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Adani Power shares require more than a headline profit or a large capacity target. The central diligence questions are whether plants are dispatched, fuel is available at recoverable cost, contracted customers pay on time, new projects are completed without excessive borrowing, and reported earnings convert into recurring cash. The company has reported strong FY26 profitability and higher nine-month generation, but its own disclosures also show sensitivity to merchant prices, weather, renewable output, regulatory timing and financing needs. Those facts do not by themselves establish that the shares are attractively valued.
What Adani Power does and what drives its earnings
Adani Power generates electricity, mainly from thermal plants, and sells it through a combination of long-term and medium-term power-purchase agreements (PPAs), open capacity and short-term or merchant markets. In the company’s description of its model, two-part, availability-based tariffs and PPAs provide core earnings visibility while uncontracted capacity can capture upside when market prices are favorable. That is management’s framing, not a guarantee of realized margin.
For an investor, the operating chain is more important than the headline PPA percentage: a plant must be available, have fuel, receive a dispatch instruction, deliver electricity under the applicable contract and collect the resulting bill. A PPA can reduce exposure to spot prices without eliminating risks from lower dispatch, tariff formulas, counterparty credit, delayed collections or disputes over fuel-cost recovery.
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Capacity, utilization and market exposure
Plant load factor (PLF) measures how much electricity a plant generates compared with its maximum possible output over a period. It is affected by plant availability, dispatch orders, fuel, maintenance, demand and market prices. A larger fleet can sell more units in absolute terms while still recording a lower PLF if new capacity is added faster than generation grows.
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What the latest reported numbers show
The latest audited consolidated results cover the year ended 31 March 2026. The figures below are reported results or company-reported operating data, not forecasts.
| Period or item | Reported figure | How to interpret it |
|---|---|---|
| FY26 revenue from operations | ₹54,240.52 crore | Audited consolidated revenue for 1 April 2025–31 March 2026 |
| FY26 profit before tax | ₹15,499.51 crore | Audited consolidated result |
| FY26 continuing-operations net profit | ₹12,971.08 crore | Audited consolidated result |
| FY26 finance costs | ₹3,366.83 crore | Shows the cost of funding the capital-intensive business |
| FY26 depreciation, depletion and amortisation | ₹4,564.53 crore | Non-cash accounting charge that also signals a large asset base |
| 9M FY26 installed capacity | 18,150 MW | Company update for the nine months ended 31 December 2025 |
| 9M FY26 plant load factor | 64.1% | Compared with 69.2% in 9M FY25 |
| 9M FY26 units sold | 71.8 billion | Compared with 69.5 billion in 9M FY25 |
| 9M FY26 continuing revenue | ₹40,523.67 crore | Compared with ₹41,950.67 crore in 9M FY25 |
| 9M FY26 continuing EBITDA | ₹15,713 crore | Compared with ₹16,478 crore in 9M FY25 |
| 9M FY26 continuing profit before tax | ₹9,896 crore | Compared with ₹10,679 crore in 9M FY25 |
| 9M FY26 profit after tax | ₹8,700 crore | Compared with ₹10,150 crore in 9M FY25 |
The combination of higher units sold and a lower PLF is consistent with a larger installed base and changed dispatch conditions. The company attributed the nine-month comparisons to lower power-selling rates, lower other income and lower one-time prior-period income. It also reported all-India electricity demand of 1,287 billion units for 9M FY26 versus 1,280 billion in 9M FY25, while peak demand reached 242 GW compared with a 250 GW peak during FY25. These are figures and explanations in the company’s release, not an independent demand forecast.
Q3 merchant sales and market conditions
For Q3 FY26, merchant and short-term sales were 4.3 billion units, down from 4.6 billion units in Q3 FY25. The company linked softer merchant rates and lower offtake under some PPAs to extended monsoons, cooler weather, weaker demand and rising renewable generation. This is a practical demonstration of why contracted capacity does not make earnings entirely independent of the power market.
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In its Q2 FY26 release, the company reported Q2 power sales of 23.7 billion units, revenue of ₹14,308 crore, EBITDA of ₹6,001 crore and profit after tax of ₹2,906 crore. For H1 FY26 it reported revenue of ₹28,882 crore, EBITDA of ₹12,151 crore and profit after tax of ₹6,212 crore. It said lower merchant tariffs and lower international coal prices affected some PPA tariff realizations.
As of 30 September 2025, total debt was reported at ₹47,253.69 crore, compared with ₹38,334.88 crore at 31 March 2025. Net debt was ₹36,775.72 crore versus ₹31,023.43 crore. Management attributed the increase to bridge financing for capital expenditure and working-capital borrowings associated with increased operating scale. These are dated balances; use the audited FY26 balance sheet and later exchange filings for a current leverage assessment.
