NEA Hydropower PPA & Tariff Rates: RoR, PRoR, Reservoir (Wet vs Dry)

A Power Purchase Agreement (PPA) is the long-term contract under which the Nepal Electricity Authority (NEA) — the state-owned utility that dominates Nepal's power sector — agrees to buy the electricity produced by an independent power producer (IPP). For most of Nepal's hydropower build-out, NEA has offered a fixed, published buy-back rate rather than negotiating each deal individually. This 'feed-in tariff' style regime gives developers and their lenders a predictable revenue stream over the 25 to 35 year life of the contract, which is essential for raising bank financing on a project.

The central feature of NEA's rate structure is that the price per unit (per kilowatt-hour, or unit of energy) is not flat. It varies along two axes. The first is the type of project: a plain run-of-river (RoR) plant, a peaking run-of-river (PRoR) plant that can store a few hours of water to generate at high demand, or a reservoir (storage) plant that can hold water across seasons. The second axis is the season: Nepal splits the year into a 'wet' monsoon season and a 'dry' winter season, and pays a much higher rate in the dry season when river flows and national supply are lowest.

Because Nepal's rivers swell during the monsoon and shrink in winter, dry-season energy is far more valuable to the grid than surplus monsoon energy. NEA's tariff structure deliberately rewards projects that can deliver firm power in the dry months. This is why storage and peaking projects command premium rates, and why the PPA specifies minimum dry-season energy obligations rather than simply paying for whatever a plant happens to produce.

Standard run-of-river projects — plants with little or no storage that generate roughly in proportion to the river's natural flow — have long been bought at the sector's baseline rate. Under the rates that governed most PPAs signed after 2011, NEA pays approximately Rs 4.80 per unit for energy delivered in the wet season and Rs 8.40 per unit in the dry season. The dry-season rate is nearly double the wet-season rate, reflecting the scarcity value of winter generation.

The seasons are defined by the Nepali calendar rather than fixed Gregorian dates. Broadly, the wet (monsoon) season runs from around mid-April to mid-December and the dry season from mid-December to mid-April, with the exact boundaries set out in the PPA. Because most RoR plants produce the bulk of their annual energy during the monsoon, when rivers are full, a large share of an RoR developer's units are sold at the lower wet-season rate — a structural reason why storage projects are more attractive on a per-unit basis.

For projects with an installed capacity below 100 MW, NEA has offered a 3% simple escalation on the base energy rate for the first eight years of commercial operation. This partially offsets inflation over the early years of the contract but does not continue for the full term; after the escalation window, the rate is effectively fixed for the remainder of the 25 to 35 year PPA. Escalation is a headline point for finance students and investors because it directly affects the projected internal rate of return.

A peaking run-of-river (PRoR) project has a small pondage that lets it hold back water and concentrate generation into the daily peak-demand hours. Because this delivers more valuable, dispatchable power, NEA rewards PRoR plants with a higher dry-season rate than plain RoR. Under the tariff NEA adopted for PRoR PPAs from 27 April 2017 (Baisakh 2074 BS), the dry-season rate rises with the number of hours the plant can run at full capacity: about Rs 8.50 per unit for one to two hours, Rs 8.80 for two to three hours, Rs 9.40 for three to four hours, and up to Rs 10.55 per unit for four to six hours of peaking. The wet-season rate remains around Rs 4.80 per unit.

These premium rates come attached to a firm obligation. To qualify, a PRoR project must be able to deliver peaking power at rated capacity for a defined block of hours, and it must supply a minimum share of its annual energy during the dry season — a threshold NEA has set at around 30% (measured across the mid-November to mid-May window in the 2017 revision, up from a weaker 15% requirement before). The dry-season energy rule is the mechanism that turns a headline rate into a real commitment to winter supply.

There is also a compensation clause protecting NEA if a plant underperforms in winter. If a project that committed to at least 30% dry-season energy actually delivers less than 30% once in operation, the excess energy it supplied beyond the level implied by that 30% is treated as an adjustment (compensation) in the following year's monthly bills. In effect, a developer cannot bank the premium dry-season pricing while quietly dumping most of its output in the monsoon.

