Evaluating a Hydropower Stock on NEPSE

First published 23 Aug 2026 · Last verified 29 Aug 2026

Lesson 44.1 — The NEPSE Hydropower Universe: One Sector, Several Different Businesses

If you have read the previous two chapters, you already know how a hydropower project is financed and how its cash flows are modelled from first principles — the debt sizing, the tariff structure, the concession period, the sensitivity of the whole edifice to how much water flows down a particular river in a particular year. Chapter 44 turns that knowledge outward. You are no longer building a model from scratch as a lender or a promoter would. You are an investor sitting in Kathmandu, or Biratnagar, or anywhere with a NEPSE trading account, looking at a list of forty-plus hydropower tickers on your broker's screen, and you need a repeatable process for deciding which of them, if any, deserves your money.

Start with a fact that surprises many new investors: "hydropower stock" is not one kind of investment. It is a label that covers at least four distinct business models, and confusing one for another is the single most common analytical error in this part of the NEPSE market.

The first model is the single-asset operator. This is a company that owns exactly one power plant, on one river, with one Power Purchase Agreement (PPA — the long-term contract under which the plant sells its electricity, almost always to the Nepal Electricity Authority, or NEA). Upper Tamakoshi Hydropower Limited is the textbook example: a single 456-megawatt (MW) peaking run-of-river plant on the Tamakoshi River in Dolakha, and nothing else. When you buy this stock, you are making a concentrated bet on one river, one tunnel, one powerhouse, and one buyer. There is nowhere for a bad year on that specific river to hide.

The second model is the diversified generation holding company. Chilime Hydropower Company Limited started life in 2003 as a single-asset operator of its namesake 22.1 MW plant on the Chilime River, but over two decades it has taken equity stakes in and consolidated several other plants — including Rasuwagadhi (111 MW) and the Sanjen cascade projects — so that today an investor in Chilime shares is effectively buying a small portfolio of rivers, not one river. Butwal Power Company (BPC) follows a similar pattern: it directly operates older plants such as Andhikhola (5.1 MW) and Jhimruk (12.3 MW), while also holding equity stakes in other hydropower special-purpose vehicles. This model smooths out the single-river risk of the first model — a drought or a landslide on one tributary does not zero out the whole company's generation.

The third model is the small, single-project independent power producer (IPP) — companies like Ridi Hydropower or Sanima Mai Hydropower, generally sub-25 MW plants built and listed by a promoter group specifically to raise public equity for that one project. There are dozens of these on NEPSE, and they are where most of the sector's retail trading volume happens, precisely because they are small, volatile, and easy to speculate on.

The fourth model is the pipeline or growth company — one that is still constructing its plant, or has just commissioned it and has not yet reached stable full-year generation. Here you are not really analysing an operating business yet; you are analysing a construction project with a stock ticker attached, and the risks are closer to those in Chapter 42's project-finance material than to a normal listed equity.

Before you open a single annual report, therefore, the first due-diligence question is simply: which of these four models am I looking at? A single-asset operator should be judged almost entirely on the quality of one river and one PPA. A diversified holding company should be judged the way you would judge a small conglomerate — sum of the parts, plus a discount or premium for how well the parent allocates capital between its subsidiaries. A small IPP should be judged on the same fundamentals as the single-asset operator, but with a much smaller margin for error, because a small company has no other asset to fall back on and often carries a proportionally higher fixed-cost burden per megawatt. A pipeline company should be judged on construction-risk criteria first and only secondarily as an operating business.

Lesson 44.2 — Run-of-River versus Storage/Peaking: Reading the Risk Profile Correctly

Chapter 43 introduced the plant-level distinction between run-of-river (ROR) and storage or peaking-ROR designs. This lesson translates that engineering distinction into an investment-risk lens, because it is the single biggest determinant of how "lumpy" a hydropower company's quarterly revenue will look.

