The Government of India has specified Renewable Consumption Obligation (RCO)¹ and Storage Purchase Obligation (SPO) ² targets, which mandate the percentage of electricity procured that must come from renewables or electricity storage respectively. These mandates have been provided until 2029-30. To understand the implications of these mandates – in terms of the kinds of capacity addition, generation, costs and emissions – four scenarios were modelled in PIER as follows.

As can be seen from the table above, the first two scenarios (4_REF and 4_REF_RPOSPO_FY28to30) present two interpretations of the MoP notifications: the former assumes that similar notifications would be issued for future years, while the latter assumes that no further notifications will be issued⁵. Both these scenarios also assume reasonable limits on annual capacity addition of different types of generation based on India’s past performance and likely changes in future years. The latter two try to assess what would happen if the notifications did not exist – i.e. there were no RCO or SPO in any year. Of them, 7_REF_noRPOSPO assumes the same limits on annual capacity addition as 4_REF, while 8_REF_Unconstr removes this constraint for solar and wind and allows unlimited capacity to be added for them in any year from FY2028.

1. Capacity addition

When RCO mandates are removed, there is an increase in installed coal capacity – nearly 300 GW in 2041 in 4_REF_RPOSPO_FY28to30 and 7_REF_noRPOSPO, compared to just 264 GW in 4_REF, which have identical capacity addition limits. However, allowing unlimited solar and wind capacity addition (8_REF_Unconstr) brings the installed coal capacity figure in 2041 down to 276 GW – just 12 GW more than 4_REF but more than 20 GW less than the other two scenarios. See Figure 1. 

As expected, the scenario with the most stringent RCO and SPO requirements (4_REF) sees the highest RE and storage capacity addition – even more than 8_REF_Unconstr, where there are neither limits to solar and wind capacity addition nor RCO / SPO obligations. RE addition is naturally the least when no RCO is imposed and there are limits on how much RE capacity can be added per year. 
Greater RE and lower coal in 8_REF_Unconstr compared to 7_REF_noRPOSPO shows that, if it is possible to do so, the cost-optimal choice is to add more RE (and storage), rather than coal. Moreover, as discussed later, this scenario also has the least cost, indicating that enabling faster RE capacity addition by addressing bottlenecks to its expansion is both an economic as well as an environmental imperative. 

The relative mix of solar and wind across the different scenarios is also interesting. If unlimited solar and wind capacity can be added, the relative ratio of wind-to-solar capacity increases, though more solar capacity is added in both cases. In 7_REF_noRPOSPO, solar capacity in 2041 is 2.18 times the wind capacity whereas in 8_REF_Unconstr, solar capacity is just 1.8 times the wind capacity in 2041.  This manifests as 455 GW of (onshore) wind capacity in 2041 in 8_REF_Unconstr, compared to just 352 GW in 7_REF_noRPOSPO. 

Figure 1. Installed capacity (GW) in 2041 across scenarios

An offshoot of the changed solar-wind mix in the two scenarios also results in changed storage needs. BESS capacity in 2041 in 8_REF_Unconstr is just 108 GW compared to about 120 GW in 7_REF_noRPOSPO and 4_REF_RPOSPO_FY28to30⁶. The storage capacity in 2041 in 4_REF (which also has an SPO mandate for 2041) is as high as 190 GW. In other words, though more RE capacity is added in 8_REF_Unconstr compared to 4_REF_RPOSPO_FY28to30 and 7_REF_noRPOSPO, the storage capacity added in 8_REF_Unconstr is lower⁷.

One concern may be whether there is unrealistically high capacity addition of solar or wind capacities in the 8_REF_Unconstr scenario which has no annual capacity addition limits. As it turns out, that is not the case (Figure 2). The highest addition of solar capacity seen in any year in this scenario is about 72.5 GW in FY37. This is not unreasonable considering that India added 45 GW of solar in FY26, and China has added more than 250 GW per year for three years running from 2023 to 2025. This scenario adds more than 50 GW of wind capacity in three years with 63 GW in 2041 being the highest. While these numbers are significantly higher than what India has added in the past, they are not beyond the realms of possibility. For example, China added over 75 GW of wind capacity in each of 2023, 2024 and 2025 including over 120 GW of wind capacity in 2025. Thus, if India can come close to China’s current capacity addition more than decade into the future, the capacity addition identified is feasible, albeit ambitious.

Figure 2. Annual capacity addition of solar and wind in 8_REF_Unconstr (GW)

2. Electricity supply

Since the model optimises overall cost, as expected, generation broadly follows capacity addition. Forcing RCO and SPO through to 2041 (4_REF) leads to 300 – 400 TWh higher solar supply in 2041 compared to other scenarios. In order to meet the RCO of 70% in 2041, there is also higher hydro and biomass-based supply in 4_REF compared to other scenarios. Correspondingly, coal-based supply in 2041 in 4_REF is the lowest – 150 to 450 TWh lower than other scenarios. As a result, the 2041 generation mix has only 26% coal in 4_REF while renewables have a share of 72%⁸ .

