Q1FY27 record PAT INR4,867cr (+47% YoY).

For the Assam and Karnataka PPA - what is the tariff, fixed and variable charge? Also, have we signed any extra 200-megawatt PPA with Assam? And for Karnataka PPA of 570.5 MW with APL Raigarh?

Assam PPA for 3,200 megawatts. The Total charge is INR 6.30/kWh. Out of that, capacity charge is INR 4.16/kWh. For Karnataka, this is INR 5.78 per unit. The fixed component is INR 4.5.

If you can give PLF, revenue and EBITDA for Godda power plant?

Godda Quarter 3 continuing revenue is INR 2,210 crores. Continuing EBITDA, INR 1,092 crores. And for 9 months, the continuing revenue is INR 6,787 crores, and continuing EBITDA is INR 3,247 crores.

Given the Vidarbha and Karnataka get operational, would the dependence on merchant reduce in coming quarters?

You might be witnessing our strategy. So, if you see that 2 years ago, our open capacity and the PPA was 80-20, which got reduced to 84-16. Now this is 90 and 10. So we are very much mindful about the merchant tariffs and rate. And what we have strategized that we are minimizing our portfolio open capacity, resulting into ensuring the assured Revenue and EBITDA irrespective of market volatility. So, the open capacity is already at 10%.

Just one question - if you can give the volume, long term, and merchant volumes for the quarter?

Merchant volume for the quarter was 4.3 billion unit. And for 9 months, this is 15.65 billion units.

In your opening remarks, you mentioned about the impact of merchant prices being significantly lower as well as imported coal price impacting the energy charges. Could you quantify both of these on a Y-o-Y basis?

Merchant realization in terms of tariff for this quarter, is INR 4.37/kWh, as against that, of same period last year, it was INR 4.56/kWh. And for this year 9 months, INR 5.44/kWh, and it was INR 6.16/kWh in the same period last year. As I explained, we are mindful about this market volatility and we have now around more than 90% capacity under PPA and only we have 10% in open capacity. Over the period of 6, 7 years, it will further reduce from 10% to 3% to 4%.

On the imported coal price - what's the cost at which you have bought or incurred at a landed basis this quarter versus the same quarter last year?

Let me brief you about the indices. This time, quarter 3, the HBA Index on average is $104/tonne, as against the same quarter last year, it was $123/tonne. So, $123 versus $104, and on a year-and-year basis, this is against $138/tonne on average to $108/tonne. So, there is a reduction of near about the $15, $16 on per metric tonne basis. This resulted into a lower revenue in some of the plants based on the imported coal.

On the earlier question, I missed the PLF number for Godda for this quarter versus last year? As well as revenue and EBITDA for the same quarter last year for Godda?

The PLF for Godda Jharkhand this year on quarter basis, is 68%, and same period last quarter, it was 50%. So, there is an increase in PLF of Godda by 18%, so supply of units has also proportionately increased in comparison to last year. Quarter 3 FY '25, the revenue was INR 2,132 crores, and EBITDA was INR 1,222 crores, for 9 months same period, it was INR 6,604 crores, and EBITDA was INR 3,989 crores.

There are 2 essentially large PPAs that were in the works for Rajasthan and Uttarakhand. There's been some sort of news with respect to the regulator not approving the Rajasthan tender. Just your thoughts on that. And going forward, when can we expect these tenders?

Just to clarify about the regulator's view, the regulator felt based on the submissions given that the full 3,200 megawatt PPA may not be required together, based on the resource adequacy plans that the regulator had seen. The DISCOM has represented that they would like to revisit the assumptions and prove their accuracy. The regulator has given them that permission to present their case again. So that should take place in some time, and we should see the PPA moving ahead after that. In case of Uttarakhand, the bid documents have been released. It's going to take a little bit longer, but we should see the PPA bids being submitted over the course of the next few months.

I can see that the interest cost has been declining fairly well. How is the average cost of borrowing now looking for us compared to, let's say, 1 year back? What would be the weighted average?

If you see on the long-term rate, this is near about 8.5%. The PFC-REC funding for Jharkhand, which is already merged with Adani Power and part of Adani standalone entity, now this asset is also rated AA and its interest cost has also got reduced significantly. Apart from that, our working capital rate is also near about 6.5% to 6.8%, and the non-fund based rates are also very competitive. Weighted average cost will be less than 9% this year.

On the merchant portfolio that's remaining, the remaining 10% of, let's say, 18.15, which is about 1.8 gigawatt. Could you quantify that across plants?

If you want to quantify it, for Kawai, we have 50 MW. For our Udupi plant, we have near about 109 MW, not very significant. In Mundra, we have 226 MW. Raigarh, we have near about 67 megawatts. In Raipur operating plant, it is very insignificant. In Mahan operating plant, we have near about 284 megawatts. And some small parts in some of the other plants. So, making it total 10% of overall fleet.

You talked about renewable capacity scaling, which impacted merchant pricing. So how should we think about that as renewable capacity increases over the next few years, how should we think about the structural impact on thermal dispatch and merchant pricing?

