ACME Solar Holdings Limited ($ACMESOLAR)

Ladies and gentlemen, good day, and welcome to the ACME Solar Holdings Limited Q4 and FY '26 Earnings Conference Call. [Operator Instructions] I now hand the conference over to Mr. Nikunj Seth from MUFG. Thank you, and over to you, Nikunj.

Thank you, Nirav. Good morning, everyone. Welcome to Q4 and FY '26 Earnings Conference Call of ACME Solar Holdings Limited. From the management we have with us Mr. Manoj Kumar Upadhyay, Chairman and Managing Director; Mr. Nikhil Dhingra, CEO; Mr. Arun Chopra, CFO; and Mr. Ankit Sharma, Head of Corporate Finance. Now I would like to hand over the call to the management for their opening remarks. Thank you, and over to you, sir.

Thank you, Nikunj. Good morning, everyone. Thank you all for joining us today. I'm Nikhil Dhingra, CEO of the company. I would like to begin by expressing my sincere gratitude to Rajat Kumar Singh for his valuable contributions to the company during his tenure as the CFO. He has decided to pursue career opportunities outside of ACME. I wish him all the best in his future endeavors. Arun Chopra has now been appointed as the company's CFO. And I would like to invite him to take over and walk us through the highlights of Q4 and FY '26 for us. Arun?

Thanks, Nikhil. It's my pleasure to share the highlights of our Q4 and FY '26 performance. I would like to start with sector highlights. India has observed its all-time highest peak electricity demand of 256 gigawatt on 25th April '26. This milestone surpasses the previous all-time high of 250 gigawatt recorded on 30th May '24 and exceeds the peak of 245 gigawatt observed on 9th January '26. The rise in demand is in line with the progression of summer conditions across the country with electricity consumption witnessing a significant growth of 8.9% during the month of April '26. India continues to maintain strong momentum in capacity additions with approximately 55 gigawatt of RE added in financial year '26, taking cumulative renewable energy capacity to 283 gigawatts. Total power generation during FY '26 reached 1,845 billion units with share of nonfossil fuels in total generation reaching 29%, roughly 538.97 billion units. In a significant milestone, India achieved 50% of its cumulative electric power installed capacity from nonfossil fuel sources in June '25, 5 years ahead of the 2030 target set under its nationality determined contribution to the Paris Agreement. In terms of the regulatory updates, SECI has been notified as single REIA by MNRE, which is expected to drive a more streamlined, focused and structured bidding framework going forward. In terms of BESS installation, the sector has witnessed strong regulatory tailwinds. MNRE has clarified that BESS charged from conventional power under FDRE bids can sell power in merchant mode without buyer NOC till the time corresponding RE is not commissioned, speeding up BESS deployment. Also, CTU has started processing BESS connectivity requests under RoFR, speeding up commissioning with 36 months of grid charging allowed from the GNA effective date. CERC has issued a draft suo moto order to extend SCOD time lines under the connectivity and GNA regulations by up to 1 year with compensation, giving regulatory certainty to delayed projects nearing connectivity deadlines. Thus, transmission delay in brownfield projects provides an opportunity to utilize BESS merchant operations. Now coming to our company's performance. In line with our continued focus on early BESS deployment, we successfully commissioned approximately 2.3 gigawatt BESS capacity to date. These BESS capacities are running on merchant and short-term contracts, capturing the tariff arbitrage between sale and purchase of power during peak and nonpeak hours respectively. As of date, it is delivering net realization value of approximately INR 2.2 crores per day. Also from an operational standpoint, the BESS is currently delivering a round trip efficiency of approximately 80% to 90%, in line or maybe better than our expectations. In addition to BESS, our operational generation contracted capacity now stands at 2,990 megawatt. With respect to our under construction capacity on order book front, we won 301 megawatt peak power FDRE projects with SECI during the quarter, expanding our under construction portfolio to 5.1 gigawatts and total portfolio to 8,071 megawatts, which will also require installation of around 17 gigawatt hour BESS. Out of the total under construction capacity, the PPA signed capacity stands at 3,280 megawatts. In terms of capital deployment, we have committed total CapEx of INR 12,475 crores, which includes CapEx incurred of INR 6,445 crores during the year and purchase orders aggregating to INR 6,030 crores. Continuing to our financial performance. Our total revenue for the quarter stands at INR 705 crores and INR 2,507 crores of FY '26. 31% and 59% increase year-on-year respectively, driven by capacity addition and higher CUS. Total revenue for the quarter includes other income of INR 157 crores. This primarily comprises recurring interest income from cash generated from power sales at SPV until it is upstream to ASHL. It also includes recurring interest from DSRA balances maintained in line with debt covenants. Since the DSRA is largely funded from debt proceeds, the corresponding finance cost is accounted for accordingly in the finance cost. EBITDA margin of over 90%, both for the quarter and full year on account of favorable operating leverage and optimized operational efficiency. PAT stood at INR 138 crores for the quarter and INR 498 crores for the year with a margin of 19.6% and 19.9%, respectively. Now at last coming to operational metrics for the quarter. We generated 1,720 million units in Q4, up 13%, and 6,464 million units in FY '26, up 61% year-on-year. Our CUS stood at 26.9% in Q4. Further, our grid availability and plant availability stand at over 99% for the year. Coming to our debt optimization efforts. During the year, we secured financing of around INR 15,000 crores for various under construction projects and refinanced debt amounting to INR 3,300 crores for various operational projects, resulting in reduction of rate of interest of the refinance projects by approximately 150 basis points. Also, the weighted average cost of debt for the operational projects stands at 8.4% per annum. As of date, 2.2 gigawatt of operational projects have an assigned credit rating of A- stable. Going forward, our key focus remains on timely execution alongside healthy order book additions with the following priorities. We will continue to focus on advancing commissioning and operation of large-scale BESS capacity, which will utilize transmission infra of existing operational projects and will run on merchant on short-term basis. Upcoming future operational capacity is expected to have an operating battery portfolio of around 10 gigawatt hour, along with 1.5 gigawatts of contracted generation capacity, subject to timely availability of transmission connectivity and other external factors. In terms of order book additions, while we remain focused on long-term 25-year contracts, we also intend to actively participate in short- and medium-term BESS opportunities to capitalize on evolving market demand and merchant market dynamics. With that, I now open the floor for questions. Our team would be happy to take them. Thank you.

