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becomes necessary depends on the system context. In all systems, however, an increase in flexible resources will become a cost-effective integration strategy at some point, requiring additional investment. Broadly speaking, resource adequacy and multi-hour flexibility issues have the largest economic impact. These can be addressed by systematic expansion of the grid, ensuring an appropriate power plant fleet and unlocking demand response potential and storage (Figure 8.7).

Figure 8.7 Integrating large shares of VRE requires system transformation

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Source: Adapted from IEA (2014), The Power of Transformation.

Mobilising the contribution of each of the three areas requires putting in place appropriate market, policy and regulatory frameworks. Frequently it will also need a change in the roles of institutions in the power system, which can take time and resources to achieve. In a nutshell, a two-way adjustment is needed, with actions to make the overall power system more suitable for VRE generation and other measures to make VRE more suitable for the existing power system.

This chapter initially discusses the fundamentals that drive flexibility from the perspective of system and market operation in India, before turning to flexible resources and systemfriendly VRE deployment, focusing on the four flexibility resources. At the end of the chapter, the IEA presents its flexibility analysis of India’s power system, taking a longer term perspective up to 2040.

System operation and electricity markets

System operation – generation dispatch

India’s power system is a large synchronous area that spans five regional grids. As such, responsibilities for system operation are entrusted to system operators at various levels: national (or central), regional and state levels.

Today’s system operation is the result of the historic development of the system, from isolated power systems to state-wide grids and their regional interconnection, which

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*State Regional Energy Management Centres (REMCs) for seven renewable energy-rich states of Gujarat, Rajasthan, Madhya Pradesh, Maharashtra, Karnataka, Andhra Pradesh and Tamil Nadu.

Source: IEA, adapted from the Ministry of Power.

This historic grid and system is reflected in the operation of the system (Figure 8.8). Power System Operation Corporation (POSOCO) manages national and regional dispatch centres as the independent system operator at interstate level. Countrywide co-ordination and system operation is ensured via the National Load Dispatch Centre (NLDC). Each region has a Regional Load Dispatch Centre (RLDC), which operates the regional transmission grid and schedules the interstate generating stations of that region. A regional grid comprises a number of states. For example, the western regional grid has seven constituents: Gujarat, Madhya Pradesh, Chhattisgarh, Maharashtra, Goa, Dadra-Nagar- Haveli and Daman-Diu. Each state then has its own State Load Dispatch Centre (SLDC). This structure implies that system operation is influenced by decisions at state, regional and national levels. Hence, to achieve a flexible system, close collaboration between the different levels is critical, while fully accommodating the specific requirements of each region and state.

The day-ahead scheduling process is aimed at optimal scheduling for dispatch the next day. The NLDC schedules and dispatches electricity across the interstate networks and optimises the dispatch of the RLDCs (it also manages electricity exchanges across borders). RLDCs co-ordinate this process for load and interstate generating stations, connected to the interstate transmission system. The SLDCs co-ordinate the day-ahead scheduling process for load and generators connected to intrastate transmission grids.

With decentralised scheduling, economic dispatch in India also follows a decentralised state-driven model. However, states and power distribution companies (DISCOMs) selfschedule the generators with whom they hold long-term contracts, not optimising statelevel dispatch, while also not making use of cost-efficient unscheduled resources across

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India. Generators can also revise their schedule to manage their real-time imbalances one hour ahead without any financial liability (right to recall) (CERC, 2018a). Against this background, the POSOCO consulted on the introduction of a national-level merit orderbased dispatch (POSOCO, 2018) and CERC has proposed the creation of a centralised market for day-ahead scheduling and real-time dispatch with gate closure. Until 2010, renewables were exempt from scheduling, forecasting and management of imbalances.

System operation – forecasting of wind and solar output

Better forecasting of wind and solar generation is essential to help grid operators accommodate changes in wind and solar generation more efficiently and prepare for extreme events during which renewable generation is unusually high or low. Forecasts can help reduce the amount of fast response operating reserves needed for the system, thereby reducing the cost of balancing the system. Internationally, improvements have been made in recent years towards reducing mean forecast errors. Day-ahead forecasts support day-ahead decisions on whether generation capacity will be dispatched, driving operational efficiency and cost savings. Short-term forecasts determine the need for a quick-start generator, demand response, or other mitigating options to support reliable operation of the electricity system.

The penetration of wind and solar power in India’s states remained below 10% until 2010 and grid integration was not seen as a serious issue. Indeed, VRE was exempt from forecasting, scheduling and supporting grid management with ancillary services. However, more recently CERC and the Forum of Regulators, POSOCO and the dispatch centres have taken several regulatory measures regarding VRE forecasting and management of ancillary services.

In 2010, under the Indian Electricity Grid Code, CERC put forward the Renewable Regulatory Fund mechanism, with the aim of requiring wind generators to undertake forecasting and provide their generation schedule on a day-ahead basis, while paying the deviation charge linked to grid frequency if their schedule deviates beyond a certain limit.