The scenarios with the highest coal-based generation are the ones where there are limits on annual capacity addition and either no RCO or SPO is imposed (7_REF_noRPOSPO) or it is only imposed from FY28 to FY30 (4_REF_RPOSPO_FY28to30). In these cases, coal-based generation remains as high as about 36% even in 2041, and RE’s share is only around 60-61%. Figure 3 depicts these.

But, even when no RCO and SPO are imposed, but there are no limits on annual solar and wind capacity addition (8_REF_Unconstr), the share of RE generation in 2041 increases significantly compared to 4_REF_RPOSPO_FY28to30 and 7_REF_noRPOSPO, and reaches 67% in 2041 – only 5 percentage points below 4_REF. As a result, the share of coal-based generation is limited to 30% in 2041 in this scenario, compared to 26% in 4_REF and 36% in the other two scenarios. In line with the capacity addition, the relative ratio of wind-to-solar generation in 8_REF_Unconstr is higher than in other scenarios. In 2041, generation from wind is 66% of the generation from solar in 8_REF_Unconstr, compared to just 48% in 4_REF and 56% in the other two cases.

Figure 3. Generation in 2041 across scenarios (TWh) and shares of coal and renewable generation

3. Costs

It is also interesting to compare the average cost of supply (ACOS) of electricity across the scenarios. ACOS is estimated as the average cost of supplying one unit of electricity in a year. The costs considered include different components such as the fixed costs incurred on all the electricity generation and storage assets, the costs of transmitting and distributing electricity and the costs of procuring and using all the fuel that may be required.

ACOS decreases across all scenarios from 2024 to 2041, but the nature of decline varies across them. Beginning at Rs. 6.76 / kWh⁹ in 2024, it falls to Rs. 6.46 / kWh in 2041 in 4_REF, after hitting a low of Rs. 6.34 / kWh in 2040. In 7_REF_noRPOSPO and 4_REF_RPOSPO_FY28to30, which have minimal or no RCO mandates but have capacity addition limits for solar and wind, it falls to about Rs. 6.15 / kWh by 2041. The scenario with the sharpest fall and the lowest cost in 2041 is 8_REF_Unconstr where it falls to just Rs. 6.09 / kWh by 2041 (Figure 4).

Figure 4. Average cost of supply (Rs / kWh)

Figure 5. Share of different ACOS components in 2041

There is also a change in the composition of the ACOS over the years and across the scenarios. At the beginning of the model period, fuel related costs account for about 28% of the ACOS, while fixed costs of the generation and storage capacity accounts for 37% and the cost of transmission and distribution accounts for 35% of the ACOS. With an increase in share of renewables – which only have a fixed cost – across scenarios, the fuel cost comes down significantly across scenarios by 2041. As expected, the scenarios with the highest renewable penetration, 4_REF and 8_REF_Unconstr, have the lowest fuel cost share of just about 10% in 2041 (Figure 5). In the other two scenarios, it drops to about 12-13% in 2041. This drop is compensated almost equally by fixed costs of generation and storage, and transmission and distribution costs in all the scenarios, and their shares increase by about 7-9 percentage points each over the model period.

4. GHG emissions from electricity generation

Since GHG emissions from electricity generation are directly proportional to coal-based generation, it follows that a scenario with a higher share of coal-based generation also has higher emissions. However, since the scenarios adopt renewables through different routes – mandated for some years in the case of 4_REF and 4_REF_RPOSPO_FY28to30, and based on pure economics in the case of 7_REF_noRPOSPO and 8_REF_Unconstr – the trajectories of emissions across the scenarios are also different. 

When RCO is mandated all the way to 2041 (4_REF), the curve of emissions from electricity tends to stay low all the way, with emissions in 2041 (1.48 GtCO2e) being lower than emissions in 2024 (1.62 GtCO2e). But, if the RCO mandate is relaxed post 2030 (4_REF_RPOSPO_FY28to30), emissions start rising from 2031. If no RCO mandate is imposed, it tracks a higher trajectory (7_REF_noRPOSPO and 8_REF_Unconstr). However, from the mid-2030s the emissions trajectory of 8_REF_Unconstr deviates from 7_REF_noRPOSPO and bends lower, because it is able to add more renewables which is also economical. As a result, the annual emissions of 4_REF_RPOSPO_FY28to30 and 7_REF_noRPOSPO tend to converge by 2041 to ~1.95 GtCO2e. 8_REF_Unconstr comes close to 4_REF by 2041 though it remains above it at 1.63 GtCO2e (Figure 6). 

Figure 6. Annual GHG emissions from electricity generation (GtCO2e)

While the total emissions from electricity generation in 2041 are either lower (4_REF), roughly the same (8_REF_Unconstr) or higher (the other two scenarios) than 2024 emissions, the emissions intensity, i.e. emissions per kWh of electricity supplied falls across all scenarios, as may be expected with the increasing share of renewables (Figure 7).