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Risk 1: dispatch, utilization and merchant-price exposure
Electricity demand is seasonal and weather-sensitive. Lower demand, high renewable output or a change in grid dispatch can leave a plant generating below its technical capability. Merchant prices can fall at the same time, reducing both volume and realized tariff.
Checks to perform
- Separate capacity covered by effective PPAs from open or merchant capacity, and examine the percentage by plant rather than relying only on a group-wide figure.
- Track plant-wise availability, PLF, scheduled generation, actual generation and realized tariff for several quarters.
- Compare contracted offtake with actual offtake and identify any curtailment, deemed-generation payment or dispatch restrictions.
- Review the sensitivity of EBITDA and cash flow to lower PLF and lower merchant prices.
Risk 2: fuel supply, coal prices and pass-through
Thermal plants need reliable coal at a delivered cost that the tariff allows the generator to recover. Contracts differ: some may pass through specified fuel costs, while others leave more exposure with the generator or depend on regulatory approval. The company’s Q2 FY26 release said lower international coal prices affected tariffs under some PPAs, illustrating that a fuel-price movement can reduce billed revenue when the tariff formula passes the change through to the buyer.
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Fuel due-diligence checklist
- Identify domestic linkage allocations, imported-coal requirements, suppliers, inventory days and rail or port dependence for each major plant.
- Read the fuel-adjustment clause in each PPA: what costs are recoverable, with what lag, cap, benchmark or approval?
- Compare contracted fuel volume with expected generation and test the impact of a shortfall or transport disruption.
- Check whether fuel-cost claims are billed, accepted by the counterparty and collected in cash.
Risk 3: PPA quality, DISCOM credit and receivables
The Q3 FY26 update said 90% of operating capacity was tied up under long-term or medium-term PPAs. That is a current company-reported figure for that update; it should not be substituted with the older FY25 statistic of 87% contracted capacity, of which 92% was described as having assured fuel-cost recovery. The two percentages refer to different reporting dates and should not be combined.
A PPA improves visibility only when its terms are enforceable and the buyer can pay. Examine tariff structure, minimum offtake, change-in-law provisions, payment security, letters of credit, counterparty concentration and the age of receivables. The company referred to realization of DISCOM dues in FY24 and FY25 and to resolution of major regulatory matters. That history makes cash collection and the source of each receivable especially important.
Questions for the financial statements
- How many days of revenue are tied up in trade receivables, and is the balance rising faster than sales?
- Which counterparties account for the largest unpaid amounts?
- What portion is under dispute, subject to regulatory approval or supported by payment security?
- Do operating cash flows broadly track EBITDA after working-capital movements?
Risk 4: expansion, construction and commissioning
Growth plans create value only after projects are permitted, financed, built, fueled, commissioned and dispatched at economic tariffs. The Q2 FY26 release described a 23,720 MW expansion program and a capacity target of 41,870 MW by FY2031–32. The Q3 release announced a 3,200 MW project award in Assam and said nearly half of the 23.7 GW expansion was tied up in PPAs with State DISCOMs.
Those statements are management plans and reported milestones, not independently verified completion outcomes. A project can have a PPA and still face land, environmental, equipment, transmission, fuel, financing or commissioning delays.
Project-by-project review
- List every project, its planned capacity, location, technology, expected commissioning date and current construction stage.
- Confirm land, environmental, water, transmission and other material approvals, noting which are final and which remain conditional.
- Compare approved project cost with spending to date, committed purchase orders and the remaining funding requirement.
- Check whether the PPA is signed, effective and supported by payment security, rather than merely under discussion or awarded.
- Test the economics at higher construction cost, delayed commissioning, lower PLF and changed fuel prices.
Risk 5: debt, interest cost and liquidity
Power projects require substantial capital before they generate operating cash. The company reported a ₹7,500 crore issue of non-convertible debentures on 27 January 2026 for expansion and working capital. The audited FY26 filing reported finance costs of ₹3,366.83 crore. New borrowing can be sensible when matched by commissioned capacity and contracted cash flow, but leverage becomes risky when debt grows faster than operating earnings or when projects are delayed.
What to examine
- Current gross debt, net debt, cash balances and undrawn committed facilities.
- Debt maturities, floating-rate exposure, security packages, covenants and refinancing dates.
- Interest coverage using recurring EBITDA and operating cash flow rather than a quarter helped by exceptional income.
- Capital commitments, bridge loans and the amount of interest capitalized during construction.
- Whether debt growth is funding productive commissioned assets, working capital or repeated refinancing.
An issuer credit rating can inform the review but cannot replace a maturity and liquidity analysis.