We have 18.15 gigawatt of operating capacity. And we have the plan for capacity expansion of another 23.8, so near about 24 gigawatts, making it total 42 gigawatts over the period of next 6, 7 years, or in financial year '31-'32. Being the baseload power, this is 2-part tariff. Fixed capacity charges, where we are ensuring that our plant is available 90% plus. Now coming to the addition of the plant, 24 gigawatts, our 100% EBITDA is driven by capacity charges only because fuel charges are 100% pass-through. There will be no impact in terms of whether there is demand or not. If plant is available, we will raise our bill, and our EBITDA will be ensured. Nishit Dave added: In the last quarter and also the year till date till December, what has actually happened is that because of the extended monsoons, we have seen a good amount of increasing hydropower generation. The contribution of thermal energy in Q3 FY '26 fell to 73% from 76% earlier. For the total renewable energy contribution, which was around 20% earlier, that is both normal renewables plus large hydro. It has actually increased to around 24%. We expect to see that sort of 380 to 400 gigawatt peak capacity requirement by fiscal '32.

In the past, you have said that the goal is to get the PPAs even higher, right? Maybe closer to 100%. Is that still the plan?

Yes. So you have to see the baseload and thermal capacity differently because this is part of resource adequacy, irrespective of sources of the power. So, every state has to demonstrate that they have proper resource and after this, they are tying up all these PPAs. The baseload, which is mainly from thermal, this resource availability is to be ensured, every single state and DISCOMs, they are paying the capacity charges. The resource adequacy part for baseload capacity is constant irrespective of sourcing of power.

As we're sort of towards the end of January, maybe if you can just give us a sense for how some of the operating metrics might be looking like on O&M availability, PLF and should we be aware of any exceptional items in this March quarter?

If we see the demand for December and January. This is already increased on year-on-year basis. It will and also the demand is higher by 10%, 12% on a month-to-month basis. What we are expecting that in quarter 4, the demand will definitely be higher than the current quarter. And so, O&M availability, 90% anyway is there. And we think that PLF will also be better than quarter 3. Nishit Dave added: As we approach the hotter months, typically, we see the PLF going up. For the full year, we should be ending with more than 90% overall plant availability anyway.

Can you just repeat again the physical progress plant wise you had mentioned in the opening remarks. And also, I think you mentioned that Korba is likely to get commissioned next year. I believe that there is no PPA for Korba as of now. So, what are the plans over there?

So Mahan, we have actually progressed nearly 80%, Mahan Phase 2. Raipur Phase 2, we are at around 44% and Raigarh Phase 2 around 38%. Korba Phase II, we actually acquired this Phase II project in a defunct state, and we have now revived the project. So, this first unit of the project should get commissioned somewhere around the middle of next year and the second unit by the end of next year. We are looking at various opportunities in the market for bidding for PPAs. Depending on the opportunity, we can sell power in the medium-term market. We can also look at supplying power in the merchant market because actually this plant is located right in the middle of some very large mines.

In terms of the 24 gigawatts of under-construction capacity, can you just break it down as to how much is likely to get commissioned, say by FY '28, FY '30 and beyond?

Broadly speaking, next year, around 2.9 gigawatts will get commissioned; in fiscal '28, another 2.4 gigawatts; in fiscal '29, 2.4 gigawatts; in fiscal '30, we have 8 gigawatts being commissioned altogether. In fiscal '31, we will have 5.6 gigawatts and then 2.4 gigawatts. So, the entire capacity, this is how it is actually expected to shape up and the plants that we expect to get commissioned in fiscal '30, we have started work on some of these plants.

The Uttarakhand PPA that we have signed for 400-odd megawatt, what is the tariff for that? Capacity charges would be around?

Uttarakhand medium-term PPA tariff is INR 5.85/kWh. This is 50%-50%, fixed cost for 2.9.

On the Bangladesh Power Plant, the Godda power plant - now that coal exports are allowed from India, are we allowed to use domestic coal for this plant, and there was some recent press article around the plant. So just wanted to make sure, contractually, there are no termination clauses that are there in the contract and that we are well protected?

Let me apprise you about this plant, which is situated in Godda district of Jharkhand, dedicatedly supplying power to Bangladesh. We are supplying around 10% of Bangladesh total effective capacity. The zone where we are supplying this power, this is around 20%. Now this is the plant, the dedicated supplying and earning around $1 billion for the country. Now the supply is regular, the payment collection is regular. The relationship is very much intact. There may be some sort of issues in that country, but we are mindful of the circumstances and environment, and we are keeping watch on it. But the operation, supply everything is going to continue. Nishit Dave added: In August '24, the government of India modified its guidelines related to the export of power from India on a cross-border basis. Previously, it was only imported coal, but now domestically sourced coal as long as not government-controlled priced coal, you can actually use domestic fuel.

On this pipeline of 15 gigawatt of ongoing thermal tenders. Could you give some more colour on that? Out of the 15, have any of them progress to financial bid submission? Or are they still in the bid invitation stage only? And no other state reconsidering like Rajasthan?

