Any color on any other nuclear project which you think you can take up in the next 24 months?
As far as anything over and above this is concerned, we are right now in the process of identifying locations. 30 locations across India are being explored. We have entered into MoU with MP government, Chhattisgarh government; and joint working group, has been formed; and consent given by government of Andhra Pradesh and studies have been completed. So we are working on the ground level thing, ensuring availability and the broad feasibility. But right now, we are under execution, we can say, is Mahi Bainswara project alone.
On coal gasification plans and targets — which are the specific projects we are working on, what type of capacity and time lines?
We have started coal gasification, we have taken up a pilot project at one of our mines, Talaipalli. And we are going to EIL, and this has a capacity of 4 lakh tonnes per annum. And this is basically for synthetic natural gas production. It's a pilot project. So it's initial stages. We'll keep you updating more on as we progress on this.
Any plans around possible listing of THDC, NEEPCO and Hindustan Urvarak?
No, there are no definitive plans at this point of time. As a group, we keep exploring all these avenues as a part of our financial strategies and unlocking value. This is one of the options that is available. But as this is a joint venture, this THDC comes under a joint venture with the UP government. These are matters which has to be dealt at the fairly senior policy level. So once we have a clear mandate on this, we'll share with you.
How do you think about capacity addition in FY27 and FY28 given the current pipeline? Can you break that capacity addition between standalone, subs and JV for the conventional and for the green?
As far as FY27 is concerned, on a totality basis, we are planning around 9,557 MW of capacity. Thermal would constitute 1,070 MW, hydro will be 250 MW, and renewable total would be 8,237 MW. Of this 176 MW coming from renewables would be on a standalone basis and 9,381 MW would be coming from the JVs and the subsidiaries. The year next, FY28, the total plant capacity addition is 10,039 MW, comprising of thermal 1,460 MW, hydro total will be 444 MW and renewable total will be 8,135 MW. For FY29, we are planning 11,478 MW total capacity. 8,408 MW would be renewable. We don't expect any hydro addition during that year. Thermal total will be 3,070 MW.
What is the status of the nuclear power projects? And where is Mahi Banswara right now? Do you expect the tender of the equipment and work to start in this fiscal?
Mahi Banswara, capacity is a 4 unit of 700 MW, total of 2.8 GW. For 2,770 MW of capacity consent has come from the customers from Rajasthan, Gujarat, Chhattisgarh, Andhra Pradesh. The excavation package for this project has already been awarded for Unit 1 and 2 on 13th of September 2025. Excavation consent by Atomic Energy Regulatory Board, AERB, has been received on 18th of March '26. The first pour of concrete is anticipated by August 2027. And first unit synchronization we are planning in November 2032. The design consultancy also has been awarded on 23rd of December 2025. And equity infusion of INR800 crores to ASHVINI has been done by JV partners in January '26. Nuclear Island's Mega EPC, NIT is expected by 15th of June '26. It will be followed by TG Island EPC, NIT by 30th of March 2027.
On NGEL, what was the curtailment for NGEL in terms of units and value for FY26 and Q4 FY26?
NGEL experienced a curtailment of 314 MUs during the year. This is besides the TRAS loss, which we can say is 135 MUs. These are the 2 things which are due to the grid situation. As far as the TRAS is concerned, we are compensated for that. But as regards the grid curtailment where we are experiencing because of the temporary GNA, it would have an impact close to INR90 crores.
We have initially said that 5, 8 and 8 GW for '26, '27, '28 on the NGEL installed capacity addition. So there has been a shortfall in FY27. For '28, '29, for the 8, 8 GW, have we secured the transmission?
First thing is it was not FY27, it was FY26 that we were planning around 5 GW, and some of the units spilled over to the next year. But as far as the current year is concerned, the 8 GW, we continue to hold to that. Right now, we are planning an average of 8 GW per annum. We would be exploring various other opportunities to top it up, including inorganic acquisitions. So our idea would be to steeply increase it so that we fulfil our target of 60 GW much ahead of what we are planning by 2032.
How much of the transmission network we have secured for FY27 and FY28?
As far as FY27 is concerned, we have the firm connectivity of 57% and T-GNA of 38%. As far as FY28 is concerned, whatever CODs are expected in FY28, we have a projected firm connectivity of 88% and 3% would be coming from the T-GNA, remaining 9% is something which we are yet to tie-up. FY29, 84% we have firm connection and remaining 16%, we'll have to work on the connectivity.
For NTPC thermal fleet, are there coal units which are having to face the challenge of hitting technical minimum of 55% PLF during daytime when solar availability peaks? How is NTPC managing this risk?
There has been a very favorable pronouncement wherein we have been assured a technical minimum of 55%. If it goes down, we are not obligated to then keep the unit live and we'll be compensated further for our availability under fixed charges. We have also kind of advocated and got a dispensation of co-locating batteries in some of these thermal power plants, whereby the backdown power can be utilised during the daytime and discharged during the evening peak for peak load management. 5 GWh of battery work has already started, and CERC has given its tariff framework for this. This would be essentially in a cost-plus framework where we are assured of our return on equity as well as our fixed charges.
Is the technical minimum support approved by the regulator already?
As far as technical minimum of 55% is concerned, this is already the rule. If I have declared a certain capacity higher than the technical minimum or let us say 85% or 100% and the scheduling comes below 55% for some reason, I'm not obliged to run this plant, I can take a reserve shutdown.