Risk 6: earnings quality and regulatory timing
The company said prior-period revenue recognition moderated in FY26 after major regulatory matters were resolved and DISCOM dues were realized in FY24 and FY25. That means reported profit may contain timing effects that do not repeat in the same form.
Reconcile reported revenue and EBITDA with generation, realized tariff, receivables and cash collections. In the notes to the audited accounts, distinguish recurring operating revenue from prior-period claims, regulatory deferrals, exceptional items and reversals. The cited releases do not provide a complete, proceeding-by-proceeding inventory of litigation, contingent liabilities or unresolved regulatory matters, so those notes and subsequent exchange filings are essential.
Risk 7: environmental and power-transition exposure
The reported fleet is thermal-focused. Thermal generation can provide dependable supply, but it faces emissions, water-use, environmental-compliance and potential transition-cost risks. The company itself cited rising renewable generation as one factor affecting demand and merchant sales.
Review plant-level emissions and water requirements, compliance status, scheduled environmental upgrades, remaining useful life and the economics of each proposed addition under a generation mix with more renewables. The available company materials do not independently quantify future carbon prices, transition costs or the probability that a particular plant becomes uneconomic.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.Risk 8: valuation and share-price risk
Good operating results do not prove that a share is cheap. The retrieved issuer information did not provide a usable live quote as of the research date, so no current price-to-earnings, enterprise-value-to-EBITDA or peer-relative conclusion is justified here.
A disciplined valuation process
- Use a dated market price and record the exact quote date and exchange.
- Normalize earnings by removing identifiable prior-period, regulatory or exceptional items.
- Use operating cash flow, maintenance capital expenditure and working-capital needs to test whether accounting profit converts into cash.
- Model debt, interest expense and committed expansion spending under base, downside and delayed-project cases.
- Compare the same reporting period and definitions with listed power generators, including PPA duration, merchant share, PLF, fuel recovery, receivable days, net debt and valuation.
Do not answer “Is Adani Power a good stock to buy?” from a single quarter, a capacity target or an unadjusted profit number. The answer depends on price, normalized cash generation, balance-sheet capacity and the investor’s tolerance for project, regulatory and market risk.
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A practical pre-investment checklist
Before buying, document the answers rather than relying on a presentation headline.
- Business mix: What percentage of operating capacity and expected generation is contracted, and for how long?
- Dispatch: Are PLF, availability and offtake improving or weakening by plant?
- Fuel: Is coal secured, delivered on time and recoverable under each PPA?
- Customers: Who owes the money, how old are receivables and what payment security exists?
- Projects: Which expansion units have final approvals, signed PPAs, financing and realistic commissioning dates?
- Funding: What are debt maturities, interest rates, covenants and total remaining capital commitments?
- Cash: Does operating cash flow support reported EBITDA after receivables and inventory movements?
- Accounting: Which earnings are recurring, and which arise from prior-period or regulatory resolution?
- Transition: What compliance and generation-mix assumptions underpin the asset values?
- Price: What valuation is implied by a dated quote under normalized earnings and downside cash-flow cases?
How to compare Adani Power with another generator
Use identical periods, consolidated or standalone scope, currency units and accounting definitions. A fair comparison should include:
- Contracted capacity, PPA tenor and merchant or open-capacity share.
- Plant availability, PLF, units sold and realized tariff.
- Coal mix, domestic linkage, imported exposure and fuel-cost recovery.
- Receivable days, counterparty concentration and cash conversion.
- Recurring EBITDA, finance cost, net debt and capital expenditure.
- Capacity under construction, approval status and historical commissioning performance.
- Valuation based on normalized earnings or cash flow, not only reported profit.
The available material does not provide a complete peer dataset, so a claim that any generator is the “best” or “cheapest” would require additional, consistently sourced numbers.
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In the 29 January 2026 Q3 FY26 results release, CEO S. B. Khyalia said: “We are swiftly securing long-term power purchase agreements for our upcoming capacities, with nearly half of our 23.7 GW expansion already tied up in PPAs with State DISCOMs.” This is management’s statement about progress. Investors should verify each project’s executed PPA, approvals, financing, construction status and eventual commissioning before treating the target as future cash flow.
Bottom line
Adani Power’s FY26 audited results and nine-month operating update show a large, profitable and expanding generator, but they also show why diligence cannot stop at revenue, PAT or contracted-capacity percentages. The decisive checks are plant-level dispatch, fuel and tariff mechanics, customer collections, project execution, debt service, recurring cash flow, transition exposure and the valuation implied by a dated share price. Until those checks are satisfied, the evidence supports a structured risk review—not a blanket buy or sell conclusion.
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