[Operator Instructions] The first question comes from the line of Puneet from HSBC.

Congratulations on good performance. My first question is on your battery side. Can you talk about how much of the battery cost you capitalized in the previous year? And how much have you spent so far in the 2.3 gigawatt that is now fully commissioned?

Puneet, thanks for the query. So in terms of last quarter, this quarter we have done approximately around INR 1,200 crores of CapEx on the battery. I think for this quarter, it is still going on. So we will update you once this quarter finishes. But in the last quarter, we did around -- basically last quarter was around INR 1,000 crores to INR 1,200 crores.

And how much was commissioned till last quarter? Yes, just in capacity terms as well?

1.3.

1.3. Okay. Second is, if you can also give a sense of what is the run rate EBITDA you are making out of your existing capacity with and without BESS so far?

So, 87% is our EBITDA for this year, right? It is in the range of 88%, 89%. I think...

90%.

91%. 90%, 90%.

No, I meant run rate EBITDA in rupees, crore from the 2,990 capacity.

Please look at FY '26, so majorly, whatever this 3 gigawatt is operational so that was primarily running in '26. So give or take for the last full year, our EBITDA, including other income has been around INR 2,200-odd crore. This primarily includes revenue from sale of power only from the PPA projects. However, given that the batteries came in various phases in the last quarter, especially in March. So probably the run rate EBITDA you will realize in this quarter itself. But having said that, like I mentioned, 2.3 gigawatt hour is currently operational. And of course, it is running on a merchant basis. And as Arun highlighted earlier, so it is delivering, give or take, average net realization of INR 2.2 crore per day, which is effectively more than INR 60 crores per month, this capacity which is running.

And last quarter there was almost nothing from the battery. This quarter, we have -- in March quarter, there's almost a negligible amount from battery because it just was getting started. It was not even started at various places.

Yes.

So INR 2.2 crore per day on a 2,300 megawatt hour battery, right?

Yes, yes, yes.

Yes.

And lastly, if you can also talk about how have your new solar plants been operating in terms of PLF. So what was commissioned in FY '25, what sort of PLF did they end up generating for '26?

So our Sikar plant basically got commissioned in this year, right? And it is doing close to around 29% to 30% year -- for the overall year.

So majority of the projects, Puneet, are in Rajasthan. And roughly the capacity is roughly 2,200 megawatts. So for the last quarter, I think the, see PLF has been around 28% plus for these plants.

On a full year basis, 29% to 30% is what you said?

And overall -- sorry?

For full year basis, you said 29% to 30% from the new plants? It is a blended number, sort of.

Yes. For the new plants. Yes, yes, yes, for the new plant it is because we have a higher DC installed there. So it has a higher CUF, yes.

For the full year, it's been close to 26% for the entire portfolio.

He is asking about Rajasthan. New plant.

Got it. And lastly, there was this SECI ISTS hybrid tranche scheme, which got a regulatory approval for 3.25. And now it says that there is a battery inclusion. Can you talk about how has the economics changed there?

You're talking about the -- the PPA is not yet signed, right?

The Sikar one. Yes. But it got approved, right? I mean, that has 2.25...

Yes, yes, yes, it got approved, right. So basically, it is -- what happens is most of the states want battery installation along with the project. So it basically keeps the return in high teens only. So it does not impact really the returns from this thing. But of course, we need to satisfy the customer requirement in terms of the power mix they want because everybody needs peak power now. So that is where we need to offer that 1 hour of battery, yes.

Next question is from the line of Karthik Sharma from Anand Rathi.

Congrats on great set of numbers. Just continuing from the previous participant, given the rising concentration of projects in Rajasthan and ongoing transmission and grid constraints in the state, is there any curtailment impact that we've had? And if yes, could you quantify in like what happened in Q4 or the full year in EBITDA loss? And how are you thinking about future project allocations like Gujarat or Maharashtra, if there is any?

