The Rajasthan Electricity Regulatory Commission has notified the Framework for Resource Adequacy Regulations, 2026, which outlines a mechanism for planning generation and transmission resources to meet projected power demand.

The regulations apply to generating companies, distribution licensees (DISCOMs), the State Load Despatch Centre (SLDC), the State Transmission Utility (STU), other grid-connected entities, the power procuring entity on behalf of distribution companies (DISCOMs), and stakeholders in Rajasthan.

DISCOMs must prepare long-term distribution resource adequacy plans (LT-DRAP) for 10 years, medium-term distribution resource adequacy plans (MT-DRAP) for 5 years, and short-term distribution resource adequacy plans (ST-DRAP) for 1 year.

Demand Forecasting and Peak Assessment

Demand forecasting must cover hourly or sub-hourly assessment using comprehensive input data, policies, and scientific modeling tools. For long-term ten-year forecasting, seasonal representative hourly profiles may be used instead of full 8,760-hour granularity, subject to Commission approval.

DISCOMs can use electric power survey projections as a base or adopt other methodologies, with justification, and are required to select methodologies based on statistical analysis that minimizes standard deviation and maximizes R-square. DISCOMs must also required to develop at least three demand forecast scenarios: most probable, business-as-usual, and aggressive.

Forecasts may be modified by considering factors including demand-side management, open access, distributed energy resources, demand response, electric vehicles, tariff signals, agricultural load variations, seasonal crop patterns, festivals, and policy impacts. Energy forecasts will consider distribution losses as well as intrastate and interstate transmission losses.

The regulations provide that peak demand will be determined using the average load factor, load diversity factor, seasonal variation factors for the last five years, and energy forecasts. They also require separate determination of peak demand for summer, monsoon, and winter seasons, as well as evening ramp-up requirements.

The State Load Despatch Centre (SLDC), with inputs from DISCOMs, will estimate demand for the entire state across different time horizons, submit forecasts to higher-level load despatch centres, and aggregate demand at the State level.

Capacity Credit and Planning Reserve Margin

Capacity credit is defined as the firm capacity, expressed as a percentage of installed nameplate capacity, considered in meeting resource adequacy requirements. It is to be determined on a technology-, location-, and season-wise basis, taking into account actual generation performance, forced outage rates, fuel availability, and resource variability.

For renewable energy resources, the regulations prescribe a net load-based methodology for determining capacity credit. The methodology uses load duration curves and considers the top “x” load hours, where x is either 250 hours or 10% of the annual hours (876 hours), as determined by the Commission based on the State’s load characteristics.

Capacity credit for hydro generation will be computed based on water availability, with separate treatment for run-of-the-river and storage-based projects, and capacity credit for thermal generation will be computed based on fuel availability and forced outages. SLDC will compute State-specific capacity credit factors and share them with national agencies.

For new renewable energy projects with less than five years of operational data, capacity credit will be based on available data along with benchmarks approved by the Central Electricity Authority (CEA) or the Commission, where applicable.

The regulations define planning reserve margin (PRM) as the percentage of capacity above the State’s coincident share of national peak demand for generation resource planning. They state that the PRM will be based on reliability indices, including loss-of-load probability and normalized energy not served, as prescribed by CEA. The PRM for Rajasthan will not be less than 10% unless otherwise specified by the CEA or the Commission.

Procurement Planning and Resource Mix

DISCOMs should determine capacity requirements to meet demand and PRM, after accounting for available capacity and adjusting for the capacity credit of existing and planned generation resources. They provide that long-term contracts will constitute 75 to 80% of the total supply-side resource adequacy requirement (RAR), medium-term contracts will constitute 10 to 20%, and the balance will be met through short-term contracts.

They specify that power procurement through the day-ahead market (DAM) and real-time market (RTM) will not be considered toward meeting RAR, and that the Commission may revise these percentages through a separate order.

DISCOMs must demonstrate 100% tie-up for the first year and a minimum 90% tie-up for the second year toward meeting their contribution to national peak demand, and to furnish plans for subsequent years. They also provide that the share of long-term contracts will be at least equal to the higher of the requirements to meet the national peak and those derived from internal planning.

The regulations further provide that procurement planning will include the optimal resource mix, procurement type and tenure, and capacity sharing, and that procurement will be undertaken first within the region, subject to least-cost considerations and transmission constraints, and thereafter from outside the region if required. They also require DISCOMs to consider capacity sharing mechanisms and interstate trading platforms.

DISCOMs must contract storage capacity corresponding to the requirements identified in the LT-DRAP, including from battery energy storage systems, pumped storage projects, or other storage technologies, in accordance with the Ministry of Power guidelines. The capacity credit for storage systems will be determined based on energy duration, round-trip efficiency, degradation factor, and dispatch constraints. Hybrid renewable energy and storage projects may be treated as a single resource for capacity credit computation with combined firm capacity.

The regulations allow procurement of power from various sources, including generating stations, independent power producers, captive power projects, renewable generators, traders, aggregators, and power exchanges. They also state that DAM and RTM transactions are allowed for balancing purposes but will not be counted toward firm RAR.

DISCOMs may undertake additional procurement in cases of increased demand, supply shortfalls, or when alternative sources are more economical. They may enter into short-term or banking arrangements with other States in emergency or grid-stability situations, without prior approval, under specified circumstances.

Approval, Compliance, and Timelines

Any new capacity arrangement or tie-up, as well as any new long-term or medium-term power purchase agreements and amendments to such agreements, will be subject to the Commission’s prior approval.

DISCOMs must comply with resource adequacy requirements within the specified timelines and may be subject to non-compliance charges as determined by the Commission. They also state that DISCOMs will not be penalized for non-compliance arising from reasons beyond their control.

The regulations prescribe timelines including submission of demand forecasts to SLDC by April 30 each year, submission of state-level data to the CEA and national load despatch entities by May 30, allocation of national peak shares within 15 days of publication of national plans, submission of LT-DRAP to CEA by September 30, submission to the Commission within 15 days of CEA approval, approval by the Commission within 30 days, and submission of contracted capacities within 30 days thereafter.

If communication from the National Load Despatch Centre regarding balance capacity shortfall is received after January 31, the distribution licensee will be granted an additional 60 days from the date of such communication to complete contracting of balance capacity.

Data Sharing

DISCOMs must maintain and share data related to demand forecasting, including historical demand, weather data, demographic and econometric variables, loss levels, and consumption patterns. They provide that DISCOMs will maintain at least 10 years of historical data, or data from the available period, and build toward 10-year data availability on a year-by-year basis.

They must publish procurement and scheduling information. Monthly, weekly, day-ahead, and intra-day power procurement or sale data, and generator schedules, are to be published on the websites of DISCOMs and SLDCs within 45 days. SLDC is also required to publish the monthly Merit Order Dispatch stack along with the per-unit variable cost of each generating station.

DISCOMs should establish a planning cell for resource adequacy within three months of the regulations coming into force, and constitute a round-the-clock cell for real-time power procurement and sale. They also provide that resource adequacy plans will be prepared in consultation with generating companies, transmission utilities, load despatch centres, and the CEA, and may involve consultation with research agencies, trading companies, and other market participants to assess the availability and pricing of power.

The Commission recently directed all DISCOMs in the state to prepare and submit comprehensive resource adequacy plans in accordance with the Central Government’s guidelines.

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