Executive Summary
The Chhattisgarh State Electricity Regulatory Commission (CSERC) notified the “Draft Chhattisgarh State Electricity Grid Code, 2026” on June 22, 2026. This regulatory framework is established under Section 86(1)(h) read with Section 181 of the Electricity Act, 2003. It provides a legally enforceable code governing all Connected Entities within the state transmission system to facilitate coordinated planning, operation, and development of the grid.
Upon final notification, this new code will replace the Chhattisgarh State Electricity Grid Code, 2011, and its subsequent corrigendum dated July 5, 2013. The revision is intended to align state-level regulations with contemporary national standards, specifically the Central Electricity Regulatory Commission’s (CERC) Indian Electricity Grid Code (IEGC) Regulations, 2023.
The draft code seeks to maintain reliable and secure Intra-State Transmission System (InSTS) operations while integrating increasing shares of renewable energy. It introduces new chapters for Resource Adequacy, Cyber Security, and the commissioning of energy storage systems, ensuring consistency with the national grid’s evolving technical requirements.
The Resource Adequacy Code: Demand Forecasting and Planning
The draft introduces a dedicated Resource Adequacy Code requiring Distribution Licensees (Discoms) and the State Transmission Utility (STU) to implement an integrated planning framework. This code mandates demand forecasting and the assessment of generation and transmission resources to meet expected consumer load in a cost-effective manner.
By July 31st each year, every Discom must submit the following data to the STU:
- Demand estimations for its control area for a five-year horizon starting April 1st of the subsequent year.
- Estimates factoring in open access consumers, captive generating plants, energy efficiency measures, distributed generation, and demand response.
- Daily load curves on an hourly basis for a typical day of each month, using trend, time series, or econometric methods.
- An assessment of existing generation resources and a procurement plan to demonstrate demonstrable resource adequacy.
The technical workflow and subsequent deadlines for the state and national planning cycle are defined as follows:
- August 30th: STU completes the demand estimate for the entire state, accounting for diversity.
- September 30th: STU provides demand forecasting and generation resource details to the National Load Despatch Centre (NLDC).
- October 31st: NLDC completes the national-level simulation study to assist the state in refining its generation resource adequacy plan.
Integration of Renewable Energy (RE) and Energy Storage Systems (ESS)
The draft incorporates specific technical standards for RE and ESS to ensure grid compatibility. These units must maintain active power control and communication facilities in accordance with Central Electricity Authority (CEA) standards. Inverter-based Resources (IBR) are specifically required to maintain reactive power capability at all times, including during non-operating hours.
| Unit Type | Technical Requirement |
| Renewable Generating Stations | Active power control and communication per CEA standards. |
| Renewable Hybrid Projects | Mandatory active power control and real-time data communication. |
| Energy Storage Systems (ESS) | Pumping/charging and generation/discharging capability testing. |
| Inverter-based Resources (IBR) | Reactive power capability must be maintained during non-operating hours. |
Commercial provisions allow wind, solar, and hybrid generators to appoint a Qualified Coordinating Agency (QCA) for scheduling and commercial settlement. Energy Storage Systems are also required to demonstrate frequency response capabilities.
Technical Standards for Grid Stability and Operations
The draft code adopts several technical thresholds and operating metrics to ensure the security of the InSTS.
Operating Frequency and Voltage Limits The grid shall operate within a frequency band of 49.90 Hz to 50.05 Hz. Furthermore, the draft adopts specific voltage limits for 400 kV, 220 kV, and 132 kV systems to maintain steady-state stability.
Thermal Unit Technical Minimum The technical minimum for coal and gas-based thermal generating units is maintained at 55% of the Maximum Continuous Rating (MCR).
Mandatory Automatic Generation Control (AGC) To support Secondary Reserve Ancillary Services (SRAS), AGC connectivity is mandatory for:
- Thermal units \ge 200 MW.
- Hydro units \ge 25 MW.
Ancillary Services and Reserves The draft adopts the framework of the CERC Ancillary Services Regulations, 2022. This includes governor response requirements for units above 50 MW and protocols for Primary, Secondary, and Tertiary Reserve Ancillary Services. Specific provisions for Inertia Management are also introduced to mitigate the impact of high RE penetration.
System Protection, Cyber Security, and Infrastructure
Grid Users and Connected Entities must adhere to upgraded protocols for system protection and infrastructure security.
- System Protection: Mandatory third-party protection audits of all substations 220 kV and above must be conducted every five years. The code prescribes specific fault clearance times and protection performance indices (Dependability, Security, and Reliability). All Grid Users must submit monthly performance indices to the Regional Power Committee (RPC).
- Cyber Security: The State Load Despatch Centre (SLDC), STU, QCAs, and Grid Users must implement frameworks compliant with the Information Technology Act, 2000, and CEA (Cyber Security in Power Sector) Guidelines, 2021. This includes mandatory periodic audits and incident reporting.
- Infrastructure Standards: The code adopts the CEA Transmission Planning Criteria, 2023, including n-1 security standards. Dedicated EHV lines are mandatory for generators with injection/drawal exceeding 15 MVA. Furthermore, the code imposes strict restrictions on the tapping of EHV transmission lines.
Flexible Operation of Thermal Stations
Provisions for the flexible operation of coal and gas-based thermal stations are included to accommodate variable renewable energy injection. When units operate below normative plant availability but above the 55% MCR minimum, generators are entitled to compensation for:
- Increase in Station Heat Rate (SHR).
- Increase in Auxiliary Energy Consumption (AEC).
- Secondary fuel oil consumption for start-ups, provided the unit exceeds seven start-stop cycles in a year.
Stakeholder Consultation and Procedural Timeline
Stakeholders and the public may submit views, comments, or suggestions regarding the draft code according to the following schedule:
Important Dates
- Deadline for Comments/Suggestions: July 17, 2026
- Public Hearing Date: July 22, 2026
- Time: 3:00 PM
- Venue: CSERC Commission’s office, Irrigation Colony, Shanti Nagar, Raipur (C.G.)
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