A pure run-of-river plant has no meaningful reservoir. It generates electricity roughly in proportion to whatever water is flowing in the river at that moment. In Nepal's climate, river flow is dictated by the monsoon: roughly 80% of annual precipitation falls between June and September. A pure ROR plant on a river without significant glacial or spring-fed baseflow will generate at or near full capacity during the monsoon and can fall to a fraction of that — sometimes 20-30% of installed capacity — during the dry months of December through April. This is not a malfunction; it is the plant working exactly as designed. But it means that a pure ROR company's quarterly revenue swings hard between wet-season and dry-season quarters, and an investor comparing one quarter's earnings per share (EPS) to another without adjusting for season will draw the wrong conclusion every time.

A peaking run-of-river (PROR) plant — Upper Tamakoshi is again the reference case — adds a small pondage (a short-term storage basin, holding a few hours' worth of water) that lets the plant concentrate its generation into the hours of the day when electricity is most valuable, typically the morning and evening peaks when NEA's demand (and, under time-of-day tariff structures, its willingness to pay a higher rate) is highest. This smooths daily revenue somewhat and can lift the average realised tariff above the plain energy rate, but it does nothing to smooth the wet-season/dry-season seasonality — the total volume of water available across the year is still the fundamental constraint.

A true storage project — one with a dam and a reservoir large enough to hold back weeks or months of inflow — is the rarest category among NEPSE-listed companies, because storage projects are dramatically more expensive to build per megawatt and Nepal's private hydropower boom of the last two decades has been overwhelmingly a run-of-river boom. If a storage project does exist in a company's portfolio, it is the closest thing to an all-weather asset in the sector: it can release water in the dry season when tariffs (and NEA's need for firm power) are highest, effectively converting a hydrological disadvantage into a revenue advantage. When you do encounter one, treat it as materially higher-quality than an equivalent-capacity ROR plant, and expect the market to price it at a premium — check that the premium is not larger than the actual cash-flow advantage.

The practical due-diligence question that follows from this is: what fraction of this company's installed capacity comes from pure ROR versus peaking ROR versus storage, and what does its river's dry-season flow look like relative to its wet-season flow? Companies disclose monthly or quarterly generation figures in their annual reports (more on reading these in Lesson 44.4); plotting a few years of these numbers is the single fastest way to see a plant's real seasonality pattern, rather than trusting a one-line "run-of-river" label in a broker's factsheet.

Lesson 44.3 — The PPA Clock and the Royalty Staircase

Every hydropower company's cash flow has two clocks ticking inside it, and both matter enormously to a long-term investor, yet neither shows up as a single line item on the income statement.

The first clock is the PPA term itself. A PPA is not a permanent right to sell power; it is a fixed-term contract, typically running 25 to 35 years from the commercial operation date (COD), after which the company must renegotiate terms with NEA or, in principle, sell power on whatever open-market or bilateral arrangement exists at that time. For a young plant like Upper Tamakoshi (commissioned 2021), this clock has decades left to run and is a minor consideration today. For some of the older private plants on NEPSE — several of which date to the mid-1990s and early 2000s, including some of BPC's and Chilime's founding assets — investors need to actually check how many years remain on the PPA, because a plant approaching PPA expiry faces real uncertainty about what tariff it will earn afterward. This is disclosed (or should be) in the annual report's project description section, and it is worth writing down explicitly for every holding in a hydropower portfolio: "PPA signed in [year], term [n] years, therefore expires in [year]."

The second clock, and the one investors overlook far more often, is the royalty staircase. Under Nepal's Electricity Act and its associated regulations, hydropower generators pay royalty to the Government of Nepal in two components: a capacity royalty (a fixed charge per kilowatt of installed capacity per year) and an energy royalty (a percentage of the value of energy actually generated and sold). Crucially, both components are structured to step up partway through a plant's operating life — commonly after the plant has been operating for around fifteen years, the royalty rate rises meaningfully, in some structures by several multiples on the capacity component and by several percentage points on the energy component. The policy logic is straightforward: young plants are still carrying heavy debt service, so the state takes a small royalty share early on and a larger share later once the debt is substantially repaid and free cash flow is higher.