In August 2015 CERC proposed the Framework on Forecasting, Scheduling and Imbalance Handling for wind and solar generators connected to interstate transmission system as a substitute to previously unsuccessful Renewable Remuneration Fund, and amended the regulations under the Indian Electricity Grid Code and deviation settlement mechanism. The new framework applies to all renewable generators connected to the interstate transmission system with aggregate capacity of 50 MW and above, Ultra Mega Power Projects (UMPP) with a capacity of 500 MW, and expansions of existing renewable capacity below 50 MW, in line with the CERC transmission open access regulations (CERC, 2015).

The new framework adopts a hybrid approach to forecasting at the interconnection point with the transmission grid. The RLDCs carry out their own forecasts with the objective of securing grid operation, and the generators or pooling stations forecast their own needs. That means that regional wind and solar generators can use their own forecast or that prepared by the RLDC. However, the commercial impact due to deviation from the schedule will be fully borne by the generators themselves. As forecast errors decrease the closer it comes to actual generation, the wind and solar generators are provided with the option of 16 revisions to their submitted schedule (each revision for a duration of 1.5 hours during the day of actual dispatch).

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Renewable Energy Management Centres

India is rolling out REMCs in the seven renewable energy-rich states of Gujarat, Rajasthan, Madhya Pradesh, Maharashtra, Karnataka, Andhra Pradesh and Tamil Nadu. REMCs will also be established in three RLDCs (north, west and south) and the NLDC to facilitate VRE integration along the Green Energy Corridors.

Table 8.2 REMC tools and functions

REMC Wide Area Data collection of critical substation via existing WAMS system in control centre.

Measurement System

Renewable Energy Real-time analysis of reserves in own control area and in neighbouring area;

Control Reserve scenario analysis for balancing renewable generation.

Monitoring Tool

Source: Prayas Pune (2016).

The REMCs are to be equipped with advanced forecasting tools, smart dispatch solutions and real-time monitoring of renewable generation in their respective areas (Table 8.2). The proposed functionalities of the REMCs include: a) real time monitoring of all renewable generation at the pooling station level; b) intraday and day-ahead forecasting of renewable generation; c) co-ordination with corresponding load dispatch centres for scheduling and dispatch of renewable generation in its area of responsibility; d) co-ordination between corresponding load dispatch centres and renewable developers. The REMC at the national level will be responsible for monitoring renewable generation, analysing collected data and co-ordinating with load dispatch centres to maintain the security and stability of the system. The REMCs at the state level will have the additional responsibility of monitoring the operating reserves in the state. They will have five major tools as outlined in Table 8.2 (MNRE, 2015; GIZ, 2015).

The success of the REMC programme will depend on well-designed capacity-building programmes at all levels (including SLDCs and solar and wind producers). Software and hardware changes/upgrades may also be required at the SLDCs and by solar and wind generators in order to use the tools of the REMC programme. The state of Tamil Nadu

– one of the pioneers of wind power deployment in India – implemented the REMC in 2016, which helped them to achieve a substantial reduction in wind power curtailment. Other states are on the path towards REMC implementation and require significant resources, including software, hardware updates and further support and capacity building to create well-functioning REMCs.

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Imbalance handling and ancillary services

Imbalance management and ancillary services are indispensable for ensuring the reliability of the Indian power system. Power procurement planning is based on long-term contracts (around 90% of the market share) and in the day-ahead market most contracts are physical, not financial (and linked to a generator and supplier).

The intraday energy requirement – as well as system imbalances – were generally managed through the decentralised Deviation Settlement Mechanisms. CERC introduced the Ancillary Services Mechanisms in 2015, which obliged all regional generators (67 plants) to provide a centralised instrument to manage grid frequency and transmission congestion (CERC, 2018b). Ancillary services are used to provide essential system services, such as frequency control, voltage support and generation and transmission reserves. In India they are classified into: frequency control ancillary services (FCAS) (primary, secondary, tertiary), network control ancillary services (NCAS) for controlling voltage and power flow, and system restart ancillary services (SRAS), which are used to restore the system after a full or partial blackout. The NLDC (through the RLDCs) acts as the nodal agency for ancillary services and prepares the merit order stack.

As of today, there are generally four options for managing system imbalances in real time (CERC, 2018a):

Deviation Settlement Mechanism or ancillary services

intraday bilateral contingency transactions

intraday market segment of the power exchanges

rescheduling four time blocks ahead (right to recall).

Ancillary services are predominantly provided by thermal power plants. However, they have ramping limitations and cannot provide fast response (CERC, 2018b), which is needed in a power system that has to integrate rising shares of VRE. CERC proposed therefore to expand the scope of ancillary services to include hydropower generators under a new framework of fast response ancillary services for providing frequency regulation service.

CERC is also revisiting the rules and regulations concerning the Deviation Settlement Mechanism, ancillary services, the power markets and their nexus. It has observed that the mechanisms are often used over several hours to manage power system imbalances, thereby substituting energy trade within the intraday market (CERC, 2018a). CERC published a discussion paper related to redesigning provision of ancillary services, while also presenting proposals to improve the day-ahead market and the intraday market.

Furthermore, CERC has proposed the establishment of a clear gate closure time with binding schedules, which is an important step to improve the Indian power system in the future. A definition of minimal dispatchable unit is also needed to optimally mandate ancillary service-providing entities (CERC, 2018b). CERC’s reform aims to ensure that there are no barriers to entry and exit – no technology should be stranded and the system operator should be able to access the most flexible technology at least possible cost (CERC, 2018b).

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