Last week, the winning bid for a solar project in Rewa, Madhya Pradesh, offered a levelized tariff of about Rs3.3 per unit (with first year tariff at Rs2.97). That’s 24% cheaper than the Rs4.34 per unit offered by the winner of the Bhadla solar park project in Rajasthan in January 2016.
Such a plunge in tariff was made possible only because the developer, under a power purchase agreement, has been assured of the following: timely and complete payment security, prevention of shutdown of the solar power plant during grid instability or unavailability of transmission line, ensuring free land availability for construction, and assuring transmission or evacuation facility for offtake of power.
In other words, many material risks were off the table. Such sweetheart deals may not be available for all upcoming solar bids since it will be largely dependent on the credit-worthiness of the electricity buyer, availability and price of land, and transmission modalities.
In other words, the solar tariff of about Rs3.3 would remain a pipe dream if risks related to payment, curtailment, land and transmission are not mitigated in future projects.
Theoretically, such tariffs also mean the solar sector has reached grid parity in terms of not just the power purchase cost of new thermal electricity generating stations, but also the all-India average pooled power purchase cost of discoms.
To be sure, policymaking corridors are reverberating with calls to replace new capacity addition in thermal with solar, but that would be an uninformed move without taking an integrated view on addressing peaking shortages, efficiency of thermal generation, grid management, overall balancing cost, and the socialization charges of solar generation.Essentially, this would require addressing four flanks.
First is that there is a mismatch in the timing of generation and peak electricity demand—demand peaks in the morning and evening, when solar generation is not possible. Also, with batteries and storage still expensive, increasing solar share would require greater balancing with hydro/gas-based power to smoothen out the variability and peak demand. In other words, commensurate investment in hydro/gas would be needed to maximize solar generation.
Second, there is the milieu to contend with. While the Central Electricity Authority (CEA) has reported a power surplus situation, demand has been sluggish in the past one year. Additionally, about 40 GW of thermal power plants are under construction.
All that means is growth in solar will have an impact on the plant load factor (PLF) and efficiencies of existing and new thermal projects. In other words, their cost of generation and the overall cost of power in the grid will rise.
The CEA, in its recent draft National Electricity Plan (NEP), projects thermal PLFs to be at 48% if capacity addition in renewables is 175 GW by 2022, and at 54% if it is 125 GW (which is the CEA’s bear case capacity addition). Such low PLF levels will not only have an impact on the commercial viability of projects, but also lead to inefficient thermal generation that affects sector viability and sustainability of environment.
For instance, any reduction in PLFs beyond a threshold will lead to higher station heat rate, and consequently higher coal consumption and poor efficiency. Therefore, capacity addition in renewable energy needs to be synchronized with the ecosystem such that efficiency loss in thermal and the balancing cost is minimized.
Third, there is a limit to how much inconstant power a local grid can support, which can cause stability issues. A target of 175 GW translates to around 75% of India’s peak load requirement by fiscal 2022.
Absorbing such a high quantum of inconstant power will require access to a greater balancing area. While most of the capacity addition in renewables has taken place on a state-level basis, there is a need to encourage interstate transactions for such energy.
For example, Jharkhand, which invited solar bids for 1,200 MW as against its local peak demand of close to 2,000 MW, will most likely face challenges in efficiently managing grid issues in the near term. This will require successful implementation of the availability-based tariff mechanism, good forecasting capacities, scheduling framework at the state level, and implementation of electronic metering infrastructure.
Fourth and last, while the Central Electricity Regulatory Commission currently exempts inter-state transmission charges for renewable energy, there is a need to re-evaluate both the direct and indirect impact of renewable energy on transmission charges in the context of loading excess cost on other forms of power generation.
The direct impact of renewable energy is that associated transmission charges fall on thermal counterparts, while the indirect impact will be because of reduced utilization of transmission capacity owing to the lower PLF of thermal projects.
So while falling solar tariffs augur well, the sustainability of an aggressive capacity-addition target of 125 GW for renewable energy will depend on balancing cost, efficiency of thermal generation, grid management, and investments in hydro- and gas-based power to meet peak demand.