Why does this matter for stock-picking? Because it means a plant's after-royalty margin is not constant over its life — it mechanically compresses as the plant ages, even if gross generation and gross tariff revenue stay flat. An investor who values an older plant purely by extrapolating last year's net margin forward is quietly assuming the royalty rate never rises, which for a plant near or past its fifteen-year mark is simply wrong. Conversely, a newer plant still inside its low-royalty window has a margin cushion that will erode on a known schedule — a predictable headwind that should already be built into any multi-year cash-flow projection, not treated as a surprise when it arrives.

The practical checklist item, then, is twofold: (1) how many years remain until this specific PPA expires, and (2) has this plant already crossed, or when will it cross, the royalty step-up threshold. Both numbers should be sitting in your notes before you look at a single valuation multiple.

Lesson 44.4 — Reading the Annual Report: Generation Data, Realised Tariff, and the Monsoon Story

A Nepali hydropower annual report contains more decision-useful information outside the financial statements than inside them, and most retail investors never turn to those pages. This lesson is a guide to reading the parts that actually matter.

Start with the generation and sales table. Every well-run hydropower company discloses, usually in a schedule near the directors' report, the number of units (kWh or GWh) generated and sold in the year, frequently broken down by month or at least by quarter. This is the single most important table in the report, because it lets you answer three questions no ratio can answer on its own:

First, how does this year's generation compare to prior years, and if it fell, was that a plant-specific problem (a landslide-damaged intake, a transformer failure, a scheduled overhaul) or a river-wide hydrology problem (a below-average monsoon)? Nepal experienced a materially weaker monsoon in parts of 2023, and several ROR-heavy companies posted noticeably lower generation and revenue that year purely from reduced river flow — a useful real-world reminder that "hydrology risk" is not a theoretical line in a project-finance textbook, it shows up in actual reported numbers every few years. Distinguishing a hydrology-driven dip from an asset-specific failure matters because the two carry very different implications going forward: a bad monsoon year is a recurring, cyclical risk that should be averaged over a multi-year window, while equipment or landslide damage is a one-off (unless it recurs, in which case it says something troubling about maintenance quality or site geology).

Second, what is the plant load factor — actual generation divided by the theoretical maximum if the plant ran at full installed capacity every hour of the year? For a pure ROR plant with strong dry-season flow deficits, a load factor in the 40-55% range is often normal and not a red flag by itself; what you want to track is whether that load factor is stable, improving, or deteriorating year over year for reasons unrelated to rainfall.

Third — and this is the step most investors skip — what is the realised average tariff per unit sold, calculated simply as total energy revenue divided by total units sold, and how does that compare to the PPA's stated base tariff (which itself is usually specified separately for wet-season and dry-season energy, since most Nepali PPAs pay a materially higher rate for dry-season energy specifically to compensate ROR plants for their weakest months)? If the realised average tariff has been drifting upward over time faster than the PPA's contracted escalation would suggest, check whether the company has simply been generating more of its energy in the higher-priced dry season (a real, sustainable shift, perhaps from a pondage upgrade) versus a one-off adjustment or an arrears settlement from NEA that will not repeat.

Finally, look at how royalty and tax are actually presented. Royalty is sometimes buried inside "other operating expenses" rather than shown as its own line — if so, it is worth asking the company (many hold investor calls or respond to written questions) or checking the notes to the financial statements, because a hidden royalty step-up is exactly the kind of thing that quietly erodes margin without showing up in a quick ratio scan. Corporate income tax for hydropower companies in Nepal often carries a preferential rate or a tax holiday for an initial period after COD (a policy tool meant to encourage investment), which is another item that mechanically changes — usually upward — partway through a plant's life and should be modelled explicitly rather than assumed constant.

Lesson 44.5 — Promoters, Construction Risk, and the Balance Sheet: What Can Go Wrong Between the Prospectus and the Dividend Cheque

A hydropower stock is, in the end, a claim on a stream of dividends, and the distance between "the plant generates electricity" and "you receive a dividend" is longer and more encumbered than in most other NEPSE sectors. This lesson works through that distance.