Reservoir or storage projects, which impound water behind a dam and can shift energy across months, sit at the top of NEA's rate ladder because they provide the firm, seasonally balanced power the grid most needs. Under the earlier structure, storage projects were bought at around Rs 7.10 per unit in the wet season and Rs 12.40 per unit in the dry season — comfortably above both RoR and PRoR rates.

In February 2026 (Falgun 2082 BS), NEA moved to a dedicated framework, the 'Directive on Electricity Purchase and Sale of Reservoir-Based Power Plants, 2026', to further support storage development. For reservoir projects up to 100 MW it set a capped maximum of about Rs 8.45 per unit in the monsoon and Rs 14.80 per unit in winter, up from the previous uniform Rs 7.10 (monsoon) and Rs 12.40 (winter). For projects above 100 MW, the rate is determined case by case on the basis of actual project cost rather than a fixed cap, with additional guardrails such as limits on capital-cost increases and on how equity is valued.

This differentiated approach signals a policy priority: Nepal is heavily RoR-dependent and floods the market with cheap monsoon energy while facing winter shortfalls, so the tariff is being tilted to make expensive storage projects bankable. Reservoir PPAs remain the exception rather than the norm, and their terms are often negotiated in more detail than the standardised RoR and PRoR rate sheets.

Rupee revenue is a problem for projects financed with foreign loans, because the Nepali rupee tends to depreciate against the US dollar over a 25 to 35 year term, eroding the hard-currency value of the developer's earnings. To attract foreign investment into big projects, NEA and the government have offered dollar-denominated PPA terms for qualifying schemes. Under this arrangement, NEA endorsed paying foreign-investment projects in US dollars for roughly the first ten years of commercial operation, or until the foreign loan is repaid, whichever comes first, after which payment reverts to rupees.

Where rates have been quoted in dollar terms, indicative feed-in tariffs have been in the range of about 3.6 US cents per unit for run-of-river, 3.6 to 6.3 US cents for peaking run-of-river, and around 9 US cents per unit for storage projects — figures broadly consistent with the rupee rates once converted. Dollar PPAs shift exchange-rate risk from the developer toward NEA and, ultimately, the state, which is why they are restricted to larger, foreign-financed projects rather than offered universally.

Landmark reservoir and large-scale schemes — such as the multipurpose storage projects developed with international financing — have used bespoke, negotiated PPA and tariff arrangements rather than the off-the-shelf rate sheet. For any specific project, the governing figures are those written into that project's signed agreement, so the standard published rates should be read as the baseline framework, not the final word for every plant.

Nepal is moving away from a single fixed buy-back price toward competition. The Electricity Regulatory Commission (ERC), the independent regulator established on 9 May 2019 under the Electricity Regulatory Commission Act, 2017, now approves tariffs, monitors compliance, and arbitrates disputes in the power sector. For projects above 100 MW, the ERC — rather than a flat NEA rate — has determined the purchase rate, and it has attached conditions such as a downward revision if a project's return on equity exceeds 17%. This regulatory layer is steadily reshaping how PPA prices are set.

A bill prepared by the Ministry of Energy, Water Resources and Irrigation, floated in 2023, proposed making competitive bidding mandatory for buying electricity for the domestic market, so that developers offering the lowest price would win PPAs first rather than deals being signed on a first-come, first-served basis at a fixed rate. The model borrows directly from solar power, where NEA already procures energy through competitive tenders with a price cap (set at around Rs 5.94 per unit). If enacted broadly for hydropower, this would gradually replace the RoR, PRoR and reservoir rate sheets described above with market-discovered prices.

For developers, investors and finance students, the practical takeaway is that Nepal's hydropower tariff regime is in transition. The fixed seasonal rates remain the reference point for the large stock of existing and recently signed PPAs, but new and larger projects increasingly face ERC-set or competitively bid prices. Anyone modelling a specific plant should confirm which regime applies to it and read the actual signed PPA, because that document — not the published rate table — controls the cash flows.