Redefining the Rules

The expert group appointed by the Central Electricity Regulatory Commission (CERC) to review the Indian Electricity Grid Code (IEGC) has recently come out with its report. The group reviewed the provisions of the IEGC Regulations, 2010, based on past experience, recent developments, changes in the market structure and future challenges including the high level of renewable penetration into the grid and the introduction of new products in the market.

Based on its review, the expert group has suggested appropriate regulatory interventions and finalised its recommendations in the form of the draft IEGC 2020 for the CERC’s consideration. While preparing the new grid code, the focus was on improving grid security, stability and flexibility in the operation of generating resources in view of India’s ambitious targets for renewable energy addition (175 GW by 2022). The draft regulations introduce three new sections – protection and commissioning, cybersecurity, and monitoring and compliance. It also defines the roles of new agencies such as qualified coordinating agencies (QCAs) and the National Power Committee.

Constituted in May 2019, the six-member expert group is headed by Rakesh Nath, ex-chairman, Central Electricity Authority (CEA), with representations from the CERC, Power System Operation Corporation of India (POSOCO) and the CEA. It held several meetings with various stakeholders during the six months up to December 2019.

“In the emerging scenario with expected high levels of renewable penetration, the draft IEGC comprehensively covers all the aspects related to security, economy, reliability, resilience and efficiency while planning, operating and maintaining the power system,” says S.R. Narasimhan, director, system operation, POSOCO, and member of the expert group.


The Indian electricity grid has come a long way from operating at four independent frequencies when the first grid code was notified in 1999 to becoming a strongly integrated synchronous grid operating at a common frequency. The grid code was renotified in March 2006 and then in April 2010, in addition to several amendments from time to time. India’s installed generating capacity has increased from 89 GW in 1999 to over 360 GW (including 82 GW of renewable capacity) in December 2019. Over the period, the grid’s capability to accommodate the variable renewable generation has increased substantially. Currently, the average renewable energy penetration is 9 per cent, which is expected to cross 20 per cent over the next few years. Apart from this, the nominal operating frequency band has progressively narrowed and deviations from schedules have been monitored to control frequency digressions.

The draft IEGC proposes measures to strengthen grid security and resilience with emphasis on increasing flexibility of resources and ensuring automatic response to frequency excursions. The measures proposed for grid security and renewable integration are technically feasible and compliant with the CEA standards.

Draft IEGC 2020 – Key highlights

The draft IEGC has been organised into 11 chapters. Four chapters are titled preliminary, Structure of the Grid Code, Role of Various Organisations and Their Linkages, and Miscellaneous. The other seven chapters have been discussed briefly as follows:

Planning code: It has been thoroughly overhauled, encompassing all facets of the power system. These include demand forecasting; generation resource planning (flexibility, ramping, minimum turndown level); energy storage requirements; system reserves; system inertia for grid stability; and interstate system planning including reoptimisation system study, resource adequacy, enhancement of the total transfer capability (TTC) across interregional boundaries and the interstate transmission system (ISTS) interfaced with the state transmission utility (STU) network. “The regulations pitch for a bottom-up approach, wherein the STU will aggregate the demand estimation (at the granular level including the daily load curve on an hourly basis for a typical day of each month) and resource adequacy data for five years, and submit it annually to the central agencies (CTU)/CEA). The CTU will then consider various factors including intra-state/regional balances and cross-border exchanges in a comprehensive manner during transmission planning,” informs Narasimhan.

Connection code: It has been reviewed and made applicable to both generators as well as transmission licensees. The National Load Despatch Centre (NLDC) or the regional load despatch centre (RLDC) in consultation with the CTU must carry out a joint system study six months prior to the expected date of first energisation of a new power system element to identify any operational constraints. For this, the code has specified the technical data to be provided by connectivity grantees; transmission licensees including deemed transmission licensees and cross-border entities; and the state load despatch centres (SLDCs)/STUs prior to the energisation of a new or modified power system element. This code also mentions the tests required prior to the trial run for the declaration of commercial operation.