Begin with the promoter. Nepal's hydropower boom has been driven substantially by a relatively small number of promoter groups and engineering-construction houses who have built and floated multiple projects over the past two decades. A promoter's track record across their earlier projects is a genuinely useful predictor: did their previous plants come in near budget and near the projected commissioning date, or did they run years late and multiples over budget (as many projects in this sector historically have, given landslide-prone terrain, seasonal access roads, and imported-equipment lead times)? Did dividends actually start flowing within a reasonable window of COD, or did the company sit on cash for years citing DSRA (debt service reserve account, explained below) requirements? A promoter's history of shepherding one project from construction into a paying dividend stream is a far better signal than the glossy language of a new project's prospectus.

For a pipeline company still under construction, the risk profile is close to what Chapter 42 described for project-finance lenders, not what a normal equity analyst is used to: cost overruns from geological surprises (tunnel collapses, unstable slopes — a recurring theme in Himalayan hydropower construction), delays that push back the COD and therefore push back the first dividend by a corresponding number of years, and foreign-exchange exposure on imported turbines, generators, and transmission equipment if the company has not appropriately hedged or matched its debt currency to its revenue currency. An investor holding a pre-COD hydropower stock should read the construction-progress disclosures (percentage completion, revised COD guidance) the way a lender reads a drawdown schedule, and should treat any COD guidance with a healthy skepticism born of the sector's own history of delays.

Once a plant is operating, the next layer is the debt structure itself. Nepali hydropower projects are financed with long-tenor project debt, usually from a syndicate of Nepali commercial banks (given the country's capital controls and the relatively limited scale of the domestic bond market), and that debt typically requires refinancing or restructuring risk at various points — either because the original tenor was shorter than the PPA term, or because covenants require periodic renegotiation. Two things to check from the annual report or notes to accounts: the debt maturity profile (how much comes due in the next one, three, and five years) and whether the company has a demonstrated ability to refinance on reasonable terms, versus being at the mercy of whatever domestic lending rates prevail when a large tranche falls due — a real risk in Nepal, where domestic bank lending rates have swung meaningfully across credit cycles over the past decade.

This leads directly to the DSRA and covenant question, which is the most common reason a profitable-looking hydropower company still pays a disappointingly small dividend. Lenders to a hydropower project almost always require the company to maintain a Debt Service Reserve Account — cash set aside, often equal to the next one or two quarters' worth of principal and interest payments — before any dividend can be distributed to shareholders. On top of that, loan covenants frequently impose a minimum Debt Service Coverage Ratio (DSCR, cash available for debt service divided by debt service due) that must be met, sometimes with a further "lock-up" test, before the company is permitted to upstream cash as dividends at all. A company can report solid net profit under accrual accounting and still be barred from paying much of a dividend that year because its DSRA is being topped up or its DSCR covenant is running close to the minimum.

Put together, the promoter-and-balance-sheet checklist for a NEPSE hydropower stock looks like this: has this promoter delivered before, what fraction of construction is complete (for pipeline names) and how has guidance drifted, what does the debt maturity ladder look like over the next five years, and is there any disclosed DSRA or covenant constraint currently limiting distributable cash. None of these appear as a single ratio on a stock screener — they require actually reading the report.

Lesson 44.6 — Valuing a Hydropower Stock: DCF Over the PPA Life, and Avoiding the P/E Trap

Chapters 42 and 43 built the machinery for a full discounted cash flow (DCF) model of a hydropower project. This final lesson is about applying that machinery, in a somewhat simplified form, as a public-market investor rather than as a project financier, and about the specific valuation traps this sector produces more reliably than almost any other on NEPSE.

