system cost, improves price signals, and ensures fairness in cost allocation.

1) Move from “must run” to “must-offer, fairly-curtailed” – Define a curtailment merit order, create a standardized compensation rule.

2) Build missing markets – Flexibility products, faster markets, congestion management.

3) Protect investment certainty – Grandfather legacy PPAs, small projects retain priority.

4) Improve forecasting, visibility, and accountability – Forecasting obligations, transparency portals, audits.

5) Get serious about system strength and inertia – Codify requirements, reward grid-forming capability.

6) Introduce locational and temporal signals – Connection charges, differentiated losses, zonal/nodal pricing.

Practical implementation roadmap (12–36 months)

Phase 1 (0–6 months) – Policy declaration and groundwork:
• Notify shift from ‘must run’ to ‘must-offer with fair curtailment’ for new PPAs from a fixed date.
• Publish standard compensation formula (e.g., foregone tariff minus saved variable cost).
• Launch curtailment dashboards at SLDC level.

Phase 2 (6–18 months) – Market plumbing:
• Introduce fast frequency response, ramping, and system-strength products open to all technologies.
• Reduce scheduling granularity to 15 minutes or less in DAM/RTM.
• Pilot SCED/MBED with redispatch payments.

Phase 3 (18–36 months) – Deep integration:
• Apply regime to all new capacity; offer legacy PPAs opt-in with incentives.
• Introduce locational pricing/zonal congestion management.
• Tighten forecasting requirements with penalties for persistent deviation.

Addressing common concerns

Investors are unlikely to leave if the rules are clear and include fair compensation. Coal will not get a free pass, as flexibility requirements apply equally to all technologies. In some cases, limited curtailment is cheaper than building excessive grid capacity or keeping inflexible plants running

Bottom line

Phasing out blanket “must run” is not about sidelining renewables; it’s about integrating them into a modern market design—such as MBED—where they compete fairly, earn revenues for both energy and flexibility services, and face curtailment only when it is the least-cost option, with predictable compensation. With a clear, phased roadmap, India can maintain investor confidence, safeguard consumers, and operate a cleaner, more reliable grid.