On pump storage projects. What is the total anticipated capex for pipeline projects in pump storage and what is likely to get incurred in the next 5 years?
Broadly, NTPC is working on 4,800 MW of PSPs. This is primarily to be executed through JV and subsidiary. THDC and NEEPCO, which are the hydro subsidiaries, they are working on 13,210 MW. So that puts the NTPC Group broad plan at 18,010 MW. Now out of the above, COD has been declared in the FY26 itself for 750 MW, that is the THDC Tehri PSP. And COD declaration of 250 MW has been done in the current financial year, FY27 first quarter. So 1 GW is already done. Another 3 GW to 5 GW, you can expect to be commercialized by 2032 to '33.
NGEL pipeline reduced from 32 GW to 30 GW. Why is this reduction and which projects have been removed?
Apoorva, we have adjusted or actualized our total pipeline plus contracted awarded capacity that we had. We had earlier shown 32 GW up to Q3 of last year. However, now we are seeing in which of the JVs or the subsidiaries the progress is being made and normalize the numbers, so that is why the numbers have come down from 32 GW to 30 GW. However, there are many other MoUs or activities where we are working upon, and we are expecting to increase the pipeline in the coming days.
Thermal backing down — while we appreciate the fact that company is entitled to a 55% technical minimum, but can you share with us if there is any incremental costs being incurred for backing down to 55% in terms of higher O&M or lower heat rate?
One is the floor percentage that it need not go below 55%, and Mr. Ravindra also explained to you about the SCUC support that is available. Within this range of 100% to 55%, we are compensated for various parameters, degradation in the parameters in terms of heat rate, auxiliary consumption. This has been kind of taken up with the regulator, and we have got very favourable dispensation over the last 2 years. Right now, we have been adequately compensated for this.
For FY27 and '28, what sort of capex guidance have we for NGEL at consolidated NGEL?
We have a broad capex for the group of INR 6,22,000 crores till the financial '32 and we have allocated roughly half of that, around INR3 lakh crores for renewable energy, which should broadly be done by NGEL. For NGEL, for current year it would be capex of INR 35,800 crores. Next year, it would be INR46,000 crores and the year next, it would be INR48,000 crores. So we'd be implementing a debt equity of 80-20.
PPA tie-up for capacities planned for commissioning — what percentage do we have for '27 and '28?
Over the next 3 years, broadly for an average 72% to 75% capacities, PPA already in place. For FY27, it is 79%. FY 28 CODs of 8,069 MW we are already covered with 71% PPA. And the year next around 8,400 MW, it is 66%.
Do we have any plans of doing battery storage in existing renewable projects, co-location of battery storage?
Yes, we are embarked on battery storage as far as renewable is concerned. Besides, of course, the co-located battery for thermal, which I was mentioning 5 GWh, we are currently working on 1,320 MW of batteries on the renewable side. On the standalone project of battery, it is 320 MW, which is under execution. And co-located with solar projects, it will be 1,000 MW, which is under tendering right now. There are around 4 GW more, which is under planning stage right now, which would be at Khavda, it would be Bikaner, Fatehgarh, Sitapur and one which is Chhattisgarh. So, all this put together would be close to 4 GW.
On Rajasthan 1.5-GW solar project — what's the update?
We have already moved ahead quite a bit on the 1.5-GW project. We have the land in possession. We have also entered into the tie-up for the implementation support agreement and other things. We are currently working out the commercial offtake arrangements with Rajasthan. And all the tendering activities, everything has been completed. Once we reach at the commercial settlement of agreements on the offtake front, we will immediately move ahead with that project.
Out of 8-GW capacity which we are planning to add in FY27 and FY28 in NGEL, how much of that will come through JVs?
In FY27, out of the 8 GW around 1.9 GW would come through JVs, primarily through Ayana and a part of that would come through a JV with IOCL that is INGEL. And in FY 28, out of the 8 GW around 624 MW would come through the JV route.
What was the reasons for other expenses to significantly increase on a Y-o-Y and Q-o-Q basis (NTPC consolidated)?
If you see the other expense, it has gone up from INR5,806 crores to INR6,972 crores, this is on a stand-alone basis, which is 20% above. Now if you see, there is an exchange rate variation of INR784 crores. But however, what happens in the cost-plus framework, we are entitled to the corresponding compensation for the ERV. So that corresponding regulatory income of INR 780 crores is available on the sales side. And we have also provided for some INR 478 crores provisioning, INR193 crores pertains to EESL and INR149 crores NBPPL and INR100 crores for Garhi Dam. So these are some onetime provisions which we have made.
How do we reconcile the capacity addition growth with respect to the revenue growth? Capacity addition has been happening, but in revenue terms, it has been flat or very low single digit.
The effect is because of some composite factors. Capacity addition happens where your MW increases. However, on the thermal side, the plant load factor compared to the past has been low because of the lower demand during the daytime, during the solar hours because of the RE injection. Now because of that, although I am compensated for the fixed charges because of the lower generation, my sales is also down to that extent and to the extent, my fuel cost also goes down, while my bottom line is protected. When the demand is low, the offtake is low. If the uptake is low, to that extent, I have to back down my generation. Because of the backing down of generation, I don't fire that much fuel. So, my cost also goes down, my revenue also goes down because of the lower offtake. Whereas my margins are protected because once my plants are available, the fixed charges has to be given to me, which improves the element of return on equity.