The starting point is that a hydropower company's cash-generating asset has a known, finite life in a way most other businesses do not: the PPA has a defined end date, after which future cash flows are genuinely uncertain (a new PPA might be signed at a different tariff, or the plant might sell into whatever market exists at that time). This makes hydropower one of the cleanest sectors on NEPSE for a proper multi-stage DCF: project out annual free cash flow to equity for the remaining PPA term, explicitly modelling the seasonality from Lesson 44.2, the royalty step-up from Lesson 44.3, the tax-holiday expiry, and the debt amortisation and refinancing schedule, discount those cash flows at a cost of equity that reflects Nepal's risk-free rate plus an appropriate equity risk premium, and then attach a deliberately conservative (or even zero) terminal value beyond the PPA's expiry, since what happens after that date is genuinely unknowable today. This is meaningfully different from valuing, say, a bank or a manufacturer, where a growing perpetuity terminal value usually does most of the work in the valuation — in hydropower, the terminal value should do very little of the work, and the explicit forecast period should do almost all of it.

The most dangerous shortcut investors take instead of this proper DCF is relying on a simple trailing price-to-earnings (P/E) ratio, and this sector produces a particularly sharp version of the "P/E trap" flagged in earlier chapters of this book. Because hydropower earnings are so sensitive to a single year's hydrology, a company can post an unusually strong year (an especially wet monsoon, a full year without any equipment downtime, an arrears settlement from NEA boosting realised tariff) and show up on a screener with a deceptively low trailing P/E — looking "cheap" purely because the denominator (that one year's EPS) was inflated by conditions that will not repeat. The reverse trap also happens: a company coming off a genuine drought year or a maintenance shutdown can show an inflated trailing P/E that makes it look expensive, right when the underlying asset is actually being bought at its cheapest, most washed-out point in the cycle. The correction for both versions of the trap is the same: normalise earnings across at least a three-to-five-year window that spans both wet and dry hydrological cycles before computing any P/E-style multiple, rather than trusting the most recent twelve months in isolation.

EV/EBITDA (enterprise value divided by earnings before interest, tax, depreciation and amortisation) is generally a more useful cross-sectional comparison tool in this sector than P/E, for a simple reason: it strips out the effect of each company's different capital structure (some hydropower companies carry far more leverage relative to their asset base than others, which distorts P/E through the interest-expense line) and it also strips out the differing tax-holiday positions discussed in Lesson 44.4. Comparing EV/EBITDA across companies of a similar vintage, similar remaining PPA term, and similar ROR/storage mix is a reasonable way to spot which names the market is pricing more or less generously relative to peers — though even here, the "similar remaining PPA term" qualifier matters enormously, because a plant three years from PPA expiry and a plant twenty-five years from PPA expiry should never trade at the same EV/EBITDA multiple, all else equal, since the buyer of the former is purchasing a much shorter cash-flow stream.

Dividend yield is the metric most retail investors reach for first in this sector, since hydropower stocks are widely (and often correctly) viewed as income plays. But Lesson 44.5 already showed why a single year's dividend can be an unreliable guide — DSRA top-ups and covenant lock-ups can suppress a dividend in a year when underlying cash generation was actually fine, and conversely a company can occasionally pay out an unsustainably large dividend by drawing down reserves ahead of a known heavy capital expenditure or debt repayment year. The sustainability check is to look at the multi-year average payout relative to free cash flow to equity (not net profit), track whether the DSRA balance and DSCR covenant headroom are stable or shrinking, and ask whether the company has any pipeline expansion project that is likely to divert cash away from dividends in the near future regardless of how strong current-year generation looks.

Table: A Snapshot Comparison Across Selected NEPSE-Listed Hydropower Companies

The table below is illustrative rather than a live data feed — installed capacities are stable public facts, but PPA-remaining-term, royalty-band position, and valuation multiples move every year and must be re-checked against each company's current annual report and market price before any real decision. Use it as a template for the kind of comparison sheet you should build yourself for the specific names you are considering.

A second short table is worth keeping alongside the first: a simple royalty-and-tax staging table, to remind yourself which margin headwinds are structural and scheduled rather than surprises.