Right, right, right. That's a very relevant point. The key thing is in terms of the curtailment, which -- where are you connected in terms of the transmission system. So we have, you can say, around 2 projects only out of our whole portfolio which are in Rajasthan connected to the state grid. Rest of our portfolio, by and large, is on the central grid where you are compensated for the curtailment through the regulatory mechanism. So in the whole year, we were of course -- and in curtailment also there are 2 kind of curtailments where you don't get a long-term open access, like which happened with our Sikar plant before the full commissioning because the long-term open access was not active. So that is like a pre-COD or a pre-DNA kind of a curtailment, which is not usually grid-related curtailment. That is where the infrastructure is not yet ready, but you are ready with the plant. So I would not call that a curtailment. But adjusted for that, for the whole year, we have only INR 5 crores to INR 6 crores of impact on the curtailment, which is the real curtailment. And of course, on STU, it was only INR 3 crores in Rajasthan for the whole year, state connected projects. And the INR 2 crores, INR 3 crores was on the account of maintenance done by the grid operator on account of the -- on account of, you can say, the O&M which they do for that. So that was the impact on curtailment on our project during the year.

Understood, sir. And the future project allocation, if you could give any?

So all of our projects are in the CTU. So we have consciously built a portfolio with, you can say, all the central counterparties on CTU. So we don't have -- and also, that is another reason we have not gone aggressive on the C&I because they are all state projects we have to do if you want to serve the actual consumer. So in terms of the -- all our CTU connected projects with CTU connected substations, where you are regulatory protected from the customer payments are there irrespective of, you can say, the grid curtailment. So they are all on the -- you can say, various substations in Rajasthan, Gujarat, Madhya Pradesh, Andhra Pradesh, Karnataka. So once the long-term open access is granted, then you are protected from curtailment on a CTU connected substation.

Understood, sir. So just continuing on that, can I ask my second question?

No, just a minute, I would like to clarify.

Yes, yes, sir.

My name is Manoj. Most of the CTU connected projects, we are installing the battery. So in fact, such curtailment sometimes provides you opportunity to sell the power in the peak or in the evening. So all our CTU connected plants, that's what we are focusing. All our CTU connected plant will have a battery available. So whenever that curtailment will happen, we will charge the battery, and we will use that power, right? While we will get compensated for the curtailment, but we will use the free power also to charge the battery.

And as the battery installation happens. Just on that, just to finish that point, as the battery installation happens, the curtailment issue will be further reduced because as more and more battery gets installed in Rajasthan. And it is by and large, happening in Rajasthan because they have the largest operational solar. So you will see that the transmission system improves a lot with the battery installation.

Understood. Understood, sir. So we highlighted that there was a sharp improvement in receivables and the DSO has come down to 14 days, which was at one point in time 180 days. So despite the significant scale up, could you help us understand whether this is largely driven by like onetime collections? Or is this like a structural shift that you are seeing in the portfolio mix when you say that it's going to be more central offtakers and how sustainable this working capital profile is going forward?

So see, our portfolio as it gets more operational, it is shifting towards 100% central. All of our under construction projects are 100% central, where they take a cash discount. So it essentially -- and they pay in 10 days. Basically, in 30 days, if you pay, you get a cash discount. So that is where they take a cash discount. So that is why we are getting a 15 days kind of a receivable cycle today. So which is more or less not because of one-off, it is the norm. Yes. So Ankit, do you want to add?

Yes, earlier, I think the higher receivable days you are talking about, so that pertains to very -- you can say FY '23 and before that. And I think at that point of time, like Nikhil mentioned the contribution of central [indiscernible] was less. And there are, of course, some payment issues, especially from a couple of DISCOMs as well, especially Telangana and Andhra. Even that payment has normalized now, right, even from the...

See, is that the effect that we've seen in the trade receivables, which have gone down 13% year-on-year?

Yes. Actually, you know that there was a regulatory reform, which was government has implemented called LPS, right? Under that LPS late payment surcharge scheme, 2, 3 states which were delayed actually because of the various regulatory issues, there were some court cases in Andhra Pradesh. All those dues are now settled and they are paying on time because this LPS scheme is very strict. They don't pay on time, you inform to the [ PATI ] portal and they will get disconnected from the power. So this discipline is helping, especially for the state project. But mostly now we -- what has happened, our projects are central projects. So central projects, technically, they are paid in just 6, 7 days because they want to take a cash discount.

Next question is from the line of Aniket Mittal from SBI Mutual Fund.

First question was just on the cash flow. So when I look at the cash flow statement, there seems a very large increase in the noncurrent assets and some other balance sheet items, which is impacting the cash flow from operations. Just wanted to understand that.

Aniket, could you point out which are the -- which number you're referring to and what is the number?

So if I look at the noncurrent assets in the balance sheet, so looking at the cash flow statement, cash flows from operations have come in lower on a Y-o-Y basis, partly I think because the base for last year was higher. But when I look at the balance sheet, there's been a sharp jump in the other noncurrent assets and also on the other financial noncurrent assets. So just trying to understand what is the...

