Last week saw Union Coal Minister Piyush Goyal pulling up Coal India for not meeting production and sales targets, and for delays in floating tenders that led to deteriorating coal stock at power plants. Later that week, at an awards ceremony, he assured everyone that all issues that recently surfaced over coal output and supply would be resolved soon.

The current dependence on imports, Goyal clarified, was because of the previous government’s insistence that power plants be designed for imported coal. Corrective measures now would lead to production growth and improvement in quality.

Action on the coal front is timely, and especially for the energy sector. Yes, there has been a lot of enthusiasm in the last four years in the renewable energy (RE) sector – led by the exceptional target of 175 GW by 2022, the government’s policy push, and the immunity for players that comes from the central government’s offtake and implicit guarantee. Yet, coal remains the mainstay of the power sector in the short to medium term.

Imported coal, though of a better quality, is expensive. The argument for renewable energy was that it would be cheaper and, therefore, preferable to new thermal plants based on such (expensive, imported) coal. But if indigenous coal supplies were to improve in quantity and quality, the picture changes by a fair bit.

In this scenario, given the economics – as also the politics – of existing coal facilities, renewable energy’s “falling costs” are not enough to outdo coal’s role – till at least 2030. A Brookings India report in September, authored by Rahul Tongia and Samantha Gross, demonstrated this. We touched upon this previously here. Briefly, the report’s authors argued, that despite the falling costs of renewable energy, the notion of “grid parity” at which point renewable energy overtakes coal was notional – and it did not take into account hidden- or system-level costs of renewable energy. We will discuss these later.

Current happenings in the RE sector do point towards unpreparedness in absorption of the supply of RE, and here a case in point is the recent ongoing tariff dispute in Karnataka between KERC (Karnataka Electricity Regulatory Commission) and SECI. SECI’s tariff of Rs 4.50 per unit is unacceptable to KERC, who insists state discoms pay no more than Rs 4.36. These tariffs go back to 2016, when SECI had conducted auctions for 970 MW of solar projects in Karnataka at Rs 4.43 per unit. With the projects now complete, SECI was to sign PSAs with four discoms, including Bescom and Hescom; SECI says Rs 4.50 is its buying rate and hence non-negotiable, but KERC wants the Rs 4.36-rate as per its May-2017 order setting the feed-in tariff. For now, Appellate Tribunal for Electricity (APTEL) has stayed the KERC order and asked them to go with Rs 4.50.

Whether KERC is justified in this scenario is irrelevant, when we go deeper into why states and discoms may not share the enthusiasm of the Centre for RE. That has to do with the many complexities of integrating RE into the grid.

A fresh report from Brookings in November, Integrating Renewable Energy Into India’s Grid – Harder Than It Looks by Rahul Tongia et al, provides relevant perspectives.

On the supply side, things are relatively smooth: developers’ costs and risks are kind of underwritten by the central government, and the low tariffs still don’t make the RE business unviable – experts’ terming of falling tariff levels as “irrational” notwithstanding. Thus issues like input costs of solar panels and rupee depreciation would also not be significant-enough deterrents; just blips to be overcome. A 3GW-bid in July was oversubscribed 2.1 times, with the winning bid at the now-stabilised rates of Rs 2.44 per kWh. And when response to two new mega tenders was lukewarm last week, SECI revised tariffs upwards to garner a positive response. So far, so good.

The problem is the demand side: the discoms are at a loss as to how to make space for this new baby called RE. Tongia et al reason out how two factors create problems for discoms: one, the variability in the supply of RE – being dependent on sunshine, wind etc; and two, backing down power supply from coal-fired plants. While the former makes supply unpredictable and unavailable-at-call; the latter is expensive and even hazardous. And these are set to escalate as RE is scaled up to target levels of 175 GW by 2022, and higher in the future.

