The evacuation and integration of renewable energy faces various issues and challenges, which include high costs of transmission and energy storage systems, inadequate levels of accuracy in forecasting and suboptimal despatch optimisation. Transmission capacity addition needs to be undertaken to keep pace with renewable energy capacity additions. While implementing renewable energy projects, developers typically do not factor in the power curtailment resulting from transmission constraints. The lack of transparency in the kind of curtailment (technical or economic) faced by developers also poses a serious challenge. At a recent Renewable Watch conference on “Evacuation and Integration of Renewable Energy”, senior industry representatives discussed the changing requirements, growing challenges and emerging solutions and technologies. Excerpts…
As developers, one of the things that we do not focus on at the outset of bidding is curtailment. Currently, I am not aware of any independent power producer (IPP) or developer that factors in the acceptable levels of curtailment. It is only after the project is commissioned and operational that we begin to question why the actual revenue is falling short of the estimated figure. Curtailment is acute, especially in windy season. We need to look at the false comfort that the grid code gives us in terms of the must run status, the exemption permit or the merit order despatch. It is time we start seeing curtailment as a key issue.
Currently, for a large geographically diversified portfolio of an IPP, the curtailment level may be 1-1.5 per cent. So, it is not really a big issue as of now. If I take the case of Brookfield, which had a large asset base in China, the levels of curtailment were in the range of 25-30 per cent. It is very high and, in fact, all the discussion about projects in China used to be about curtailment. Developers in India are very fortunate that we have not reached that kind of curtailment levels. From an operational O&M perspective, the government typically does not give any concession for curtailment.
However, it needs to consider concessions, given the way the curtailment is reported. There is an issue of transparency, as, currently, it is claimed that most of the curtailment is due to technical issues but it may be due to economic factors as well. That is one of the reasons for developers to seek the removal of the load despatch operations from the purview and mandate of the state transmission utility. It has been done at the central level and should be implemented at the state level too.
Also, it must be noted that the government’s T&D expenditure is not in line with the capex on developing the generation capacity. While globally, the capex ratio between T&D and generation is 1:1, in India, it is probably half of that.
Meanwhile, I think, we should be able to come out of this exemption business for renewable energy and send out the right signals for the kind of transmission capacity that will be required.
Hero Future Energies has a large portfolio in Karnataka, including a hybrid solar plus wind plant. We are facing the issue of curtailment, especially during the wind-rich months but it is not severe as of now. A plant’s revenue model is mostly centred on those high wind months and the level of curtailment is 10-15 per cent during this period. Overall, on a yearly basis, it is 2-3 per cent. However, with the growth of renewable energy capacity in the state, we can foresee this issue becoming larger.
We are now working towards devising a solution for this problem. One way is to jointly resolve the constraint on the transmission side. In most cases there is a common substation where a number of solar and wind power generators are pooling their power. So, in case the substation or transformer capacity has to be enhanced, the developers as a consortium should come along and add the capacities by themselves.
Typically, most of the thermal power plants have been developed in coal pit areas. Unfortunately, these coal pit areas do not have good global horizontal irradiation (GHI). Meanwhile, the GHI-rich areas such as Rajasthan neither have industry, nor coal resources. So, according to me, the country should be divided in various zones for transmission planning. Each zone should have a separate bid. Under this mechanism, the evacuation infrastructure cost should also be a part of the tariffs quoted by developers. It will help in the precise calculation of the evacuation and transmission costs. This will ensure that there are no delays due to transmission constraints.
India has a massive target of installing 175 GW of renewable energy capacity and a large part of it has to be ISTS-connected. But recently, a large number of tenders and projects got delayed due to the lack of transmission infrastructure. It must be noted that the shorter gestation period of renewable energy projects vis-a-vis that of transmission projects leads to a mismatch, thereby resulting in commissioning delays. The transmission system should, therefore, be planned keeping in view the entire renewable energy potential of a particular area and the construction could be taken up in phases to mitigate such situations. Also, transmission planning should be done in consultation and collaboration with all the renewable energy developers and transmission developers.
I must say that the current crisis is being managed in a very realistic way. The Transmission Planning Regulation, issued by the CERC, is a positive step towards a coordinated planning process where stakeholders will be involved right from the planning process. I would like to appreciate the policymakers’ call that competitive bidding can solve the problems in the best possible way and at the least possible cost.
There are a number of smart ways to integrate renewable energy such as the promotion of tail-end load centric community projects with one-way power flow, the harmonisation of technical feasibility, the transition to hybrids and higher investments in energy storage.