So it is mainly because of the CapEx buying which is happening. So it mainly include the [indiscernible].

Okay. And what is the capital advances number there?

Capital advances, just a minute. Roughly INR 323 crores.

INR 323 crores. And this is pertaining to what, like?

So this advances basically given to -- for the procurement of material, which has been given to various and the material will come in over a period of time. So these advances have been given to them, maybe a partial advance, let's say, 10%, 20% advance.

Let's say, battery contracts, we have typically 10% advance upfront where we get a bank guarantee against it. Similarly, the turbines also we give 20% advance. So these are capital advances you need to give to supplier where they give you a BG against that.

Okay. So this largely because of battery and probably some wind.

Yes, yes, yes. On services and domestic procurement, typically, we don't give any advance. But from an international procurement perspective and large equipment, we have to because it helps you to bind the supplier also in terms of the contract honoring and also giving him advance to purchase raw material because if you don't pay advance, he will not have money to purchase the raw material.

Okay. And when I look at the PLF number on a Y-o-Y basis, I see a 1% decline. What's the reason for that for this quarter?

For this quarter, Anikit, could be a function of, of course, the lower addition or and curtailment. These 2 could be the only 2 factors which would have impacted. On a Y-o-Y basis, of course, the larger capacity, it is a larger capacity. So of course, the denominator is higher. But these are the 2 only factors because it is determined by seasonality as well. So these are the factors in terms of -- we can give you a site-by-site, I think, analysis. But broadly, it is because of these factors.

Okay. In the presentation within the under construction portfolio, I also see a merchant BESS of 654 megawatt hour. Are we putting some purely on a merchant basis? What does this pertain?

Actually, it is merchant as of now. It is slated to go to a PPA, which we are supposed to sign very shortly. Most likely -- because it is pure battery, which is taking power from the grid and giving to the grid, it can fit it in any of these peak power projects PPA we have, which we have not yet signed with a tariff of either 6.28 or similar, and there are a lot of bids coming in where we can deploy this best. It gives us some flexibility, and we also wanted to get it financed on a merchant basis because it gives us some flexibility in terms of getting ready for early installation because it does not tie you to a specific PPA. So in terms of the financing and in terms of the early commissioning, we have installed it like this. But of course, it will go to a PPA.

Okay. And for FY '27, how are we placed in terms of the commissioning of the SGB and FDRE project and the NTPC hybrid project?

Right. So there are -- on the whole commissioning during the year, I would like to explain. There is a Neemuch substation, which will be the first commissioning from our side because that's the substation which is more or less ready, and it is -- will be charged in June because you know the commissionings are determined by, the FDRE commissioning, since you are asking, they are determined by the solar connectivity being ready. So that's where the -- that is on the -- that will commission our 2 plants. One is the NHPC and another is the Tata. So that is the first commissioning from our side on the FDRE. Then, of course, there's a substation at Fatehgarh, which will have the SJVN whole 570. That has a short-term open access available right now. The long-term open access as per CTU is in March '27. So the full FDRE for SJVN, but will be ready by FY '27 end. So that's the FDRE. And the NTPC, we are ready with the solar. But of course, there is a long-term open access there also which is slated to be commissioned by December '26. And our Pachora wind component is also ready, but that is also slated for, you can say, a couple of quarters later. So by March '27, all this will be commissioned. In terms of the other commissionings, we are targeting, there is Pavagada, Anantapur, which are also going to come up during this year as per the CTU time line. What we are trying to do is commission the batteries at our operational substations in Fatehgarh-1, which we have 1,000 megawatt. Then Fatehgarh-2, which is again -- the Fatehgarh-1, sorry, is 200 megawatt. Fatehgarh-2 is 1,000 megawatt where we have an STOA. In STOA, you can transmit all the battery. And then we have Bikaner 3, again, where bay is ready, so you can transmit the battery power. And of course, so these, you can say around aggregating to around 2,500 megawatts of ready connectivity for selling battery power during night is what is ready with us from where we are trying to transmit 10 gigawatt hour of battery during the next of the calendar year. So in terms of commissioning, so the battery commissionings are going to happen early because we have ordered a battery, the battery is arriving every month. And also in parallel, as and when the CTU substations are getting charged, we will commission the solar also. In terms of preparedness, the transmission line, the balance of system, the equipment delivery, they're all on track. And we are trying to co-terminus with the CTU time lines of these substations. And we want to also want to prepone our revenue from the battery sales because from the power sales through nighttime power, which is now allowed as per the PPA construct and as per the clarification given by MNRE. So we will see a good jump on the revenue side because of the nighttime installations, which will more than compensate for, you can say, the CTU time lines getting shifted from one quarter to another. So that is the reason we have preponed the battery installation, and we are commissioning it at the operational substations and not in the greenfield substations. That is the key thing. And we have 2,500 megawatts of ready substations and connectivity, which are going to go live in the near future.

Understood. What would be the battery total installed base, let's say, 6 months down the line and 1 year down the line?

