The Central Electricity Authority (CEA) has prepared a draft resource adequacy plan to maintain adequate generation capacity to meet future energy demands.

The document says that it had become imperative to plan for the increasing share of variable renewable energy in the total energy mix. Distribution licensees seeking to move away from long-term power purchase agreements (PPAs) could lead to erroneous calls on contracting. This could result in over or under-provisioning of generation and lead to surplus or deficient situations in the short term as renewable energy generation fluctuates.

One of the main aspects of resource adequacy planning was to ensure that adequate generation capacities were available to cater to the demand. The draft plan said that it was necessary to develop a resource adequacy framework to suggest the optimal capacity mix required to minimize the total system cost in meeting the projected demand for the future.

It was important to determine the duration of time when a loss of load can occur due to demand forecast errors, generation forecast errors, outages, and weather phenomena.

The draft report points out that energy storage and other resources, which can help balance out the variability and intermittency of renewable energy, must be considered to ensure reliability and reduce system costs.

The draft plan says utilities must undertake an optimal reserve margin study to determine the planning reserve margin through any scientific method, provided the determined planning reserve margin is higher than the national-level planning reserve margin. The capacity planning by utilities should be developed through an integrated resource plan.

Integrated resource planning

A utility prepares an integrated resource plan to determine the target generation capacities for meeting the forecasted energy demand over a specified period.

The plan requires many inputs, such as demand profiles, demand growth rates, contracted capacities, and cost for new capacities. The model can optimize for various technologies such as renewable, conventional, distributed energy resources, demand-side management (DSM), and energy storage resources.

The proposed plan states that the model would undertake the least cost generation optimization to meet the demand to minimize the overall system cost, including capital costs, operations and maintenance costs, costs to procure spinning reserves, fuel costs, transmission costs, and start-up and shutdown costs.

Resource adequacy will be determined based on resource availability and accessibility after consideration of sharing reserves from other utilities and states through the national markets or bilateral mechanisms.

Compliance monitoring

CEA will publish the long-term national resource adequacy plan, which will determine the optimal planning reserve margin requirement at the all-India level conforming to the loss of load probability and normalized energy not served targets.

It will publish the optimal generation mix required for the next ten years to ensure that the national-level system is resource adequacy-compliant while meeting the all-India demand at the least cost.

The Power System Operation Corporation (POSOCO) will annually publish a one-year look-ahead short-term national resource adequacy plan which will include parameters such as demand forecasts, resource availability based on the under-construction status of new projects, planned maintenance schedules of existing stations, station-wise historic forced outage rates, and decommissioning plans.

The hourly demand forecasts used by POSOCO will be aligned with the projections per the individual distribution licensees. The state transmission utility or the state load despatch center, on behalf of the state’s distribution licensees, will provide POSOCO with the details regarding hourly demand forecasts for the next five years by June every year.

The distribution licensees should demonstrate to the state electricity regulatory commission a 100% tie-up for the first year and a minimum 90% tie-up for the second year to meet the requirement of their contribution towards meeting coincident national peak.

For the next three years, the distribution licensee should submit a plan for 100% capacity tie-ups to meet the estimated requirement of their contribution towards meeting the coincident national peak for SERC’s approval.

The optimal target level or planning reserve margins should be arrived at through measures such as the loss of load probability and normalized energy not served. Loss of load can happen due to factors such as forced outages, planned maintenance of conventional generation, unforeseen real-time excursion in demand, demand forecast errors, generation forecast errors, and renewable energy intermittency.

Determination of capacity credits for renewable resources

According to the draft report, it is important to determine how much energy-limited resources (hydro, wind, solar, storage) will count toward resource adequacy requirements. Generation planning will become more complex as larger amounts of weather-based, variable renewable generation are added to the system.

Each generator can provide a ‘firm capacity,’ representing the amount of power the generator can reliably provide. Capacity credit expresses firm capacity as a percentage of the installed nameplate capacity.

The following are the various methodologies adopted internationally to determine capacity credits of renewable energy.

• Capacity credit approximation with top demand hours: In this case, a basic approximation of capacity credit can be obtained by averaging the historical contribution during peak demand hours. However, the selection of how many peak demand hours to include often varies across geographies.
• Capacity credit approximation with top net load hours: In this case, consideration is given to the fact that periods of system stress occur when high demand coincides with low renewable energy generation. The net load is the total renewable energy generation subtracted from overall demand, which must be met from dispatchable resources like thermal plants and hydro projects.
• Expected load-carrying capability: The model uses hourly time-series demand data for a particular period in this method. It also uses the availability of different generation resources at each hour of the year. Random outages of generators are also applied, considering the historical and expected outage conditions.

The utilities must plan their firm capacity as per the coincident peak, which implies that the capacity credits of all resource types are to be calculated on the national-level load profile.

According to CEA’s recently released National Electricity Plan, India needs to add 224.9 GW of renewable energy generation capacity by 2032 to meet the peak demand and energy requirement for the financial year 2031-32.

The all-India peak power demand touched an all-time high of 201.066 GW on April 26, 2022, surpassing the peak power demand of 200.539 GW met on July 7, 2021.