Protection and commissioning code: It is a new chapter that has been added to the regulations. According to this chapter, a centralised database must be maintained by the respective regional power committees (RPCs) with details of relay settings for grid elements and a system-wide study must be carried out by the RPC secretariat twice a year for validating the protection setting. The new protection code proposes annual self-audits as well as third-party audits once in five years. In the commissioning code, the procedure for trial run and declaration of the date of commercial operation date for renewable generators has been included. The code allows part-commissioning of minimum 50 MW of both wind and solar generation plants in the ISTS system. In addition, to validate the flexibility of generators for grid security, some essential tests have been prescribed prior to the trial run for different types of conventional and renewable generators.

Operating code: Under this, the draft regulations propose frequency response measures to correct the load generation imbalances in an automated manner with the help of primary, and secondary reserves, followed by manual tertiary reserves deployment. In the event of an emergency, it proposes load shedding through demand response contracts or special protection schemes. The draft regulations mandate adequacy of generation resources for round-the-clock supply to all consumer categories.

  • Given the existing comfortable power supply situation, it is possible to bring reserve generating capacity on bar for a quick response. It may be noted that the NLDC has already done preparatory work with respect to secondary control via automatic generation control (AGC). Currently, the primary response available is of the order of 12-14 GW per Hz to contain frequency deviations. This requires to be maintained at a minimum level of 15 GW per Hz in the future. The new grid code proposes free governor mode of operation (FGMO) instead of the restricted governor mode of operation for all generating units in order to arrest the steady fall in frequency in the event of major grid disturbances following any contingency or otherwise.
  • “For the reference contingency of 4,500 MW generating station outage, the frequency would dip from 50 Hz to 49.5 Hz and quickly recover to 49.7 Hz with the support of primary response,” says Narasimhan. Once the FGMO is implemented, generating machines across various control areas should be able to provide primary response (as per droop settings and available margins) immediately for up to five minutes, after which the secondary response will take over through AGC to recover the frequency.
  • The secondary reserves would start responding within 30 seconds of the area control error (ACE) of a particular area going beyond the minimum threshold limit of ±10 MW. The required secondary reserves through AGC should be fully delivered within 15 minutes and be capable of sustaining for the next 30 minutes. The regional generation units regulated by the CERC have to provide secondary response starting April 1, 2020, whereas the thermal (200 MW and above) and hydro (25 MW and above) generating units in states having an annual peak demand of over 10 GW or in renewable-rich states have to provide such response from April 1, 2021.
  • The operating code has provisions for ensuring and monitoring the availability of reserve capacity. The demand forecasting activity has been properly structured and there is a monitoring mechanism for errors in demand forecasting. This is important as the quantum of reserve capacity required to be maintained for grid security is related to credible contingency including errors in demand forecast and renewable generation.
  • Further, to minimise forecasting errors of renewable generators, aggregation of renewable energy has been allowed at one or more pooling stations for the purpose of deviation settlement. An institutional mechanism, in the form of QCAs, has been provided for composite scheduling and common deviation settlement of renewable generating stations at one or more pooling stations. The role and functions of the QCA have been specified in the grid code.
  • The nominal frequency band has been narrowed to 49.95-50.05 Hz from 49.90-50.05 Hz. The power system condition has been categorised into normal, alert, emergency, extreme emergency and restoration states. The roles of users have been defined for each state. Further, structured demand estimation has been defined for operational planning studies on a daily, monthly and yearly basis.
  • Post despatch, the draft IEGC provides a timeline for event analysis, lays down responsibilities of different agencies in event analysis and disseminates the lessons learnt. The CEA grid standards classify grid disturbances on a scale of 1 to 5 depending on the percentage of load or generation lost in any region, but they do not cover the near misses. The draft IEGC defines the “near-miss” events as well to ensure a thorough analysis.
  • To accurately forecast grid behaviour in different eventualities, it is necessary to validate the performance characteristics of power system elements, particularly generating units. Hence, field testing of machines has been mandated once in five years for validation of their mathematical models to be used in power system studies.