So 10 gigawatt hour is our total target. And of course, it is completely dependent on a number of factors in terms of the supply of material, in terms of the connectivity. But as far as connectivity is concerned, we can do this 10 gigawatt hour because we do have the connectivity. We do have the financing available. We do have the supply tie available. But of course, in terms of the various factors which are interplay in terms of the supply of material, in terms of, you can say, geopolitical factors, those are the only uncertainties. But as far as the CTU linked is concerned and as far as the other dependencies go, it has much less external dependencies than you can say, a CTU-connected solar plant.

Next question is from the line of from Ishan from Antique Stock Broking.

CERC has recently proposed a new mechanism for LOA-based connectivity. So wherein the capacities have been delayed for 1 year, there is a surrendering exit option for those connectivity. So I just wanted to know how much of that much connectivity inventory falls under this? And what is your strategy to convert it?

Right, right, right. No, that's a very welcome move from CERC, which CERC has done. It's a discussion paper right now, and they will formalize it after getting comments from all. So that's a good move. In terms of how it will work is if you are not able to sign PPAs for a certain amount of LOA and you have been -- and the Renewable Energy Implementation Agency really clarifies that these PPAs cannot be signed, then of course that developer is free to develop it in a merchant basis or free to use it in another LOA. As far as we are concerned, we have around 6.2 gigawatts of signed PPA, which we are constructing. And so -- which is a very sort of -- so our LOAs are more or less converted into PPA.

3.2.

Yes. In terms of the construction 3, if you remove the 3 operational for us, we have 3.2 gigawatt of LOA, which have converted into PPA which we are constructing. There is 1.8 gigawatts of PPAs we have won recently, and there are some which are older, you can say around 850 megawatts of older PPAs which are in various stages of discussions. But we are not anywhere near to that time line where we -- the REIA will say that, right, PPA will not be signed because they are trying their best and all the agencies are trying their best to get it signed. There are various discussions at various forums to get it signed. But just in case if this happens, these will be for us, our strategy will be to use them for future bids and -- or to use them for, you can say, for battery connected projects in future. So we will use this connectivity in any case because we have a good pipeline of PPAs where there is a lot of bids which are coming which are now backed by a solid demand from states like thermal mimic, which is coming, which will require a large amount of CapEx and large amount of solar and battery. And there are a lot of other bids which are coming which we will use the connectivity for. So we will keep the connectivity with us. And we don't foresee that our LOAs will, we will have to surrender. But just in case it happens, we will have a backup plan ready by then.

Got it. That's very clear. Just a follow-up on that on the industry level only, we have seen like around 3-plus gigawatt of PPA conversion from LOA capacity. And overall of the industry there was a huge buildup of LOA capacity. So how, do you see like DISCOM -- what types of capacity are the DISCOM preferring to convert from LOA to PPA? And also, what is your overall view in the RE tendering momentum in FY '27, given the peak demand is growing strong?

Right. So the good thing is because of the huge amount of bids, which they did, of course, more than the demand, most of the developers have a sizable PPAs to execute. And that is giving everybody a sizable, you can say, CapEx opportunity or a revenue opportunity. And of course, there are a lot of unsigned PPAs. So in terms of the PPAs getting signed and demand coming up, there is a demand for peak power, so -- which does not have a battery is hard sell as far as the states are concerned. So everybody needs some amount of peak power at least, if not 4 hours, at least 1 hour, 2 hour. So something which -- and if not -- so plain solar is the hardest to sell, right? But some states have a typical demand for solar because they are putting up their PSP or they are putting up their -- their thermal is a bit, some distance away. So very few states have a plain solar demand. So in terms of the pecking order, you can say peak power selling fastest. The partial peak power is second, second fastest. And then the wind is selling well, but wind opportunities are very less and people are doing less wind, and the solar is selling the slowest. In terms of the bids for this year, we see that the bids will be lesser than last year, but the PPA should be faster again because they are not doing bids until the previous ones get at least allocated or signed in some way. So that is -- and the REIA is one. So focus will come in terms of -- there is only SECI, which will now be aggregating demand. So they'll have some sort of, you can say, aggregation power, which being a sole entity gives them in terms of the -- with the states. So they are aggregating demand for, let's say, a thermal kind of tender or peak power tender or a CfD tender, which is -- which will find takers because that is purely basis demand. They are doing wind tender, they are doing PSP tender. There are at least 5 gigawatts of tender currently open with SECI, which has -- which is 2 gigawatts of wind, around some 1 gigawatt of PSP, then there is this thermal mimic, there is CfD. So you will see bids of a level of 15 to 20 gigawatts. Of course, this can change depending on the shortage this year. So the states can change their behavior. And not all states can afford to do state-level bids because there is little renewable in some states. So they'll continue to buy from SECI because of the competitive rates, which these go. And also, there are some states which will do on their own where also they'll be successful like Southern states or Maharashtra or you can see Gujarat. So there also you will see some growth and bids coming up. Like UP recently called for a bid wherein they called for a peak power in their own -- where you could charge from anywhere in the country, but the battery installed in their place. So those kind of bids you will see. So a lot of peak power. Peak power is something which everybody wants. So bids focused around that will be successful.