As we understand, Maharashtra financial bidding has been done, but the bidding process, we think it is still to be closed. In other cases, I think we are at the prequalification bids or, you can say, discussion on the bidding document stage. No other state reconsidering. In case of Rajasthan, it is primarily about how the regulator sees what the CEA has worked out as part of the resource adequacy plan and what DISCOM itself says about their future requirements.

Most of my questions have been answered.

No question asked - moderator moved to next analyst.

Bookkeeping question on your open versus PPA tied-up capacity. In your presentation, we see that 5.5% is yet to be operationalized. Is that 5.5% part of that 90%, which means currently 84.5% of the operational capacity has operational PPAs?

Out of the total 100% capacity that we have, some of these PPAs are being operationalized as we go along. But on an average basis, you can consider that 90% of the capacity is tied up and ready to supply power under the long-term PPAs. Some of the additional capacity will start over the next few months and then this would increase to around 93%. The 5.5% is part of that 10% which is not tied up yet and eventually will get operationalized.

On the 370-megawatt PPA that's been tied up with Uttarakhand that happened at the beginning of the quarter? Did you get the full impact of that during this quarter? Or is this going to be operationalized after the quarter 3?

These PPAs that we are talking about primarily that are not yet operationalized. These PPAs that are with our group companies, where we will actually start to see them getting operationalized. The Uttarakhand PPA will start supplying it from next month onwards.

For 3,200-megawatt Assam greenfield project, what is the estimated capex per megawatt? And what will be the equity and debt mix for the expansion you are planning?

We are not going for any project-wise financial closure in Adani Power. So, if you see our performance from operating assets, the continuing EBITDA is very good and FFO on a yearly basis from our operating assets is also very good. So near about INR 20,000 crores of FFO. And majority of our capex, we are funding from our internal accrual, so there is no project specific funding we are doing. Now in terms of the capex cost is concerned, for Assam, it will be near about the INR 10 crores per megawatt basis.

Regarding Godda power plant, it is mentioned that a significant amount from the Bangladesh board in the 9 months that we have recovered. So, could you please quantify the current outstanding receivable from Bangladesh board as on 31st December? And on the unsecured perpetual securities, company has paid around INR 3,000 crores in the first 9 months and what is the outstanding balance?

What I explained to you is that the outstanding from Bangladesh is regular. So let me explain the Bangladesh matter, supply is regular, billing is regular, payment we are getting on a regular basis. So, the dues are near about equal to -- 1 month is not due. There are about 2 months due is there so far Bangladesh is concerned. So, we're getting payment regularly from Bangladesh. So, it's a regular due. On unsecured perpetual securities, we have paid the entire amount. If you ask what is the outstanding, as of now, there is no outstanding at all. So, you can say it is nil. No outstanding.

With power demand remaining strong and thermal generation continuing to play a critical role in grid stability. How is Adani Power thinking of optimizing its operating portfolio between contracted and merchant exposure? In this context, how do you prioritize sourcing tactics, plant efficiency improvements and long-term capacity utilization to ensure sustainable returns?

We have 18 gigawatts capacity now. We are adding another 24 gigawatts. Now for the new capacities that we are setting up, actually, we intend to tie up the entire capacity in long-term PPAs and the existing capacity also has 90% tie-up in long-term PPA. So, we actually are reducing our merchant exposure going forward. Now if you look at the overall structure of the new PPAs in this case, now the entire game has become keeping generation capacity available to help integrate more renewable power into the grid and to continue to supply base load power. The PPAs or you can say the power plants will now act more as increasingly as we go along, they will start to act more as balancing power plants. These power plants that we are setting up are the state-of-art in technology with very good levels of thermal efficiency, which means that they utilize lesser amount of coal to generate a unit of power up to around 5% to 10% advantage over the older technology power plants.

Given constant volatility in the fuel cost and the constant regulatory compliances, just want to understand what is your vision on approaching margin visibility and cash flow across the board? Additionally, can you just shed some light on the capital allocation and balance sheet priority as the company balances debt, maintaining capex and potential growth?

As we are briefing our overall capex plan over the period of 6, 7 years to add 24 gigawatt is near about 2 trillion. So, in dollar terms, we can say that USD 22 billion. So, INR 2 lakh crores capex program we have in Adani Power that we are going to incur over the period of 5, 6 years. The funding arrangement, majority of the funding arrangement we will do from our internal accruals. We have operating assets of 18.15 gigawatts. From that, on a yearly basis, we are generating an EBITDA of about INR 22,000 crores and FFO INR 20,000 crores. So, in the same period of time, so over the period of 5, 6 years, we are generating from our operating assets only INR 1.4 trillion -- so INR 1.4 lakh crores. So, there is a gap of INR 60,000 crores. And this interim gap is funded from a mix from the domestic capital market as well as from a domestic bank. By '31, '32, where we will add our entire capacity, our EBITDA and cash flow, we will have sufficient cash flow. We can pay our entire debt.