Figure 7. GHG emission intensity across scenarios (kgCO2e/kWh)

Figure 8. Cumulative GHG emissions and estimated "cost of carbon"

Cumulatively, over the entire model period, it is not surprising that the emissions from electricity generation are the lowest in 4_REF (27.3 GtCO2e) and the emissions of 7_REF_noRPOSPO are the highest (31.4 GtCO2e). The cumulative emissions of the other two scenarios are roughly identical, are in between these two, at about 30.5 GtCO2e. However, as seen earlier, the ACOS of the scenario with the lowest emissions is the highest – thus, there is a price to be paid to lower emissions. Therefore, it would be interesting to analyse the price paid to abate GHG emissions in the various scenarios. This is done by considering the scenario with the highest cumulative emissions (7_REF_noRPOSPO) as the base and comparing other scenarios against it. The price of abatement is calculated as the total additional costs incurred by the scenario to supply electricity over the model period divided by the cumulative saved GHG emissions by that scenario. 

The cost of GHG abatement comes to about Rs. 3,650 per ton of CO2-equivalent in the 4_REF scenario which has the most stringent RCO and SPO requirements and the highest costs. This drops to about Rs. 3,560 per ton of CO2-equivalent in the 4_REF_RPOSPO_FY28to30 scenario where RCO is imposed only for a shorter period – which results in lower costs but also lower emissions reductions. The most interesting case is 8_REF_Unconstr, where there are no capacity addition limits on solar and wind and no mandates, and all decisions are made purely on economic grounds. In this case, the total cumulative cost of electricity supply is lower than in the 7_REF_noRPOSPO scenario, leading to a negative abatement cost of about Rs -1,360 per ton of CO2e. See Figure 8 for details. 

To summarise, the 2041 emissions in the 8_REF_Unconstr scenario are comparable to the 4_REF scenario (and lower than the other scenarios), its cumulative emissions are not much worse than the scenario with the lowest emissions, and its overall cost is lower than the other scenarios. Since this scenario does not involve any mandates but has relaxed limits on annual solar and wind capacity addition, it suggests that, rather than imposing mandates that are hard to enforce, an economical and environmentally friendly path for India would be to enable easier and higher addition of renewable capacity on the one hand, and adopt economically prudent power procurement methods on the other. 

5. Conclusions

This article compares four different trajectories that differ in mandates for renewable energy and limits on capacity addition of renewables for their impacts on various aspects such as capacity addition, generation, cost and GHG emissions. While the results are broadly as expected – imposing the most stringent renewable consumption mandate leads to the lowest GHG emissions – the interesting observation is the comparison between a scenario driven purely by economic considerations and with no limits on annual solar and wind capacity addition (8_REF_Unconstr) and the scenarios that have some RCO mandates (4_REF and 4_REF_RPOSPO_FY28to30). 

Given the changing economics of renewables versus coal-based generation, the purely economic scenario not only ends up with lower costs of electricity supply but also with emissions that are not too different from the scenario with the most stringent mandates. Moreover, the amount of annual renewable capacity added in such a scenario, while being ambitious, are far from unrealistic. In other words, ensuring analytically-based and economically prudent power procurement combined with a policy environment and institutional mechanisms that enable faster addition of renewables can be a cheaper and effective path to decarbonising India’s power sector than imposing mandates. Enabling such accelerated solar and wind capacity addition is likely to require not only policies that make it attractive to invest in renewables and storage, get transmission connectivity etc., but also policies and mechanisms to ensure fair compensation to individuals and communities whose lands and livelihoods are likely to be affected. 

Endnotes

# This article is based on the PIERv2 model and the primary author is Ashok Sreenivas. The PIER team acknowledges the valuable review inputs of PEG colleagues Shantanu Dixit and Ashwin Gambhir.

* PIER: Modelling India's energy system from FY2023-24 to FY2040-41 (Version 2.1 Demand+Supply Model+Docs). Prayas (Energy Group). 2026. https://doi.org/10.5281/zenodo.18043483

1 Gazette id CG-DL-E-23102023-249637, dated 20th Oct 2023, on Renewable Consumption Obligations notified by Ministry of Power

2 Order dated 22nd July 2022 on Storage Purchase Obligation trajectory till 2029-30 from the Ministry of Power

3 Some scenario names have RPO” (Renewable Purchase Obligation) in them though they are modelling RCO”s (Renewable Consumption Obligation) because the RCOs were initially called RPOs.

4 Reference to any year is to the corresponding fiscal year – i.e. 2030 refers to 2029-30 and so on.

5 An additional difference is that 4_REF only imposes the obligations from 2030, but since the obligations stop in 2030 in the 4_REF_RPOSPO_FY28to30 scenario, it imposes the obligations from 2028 onwards.

6 Pumped storage numbers are broadly similar across the scenarios

7 It should be kept in mind that energy systems models such as PIER may not value the various contributions made by electricity storage systems to the grid and hence may install a little less of them than desirable.

8 The share of renewables is 72% though the RCO mandate is only 70% because the 70% mandate applies only to end-use consumption and 100% of the electricity required to produce green hydrogen is from renewables.

9 All the costs are in real terms – in terms of 2024 Rs.