I would like to add that although the bids will be won with capacity in next year this year, adding state and [indiscernible] will be 20 to 30 gigawatt. But the overall solar or overall the CapEx requirement will be higher than the last year because what is going to happen in the plain vanilla solar will be INR 3 crores, INR 4 crores, INR 4 crore per megawatt. But the current bid, which is happening, for example, mimicking the thermal power or mimicking that long duration storage, solar storage, they will be -- actually they will carry a very large solar behind the battery. So technically, maybe 25 to 30 gigawatt will technically mean solar of 40, 50 gigawatt. So overall, if you see that the name of the -- actually configuration of the procurement will change, but deployment of solar will remain 40 to 50 gigawatt.

Just to add, even if you look at the CERC connectivity rules, when they have asked to put batteries, they have made it mandatory to put solar in the 3 years once you take a connectivity. So the solar is mandatory to be installed if you are taking connectivity under certain guidelines like 5.2 regulation. So they also want their connectivity to be appropriately utilized. So you will see battery-linked solar installations coming up very fast and pure battery installations will be very less.

Yes. Sure, sure. Just one last question on the standalone battery. Just want to know what is our IRR -- expected IRR from that 550-megawatt project? And what is the end of the life value for the BESS in that part project?

So the 550-megawatt hour project is currently -- basically the tariff is adopted with the caveat, so it is not yet started. But in terms of the IRR for that project, you were asking? IRR is in, again, in terms of mid- to high teens for that project because there is not much transmission infrastructure to be put. It's a 33 kv level installation. But the zero date for that project has not started for us. So we have not really finalized the CapEx because the state regulator has really asked that on the trading margin of NHPC, because in this case it's a pure leasing and they are getting a VGF. So it is in terms of the -- whether they should get a 0.5% margin or INR 0.7 margin. So that is being debated. So zero date has not yet started for us. We'll be able to update you once the zero date has started. But broadly, we are telling you the bid return when we bid it. And also in terms of the end-of-life assumptions, these batteries are basically slated to run for 8,000 to 10,000 cycles, right? So in terms of -- I think that depends on the PPA, it's a single cycle or a double cycle. I think it's a -- single cycle or double cycle. It depends on...

It's a very small project in the overall portfolio because this is 550-megawatt hour. But correspondingly, for other projects that we have, which are 5 gigawatt under construction, that will require installation of around 17 gigawatt hour battery. So it's more just like the small project that you're talking about. It's more like a leasing model wherein you are not putting any generation storage, you're just storing the power, which you are getting from the DISCOM and then you are just discharging the batteries. So those are the bids we have -- it's 1 bid out of the overall portfolio of 8 gigawatt hour. So we are not focusing at all on those bids. And so -- and like Ankit mentioned, the batteries which are part of the overall solar, wind and FDRE mix, the peak power mix, those will be, you can say, 99% of the CapEx. This is less than 1% of the CapEx.

Next question is from the line of Dhruv Muchhal from HDFC.

Sir, if I look at your gross block increase for the year, it's about INR 3,400 crores Y-o-Y approximately what you reported. And your run rate EBITDA would have increased by about, I think, INR 300-odd crores Y-o-Y. So it was INR 1,700 crores last year, it's about INR 2,000 crores this year. So the gross block to EBITDA run rate is about 11x, which is very worse off versus what you typically do. I'm just trying to understand what am I missing here?

So gross block has increased by around INR 3,000-odd crores, right, in terms of capitalization. right? So in terms of the -- what you are seeing -- not seeing is the -- you can say the wind, wind has not really started performing, first of all, because wind has got installed in the --

In phases.

In phases. And it is...

But that's included in your run rate EBITDA of INR 2,000-odd crores, right?

No, no. See, the run rate EBITDA is basically in terms of the last month, it basically got commissioned at the fag end of the -- I think it got commissioned at the fag end of the year. And so run rate EBITDA is -- what you're talking about is the reported EBITDA or the run rate EBITDA?

Run rate EBITDA. So in Q3, you reported run rate EBITDA of about INR 2,100 crores. I think largely all your projects were commissioned by then, including the wind, probably small portion was remaining. So is it probably the gross block number includes the battery, which was commissioned by the end of the year for which the run rate EBITDA is not part of it?

It definitely includes the -- we can give you the commissioned projects for the full -- basically, the run rate EBITDA is for the 12 months number. We have -- I think we don't have that number in this year because these -- the whole gross block will not be operating for the 12 months.

So out of this INR 3,460 crores, roughly INR 1,000 crores to INR 1,100 crores is related to battery, which...

I think that explains that, yes, yes. Yes, so that explains it very well. So INR 1,000 crores, if I remove INR 1,000 crores gross block has increased by about INR 2,300 crores and that explains it.

Yes.

Got it, sir. Perfect. Sir, the second question is on the MNRE clarification that you highlighted. Now does it mean that for an FDRE project, if you're commissioning a battery early, the charging of the battery can happen through a conventional power, which is now allowed. Is that the approval which we have got or the regulation which has changed?