In the case of Karnataka, for instance, the Greening the Grid (GTG) report of 2016 – the main study about the viability of integrating RE into the power grid – had made certain assumptions that now appear simplistic; like the wind output on a particular day (16 July for demonstration) has been estimated in GTG as a smooth curve (not shown here) at a certain level. However, the charts below show that the actual full-state wind output for 2014, 2015, and 2016 was far more variable – also lower than estimated in some years (the decline is not to be taken as a trend, but owes itself to randomness).

Actual wind output on 16 July for Karnataka

Again, for Solar, GTG had assumed a smooth output curve, which the authors argue, need not always be the case for any given day, even at the full-state level. Apparently, the assumptions in GTG take the best-case scenario. More needs to go into studying how to optimise grid integration, they say, as GTG still “explicitly doesn’t examine contractual economics of power plants, something state load dispatchers would need to worry about.”

This higher variability implies that the discoms need to balance more between sources of power, and coal bears the burden of this uncertainty, filling up or backing down (called “flexing”) – as the situation demands. Tongia et al say that it is this variability that has led Karnataka to choose to move away from large solar parks.

It would be simple if coal plants could change or flex output at will. But it does not work like that. Though the assumption made is that all coal plants can go down to 55-per cent output, fact is there are costs for ramping and start-stop operations. Even technically, doing this depends on the vintage of the plant and its design. Newer ones can, but for older ones, severe economic and operating penalties would apply. But even for newer plants, would we want them to reduce output given that they are the more efficient ones?

And if investments for enabling flexing are imposed as a compliance requirement, it would in effect mean that coal plants would be paying huge sums of money per GW to reduce their output – an absurd idea! – as witnessed at NTPC’s testing at Dadri.

The way things work is that each state is responsible for buying sufficient power demand, and state Load Dispatch Centers (LDC) choose which suppliers to call to meet instantaneous demand. It is their responsibility to not just keep the grid in balance, in coordination with regional LDCs, who manage inter-state flows of power, but also costs – they aim to run the system at the lowest cost. Discoms anyway have to pay coal’s fixed costs – whether they draw power or not, so using existing thermal capacity for more output would make more sense than adding new RE.

As of today, there is incentive to underutilise RE, because load dispatchers treat coal and RE plants differently in terms of fixed and variable costs.

Apart from generation costs, there are the systems-level costs of RE. Accommodating RE can raise costs of other generators, who have to lower their output. Lowering the output of coal plants causes not just wear and tear but also lowers the thermal efficiency of such plants and increases SOx and NOx emissions. Central Electricity Authority’s December 2017 study on such costs of RE estimated the impact to be about Rs 1.5/kWh of RE. This is very high compared to bid Levelised Cost of Energy (LCOE)s costs of about Rs 2.5/kWh currently. RE’s hidden costs need to be quantified and incorporated into the economics of contracts.

If backing down coal with minimal costs is one problem, the other is the unfair burden on RE-rich states of the cost of grid integration. Their solutions would be either to:
a) deploy storage technologies, which are expensive today, and that would increase costs of RE considerably;
b) throw away RE – that is, curtailment;
c) improve transmission to ship power to other states; for this, the government is planning ‘green corridors’, but the report estimates that the costs of such transmission could easily be Rs 1 per kWh above and beyond today’s average transmission costs. Even from just a costs point of view, this is overwhelming, leave alone technical challenges involved.

With grid strengthening, some of these costs may come down and RE costs will also fall further, but with RE share rising, overall costs may still be high. So, when we talk about tariff bids going low, this takes into cost the developer’s LCOE. But for the grid, the system-level costs – transmission requirements, impact on other generators, need for alternatives that can step in at short notice – would also count.

At another level, the Indian power scene has some peculiarities that make RE deployment almost foolish: as the chart below shows, India’s demand for power is near-flat over 24 hours, with not much difference between peak and off-peak demand. In other countries, this difference is much larger and that helps solar – more demand during the day could be met by solar, which is also available in the day.