There is about 68 GW of renewable energy generation capacity that will require transmission infrastructure. Of this, around 33 GW of capacity has been handled under Phase I of transmission planning. It is at the bidding stage and is likely to be allocated in June 2019. The balance capacity will be handled under Phase II for which transmission planning has already been done. However, there is still a long procedure that needs to take place before this transmission capacity is actually allotted for construction. If these procedures do not take place in time, we will end up in another crisis. It will take the National Committee on Transmission four to five months for finalising Stage II bidding, another four months to conduct the bidding and 24 months for the actual construction.
If the 175 GW dream is to be realised by December 2022, we need to work like we would in a firefighting situation. We need to plan fast and execute faster. I believe that 24 months are sufficient for the required transmission infrastructure to come up for any voltage level, and for any distance.
There are three challenges, these are related to the holistic economics of renewable energy, grid management and keeping up with the pace of capacity addition. First, for the holistic economics of renewable energy, it is important to factor in the system level cost impact on discoms, retail tariff and incumbent thermal power plants. The main point here is that the cost of the overall system should include the capacity charges for ramping down thermal generation. The system-level implication cost to the discom really needs to be considered when looking at grid parity. It should also be noted that if the transmission charges are, say, Re 0.20 per unit for a thermal plant, it will be around Re 0.55 per kWh to Re 0.60 per kWh in the case of renewables, due to a much lower plant load factor. So, that is an additional cost of transmission of renewable energy. And, making it despatchable adds to storage. Hopefully, storage will repeat the story of solar PV in terms of cost. One of the things that I feel could help is not to charge cess on flexible thermal plants and those that meet the environment norms. That will need a lot of advocacy. While it is beneficial for end consumers, the government does not lose out in terms of paying for viability gap funding on capex, hence, the consumer should not pay for this. When you have more flexible thermal plants, they are the ones that will be backed down first for balancing the grid. Normally, the flexible thermal plants are the latest generation plants which are very efficient, in terms of the cost per unit.
Second, making the thermal plants flexible will add to capacity charges. So, using flexible thermal is a good idea, but the opportunity cost or the additional cost of backing it down is more than that of a dirty plant. So, if we look at this in aggregate terms, we might come to a conclusion that the dirty plant should be decommissioned rather than making it flexible. This is something that we really need to talk about.
It will be better to have flexibility in renewable energy plants, rather than spending more money on making thermal plants flexible. Over the next 15 years or so, if we don’t add more thermal power, its generation will come down, and the renewable energy requirement will correspondingly go up. If we have the “flexibility” component in the auction tenders, it will give a trajectory for the sale of renewable power. It could cost more because the tariff would definitely be higher than the cost of making thermal flexible. Somebody should do an economic analysis to assess the overall cost of power when renewable energy plants are made flexible. Initially, it will cost more, however, over a period of time, it might become economical, leading to tapering off thermal generation.
Under grid management, the key issue pertains to limited availability of additional power and reserves in terms of storage. The lack of accuracy in forecasting is another problem. I hope renewable energy management centres (REMCs) will solve this over a period of time. For ensuring more accuracy in forecasting, some sort of penalties should be considered. One of the things that need in-depth study is suboptimal despatch optimisation, commonly known as merit order despatch. The cost of keeping renewable energy as a “must sell” has to be seen in terms of the overall cost of power which reaches the consumer. There are technical issues of thermal plants not being so flexible as to allow the must run status of renewables at a time when renewable power generation is very high. We are looking at something like 160 GW of solar and wind power versus maybe a 200 GW of peak demand in 2022. Today, the peak demand is 160-170 GW. If we are going to have 160 GW itself of renewables, how are we going to manage that kind of a show.
Last, power transmission augmentation needs to keep pace with renewable energy capacity addition. The Green Energy Corridor programme is being implemented in eight states but the ongoing auction only seems to be driving solar in Rajasthan and wind in Gujarat. This is a cause for concern. Another challenge is the commissioning schedules. While an ISTS-based solar or wind project takes about one-and-a-half years to be commissioned, a transmission line may take around three years to be complete. As a result, the timeline for the waiver of interstate transmission charges needs to be extended. A much bigger challenge awaits on the distribution side in terms of handling rooftop solar, electric vehicles, etc.
However, the future of the transmission and distribution market in India is promising. The government is focusing on providing 24×7 power to all. This will require strengthening of the state grids to ensure last-mile connectivity. India will also need large investments in grid infrastructure for balancing the energy transmission from thermal, renewable and other sources.
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