Yes. It is allowed to be sold in the merchant. Basically, it is allowed to be sold outside of the -- because since it's a nonrenewable power, you can sell it outside the -- not to your offtaker to anybody you want. Till the time you have not installed renewable behind the battery it is not a renewable power. So it is -- that is the clarification they have explained, which was already part of the PPA, but they have clarified it.

So for example if you put an FDRE project -- yeah.

-- no, no, just I would like to add it here that even if you have installed the solar panel, if you are not connected with the battery, for example, if you FDRE -- if your LTA is not right now operational, most of our projects are actually connected with the brownfield of power grid service station. That means we can energize our transmission line, we can energize the project well before our connectivity time line or our PPA time line. What we are doing is actually we are installing the solar and we are installing the entire power generation also, but we are not connecting it. Because the moment we connect it, it will be treated as the part of FDRE. Because right now in the summer the price is very good, we are not connecting that. We are just connecting the battery and charging from the grid and selling it. That is giving us a very good return. So we are doing purposely. But the day that COD time line comes in, LTDA, LTA days comes in, the whole thing will get integrated and...

And Dhruv, we are deferring the CapEx also on the solar side because it is not -- doesn't make sense to call modules at site and keep them here because what we are doing is we are deferring the solar part of CapEx. We are not installing the modules. We are because, of course...

You can get the cheaper merchant power from exchange...

And also the interest during construction is safe. So there is no reason to do a solar CapEx until your LTO is operational. So we are deferring that also, which is helping us improve our returns.

Got it, sure. And sir, last question is, you mentioned about the commissioning target of your generation assets for this year. But if you can give the number what you're targeting to commission based on -- of generation assets based on whatever transmission visibility you have in megawatt terms?

So we are targeting 1.5 gigawatts of projects in this financial year, right, and around 10 gigawatt hour of battery. So this 10 gigawatt hour of battery may be for those projects which are not included in this 1.5 because for 1.5 it will be maybe 5 gigawatt hour, but we are charging the battery ahead of time.

Next question is from the line of Dhruvin Shah from HDFC Securities.

I think my question was answered in the previous question. But I just wanted to clarify, the 10 gigawatt that you said we are planning to commission this year, how much of it would be on merchant basis? And what is the kind of EBITDA margins that we can expect on the capacities that operate on merchant basis? That's it.

Yes. So see, in terms of the -- all of it will start on -- other than the -- you can say around 1,200 megawatt hour to 1,500 megawatt hour, which will be commissioned on the FDRE format because of the Neemuch substation, which I mentioned earlier. Rest of it will start on the merchant basis in this financial year because the substations will get start charging in the fag end of the year only. So you will see around 8.5 gigawatt hour out of this 10 gigawatt hour would be on merchant. And 1.5 gigawatt hour would be in the FDRE format. In terms of the EBITDA realization, Ankit, I'll request you do it.

Yes. On the EBITDA margin, look, it's a function of at what cost you are procuring and of course at what price you are selling. But assuming a tariff arbitrage of INR 6, which means selling the power at INR 8, which of course more than that we are currently seeing and purchasing the power at INR 2. So give or take, the margin will be around 75% to 80% EBITDA margin.

Next question is from the line of Aanchal Jalan from Lotus Wealth.

So my question is that in the first slide for under construction portfolio, a total of 3,280 megawatt plus 1,200 gigawatt hour of BESS portfolio is given. So by when will this be completely commercialized, the whole under construction portfolio?

Yes. There is a second slide also, which is PPA yet to be signed. But on the PPA signed, yes, so these will be commissioned by FY '28. Battery we are putting up early, like Nikhil mentioned earlier.

Next question is from the line of Sweta Jain from Anand Rathi.

A couple of questions on this best arbitrage that we're talking about using conventional power and then discharging at peak demand. How long do we see that this arbitrage situation should sustain into the future?

This is anybody's guess in terms of that...

Nikhil, let me take this answer. Yes. Actually, right now, the current calculation of CA is you need around 200 gigawatt hour of battery to come to this if you don't add any more solar. But what is happening is also another 40, 50 gigawatt of FDRE and this one where the tender has happened, they will get added in the daytime. So technically, what is happening as long as you are adding more and more daytime solar, you need a more battery in the unit. So that's a formula. Right now, that formula tells we need 200 gigawatt hour. But what has also happened is that the thermal power in the evening, it is already at INR 6.5 if you run at full capacity. And most of the capacity thermal power cannot come up fast and cannot go down. So they operate around 60%, 70% capacity. So considering their capital cost, full capital cost in this one, they are around INR 9 and INR 10. So battery will remain -- my guess is battery will remain at INR 9 to INR 10 in the peak hour time. And as a country, we will need around 200 to 300 gigawatt hour considering the current installation and the planned installation of this year. But as and when we are adding more and more solar, it will keep on going up.

So if you look at the history, if you look at the last few years, we have seen that the annual price remains at around INR 7 to INR 8 for the last few years, even when we have low demand. In terms of the last few years, we had relatively less demand than before. But even in those slow years, we had a realization for peak power for around 7, 8 years. But now that the gas is constrained, it is slightly elevated, and it is likely to be elevated. And we are seeing some peak demand, which is much, much higher than last year. So we see that like Manojji mentioned, at least for around 4, 5 years, we don't see this going down.