Unit commitment, scheduling and despatch code: This code for the physical delivery of electrical energy replaces the existing scheduling and despatch code. It covers new features such as real-time market, combined scheduling for QCAs, commitment as well as scheduling and curtailment of must-run plants.

  • The regulations lay emphasis on the continuous reoptimisation of ISTS in order to achieve economy and efficiency in system operations. In addition to the interregional power transfer capability, the CTU and NLDC, in coordination with the STUs, will be required to declare the import/export transfer capability at the electrical periphery of a state.
  • Wind, solar, wind-solar hybrid and hydro plants (in case of excess water leading to spillage) must be treated as must-run power plants and should not be subjected to curtailment on account of merit order despatch or any other commercial consideration. In case of any transmission or system security constraint, renewable generation may be curtailed only after harnessing the available flexible resources including energy storage systems.
  • In extreme circumstances when must-run plants have to be curtailed, their details must be published on the RLDC/SLDC website the following day.
  • Curtailment may also be required when all flexible resources are employed by the load despatch centres, but frequency remains above 50.05 Hz, the ACE remains high and any further reduction in conventional generation would necessitate decommitment of units, leading to shortage and possible load shedding during peak hours.
  • Likewise, in case of low frequency, the IEGC facilitates the absorption of available spare capacity in wind and solar generating units through primary response without binding them to restrict output up to their installed capacity.
  • Solar/Wind/Hybrid plants (with a capacity of 10 MW or above and connected at 33 kV or above) commissioned after March 31, 2022 have to provide primary response and have the capability of instantaneously ramping up to 105 per cent of their maximum continuous rating in case of sudden drop in the frequency. These plants have an option to do so through individual battery energy storage systems (BESS), or a common BESS installed at its pooling station.
  • Flexibility has been granted to distribution utilities/buyers that have long-term transmission access (LTA) for scheduling power from their PPA portfolio, including short-term contracts, up to the approved quantum. This will facilitate utilities to optimise their power procurement cost. Utilities or buyers that have short-term bilateral access will be able to revise their schedules as per the timelines provided for long-term or medium-term schedules.
  • To enhance the flexibility of thermal generating stations for the high renewable penetration scenario, the compensation mechanism for plants with below the normative PLF has been reviewed and rationalised. The compensation for degradation in performance parameters resulting in higher cost of energy will be calculated for each time block and settled on a monthly basis. The extant mechanism for sharing of efficiency gains from power plants has been retained. Generating stations have been given the option to declare minimum trun down level of up to 40 per cent.

Cyber security code: It has been added in the draft. The code provides for the identification of critical information infrastructure, appointment of an information security officer (ISO) as per the Information Technology Rules, 2018, and necessary measures in accordance with the guidelines of the National Critical Information Infrastructure Protection Centre.

Monitoring and compliance code: A new chapter has been added to provide for annual self-audits as well as third-party audits for the performance of all users, the CTU, STUs, NLDC, RLDCs, SLDCs and RPCs to ensure grid code compliance.

In addition to the provisions listed in the draft regulations, the expert group has made three other suggestions for the CERC’s consideration.

  • It has suggested that a penalty should be levied on transmission licensees for paying compensation to the affected LTA holders in case of transmission outage due to the poor performance of the licensees.
  • The second issue pertains to virtual power plants, which act as a single despatchable plant by aggregating capacities of heterogeneous energy resources and energy storage for providing renewable energy on demand. The general view is that transmission adequacy has to be ensured prior to allowing a spatially distributed generation complex the flexibility of delivering power at different points in the grid.
  • The third issue relates to the liberalisation of the coal market. The CERC, which is responsible for electricity market development, must ensure that fuel shortages do not lead to deficient or negative generation reserves during peak hours despite the existence of spare installed conventional capacity.

The way forward

It is acknowledged that the grid code is a dynamic document, which evolves over time, taking into account the current operating environment, the future mix of energy resources, technological advancements and the maturity of the system. The latest version of the rules governing grid operations has come out at the right time as the power sector gears up to enter into the next phase of development with greater amounts of variable generation and new products in the market.

Swarna Kesavan


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