That's helpful. Secondly, sir, on -- when you mentioned that majority -- almost 80% of our projects would be on the CTU side of the business, wanted to understand the transmission and distribution angle. Are we facing lag in terms of substation connectivity at the SKU level or the CTU level from an industry perspective? And how do you see the projects getting commissioned when we shift the portfolio to this 80% mark that we're looking at?

So see, in terms of the CTU substations, what happens is there is a lot of linkages. They are mostly on time with regards to their local infrastructure regarding bay construction and equipment ordering. Where they lag is the components relating to transmission line interconnection and right-of-way issues because of which there is a time line delay at their end. And the central transmission utility is in turn dependent on the various companies which bid for them. So they get a time line basis, the delay on their part. So the CTO is a very structured entity where they keep -- give you a firm date every quarter when their substation is coming up. So as far as we are concerned, we plan our project basis that declared date because that's the obligation on our part to commission the project by that date, and we get extension till the time that thing is coming up. So till date, they have done a wonderful job of give and take 6 months delay. They have done a wonderful job of coming up with the transmission capacity. And we have also been in sync with that, let's say, a delay of 6 months. We also try and sync our CapEx and sync our work along with that. So as a renewable player, we can't really function without the transmission. So we have to sync up. So there has been a delay. But for a grid of this size and scale, which is the largest in the world, single grid, I think that has done a good job. So 6 months delay is, I think, very much -- should be taken in a good light. As far as the STU is concerned, we are not building any projects on STU. The Gujarat project of wind that we did was the only project we have done on the state grid. There is no project in our pipeline other than the battery we are installing on the Andhra Pradesh, very small 550 megawatt hour. There is no project on the state grid. And state grid is a different organization structure. It depends on each and every different states. Some states are more efficient, some states are not. And some states don't have renewable energy potential, so they don't really develop their grid as much. But states like Gujarat are quite good, I must say. And of course, in terms of getting the transmission up and running on time. But it varies from state to state. But as far as we are concerned, state -- STUs are not a factor. And as far as the portfolio realization and risk and everything is concerned, CTU is a much better place to be in terms of the curtailment and in terms of the predictability of the substation coming up on time and in terms of central grants and monitoring at every level.

Got it. And just lastly, so our project blueprints already factor in the 6-month kind of a delay on a nominal basis?

Yes. So what we -- see, typically, this can't be generalized. This is on a generic overall portfolio level. But some substations, you can say around 60% are on time. The maximum delay is typically 6 months. In some cases, because of some unfortunate event, it could be more. But typically, some -- like I mentioned, our Neemuch substation is on time, right? Some substations are delayed. So not every substation is delayed. But wherever it is delayed and we know it from now, we will not call for our modules. We will defer our CapEx. What we can do about it? I can tell you what we can do about it. We can defer our sizable CapEx of modules because there is no -- because modules are available just in time and there is sufficient capacity of that available in India. So we will not call for modules because it's around 60% of a solar plant CapEx or sometimes more. So you don't do that. You keep the service-related work ready, the transmission line ready, the substation ready because those are typically, you can say, 20%, 25% of the overall project cost. But these are long lead items. So you do that, you don't call your modules. You keep your -- everything else ready. And that's how you defer the CapEx. And that is how the industry has been doing and syncing up with the power grid or CTU. And also there are extensions also. The good thing is you don't get any penalty because of the delay because of this because -- and that's how the central renewal program has been running because -- in sync with the grid.

Sir, just one last question. So there is no risk in such cases and on -- there would be no risk in terms of PPAs getting not signed or getting the DISCOMs not eager to sign the PPAs from the developer's perspective?

So see, that's a different question. See, in terms of the -- if you don't have a connectivity, there are 2 things on PPA signing bids, right? PPA signing when you go to a DISCOM, they look for what is the declared date of your substation, right? And they look for a declared date of substation getting charged in near term, right? So if you are somebody who has a substation getting charged in 2027, you will get a better priority from a DISCOM because customers have more visibility to your project, right? Because -- but if you -- if there is somebody whose substation is coming up in, if the connectivity he has is for 2029, then you'll get a second trial. He'll not get a seat at the table, right? Because the state will I don't want power in '29, I want in '27. And there are certain ISTS waivers also which are expiring in 2028. So this determines your attractiveness to the customers, right, in terms of the connectivity date, right? But if they get delayed in future, the states also don't get penalized because they are also part of the same sync up formula, where the ISTS waiver also they are eligible for depending on the original date declared by CTU. So that's a good regulatory setup where nobody is basically penalized for the delay on the behalf of CTU, neither the states nor the developer, right, gets penalized because it is something beyond their control, right? So the only thing which a state needs to take care of when they are signing PPA, what is the declared date of that substation, right? As long as that is '27, they will get the same window of ISTS waiver, which is applicable during that particular year, even if the substation gets delayed to '28 and '29.

Ladies and gentlemen, that will be the last question for today. On behalf of ACME Solar Holdings Limited, that concludes this conference. Thank you for joining us, and you may now disconnect your lines. Thank you.