Hydropower Project Registration In Nepal: Notes For Developers And Lenders (2026)

Nepal’s hydropower sector still runs on a licensing regime built around the Electricity Act, 2049 (1992) and the Companies Act, 2063 (2006), with a cluster of sector-specific policies layered on top over three decades. The Ministry of Energy, Water Resources and Irrigation (MoEWRI) retains policy oversight and licensing authority. The Department of Electricity Development (DoED) issues survey and generation licences for certain threshold. The Ministry of Forests and Environment approves the IEE or EIA. The Electricity Regulatory Commission (ERC), established under the Electricity Regulatory Commission Act, 2017, now sets tariff and technical standards. Nepal Electricity Authority (NEA) remains, in practice, the only entity a project company will ever sell power to.

A long-pending Electricity Bill, 2080 intended to replace the 1992 Act, extending licence tenures, restructuring NEA, and formalising electricity trading, remains before Parliament, and party manifestoes were still promising its passage as recently as February 2026. Until it is enacted, the current framework, and the practice built around it, is what developers and financiers are actually negotiating against.

The clearest trend of the last eighteen months is the sector’s tilt toward storage and reservoir-based generation. Run-of-river tariffs have been static for years, while the ERC has now been given authority to set differentiated rates for reservoir projects, capping PPA rates at NPR 14.80/kWh in winter and NPR 8.45/kWh in monsoon for projects up to 100 MW, with cost-based pricing above that threshold, replacing NEA’s earlier flat reservoir rate. IBN has correspondingly pushed forward a wave of reservoir and peaking-capacity projects, including Arun-3, the newly licensed 669 MW Lower Arun, the 750 MW West Seti survey extension, and the 1,200 MW Budhi Gandaki PPP, while smaller RoR pipelines queue behind an oversubscribed IPO and PPA backlog. For financiers, this shift changes the risk conversation. Storage assets carry materially higher capex and construction risk, but escape some of the seasonal cash-flow volatility that has made RoR debt service schedules difficult to underwrite in the dry season.

The registration and licensing sequence, in outline

The mechanics of getting a hydropower company registered and licensed are well documented elsewhere, so we outline them only to set up the bankability discussion that follows.

1. Name reservation and incorporation at the Office of the Company Registrar under the Companies Act, 2063, as a private or public limited company, with objects clauses specific to power generation.
2. PAN registration with the Inland Revenue Department.
3. Survey licence application to DoED, with feasibility documentation. For projects that will exceed the IBN thresholds, parallel engagement with IBN typically begins here rather than after generation licensing.
4. Environmental clearance, either an IEE or EIA depending on capacity and location, from the Ministry of Forests and Environment.
5. Generation licence from DoED or, above threshold, IBN, which fixes the licence term. The Electricity Act still caps this at 50 years, though the Hydropower Development Policy 2058 sets practical limits closer to 35 years in most licences actually issued.
6. PPA negotiation with NEA, which in our experience is where the real project timeline sits. Twelve to twenty-four months is a realistic range even for straightforward RoR deals, and considerably longer where a project sits above 25 MW or falls into one of NEA’s periodic moratoria on new PPA intake.
7. Financial closure, land acquisition, and construction, running in parallel with the local-share and, eventually, IPO obligations discussed below.

NEA’s role deserves emphasis on its own terms, because most other bankability issues in this article eventually route back through it. NEA is not merely the counterparty on the PPA. It is the sole offtaker, the entity that determines dispatch, the body that administers the take-or-pay mechanics, and, in practice, the party whose creditworthiness and payment discipline the entire debt package is underwritten against.

Bankability is always tied to PPA and NEA

Tariff Ceiling.
NEA’s standard PPA, and now the ERC’s tariff-setting practice for larger and reservoir projects, builds in a downward tariff revision if the project’s return exceeds a regulatory ceiling. That ceiling has consistently been set at a 17% internal rate of return or return on equity, not the 18% figure sometimes quoted informally in the market. Exceed the ceiling, and the power purchase rate is revised down rather than the excess being retained by the sponsor. This is a genuinely bankable mechanism because it is transparent and rule-based, but it means lenders’ financial models need to be built around the ceiling from day one. Over-optimistic base-case returns do not survive contact with NEA’s revision right, and refinancing upside that assumes a higher realised return is not something we would advise a lender to size debt against.

PPAs are not sacrosanct
The PPA is drafted as take-or-pay, which in theory should insulate the developer’s revenue from NEA’s own dispatch decisions. In practice, we have repeatedly seen the gap between that theoretical protection and its practical value. Where NEA does not dispatch, or curtails, for reasons not clearly attributable to NEA (grid congestion, system balancing, or simply a decision not to draw), developers are left without a clean contractual remedy, because the PPA’s compensation mechanics for non-dispatch are narrower than a lender’s term sheet will usually assume at signing. Hydrological risk compounds this. Even under a take-or-pay structure, the developer bears the risk that the river simply does not deliver the contracted energy in a given season, and NEA’s payment obligation is calibrated to actual, not contracted, generation in ways that shift real risk back onto the project company despite the take-or-pay label.

Non-payment and the limits of termination as a remedy.
Because NEA is the only offtaker in the market, termination for NEA’s payment default is, as a practical matter, not a remedy lenders can rely on. There is nowhere else to sell the power, and termination destroys the asset’s only revenue stream rather than preserving it. We would flag this to any financier treating a standard termination-for-default clause as adequate downside protection. The real protection has to come from elsewhere in the security and support package, not from the PPA’s own termination mechanics.

Open access and the transmission bottleneck.
The ERC’s Open Access Guideline is the first real move toward allowing licensed traders to use NEA’s grid without a PPA with NEA itself. In time this could give developers an alternative to single-buyer dependence. As of now, private power-trading licences and the associated commercial arrangements are not yet standard practice, and, more fundamentally, the transmission infrastructure needed to actually evacuate power to a genuinely open, cross-border, or third-party market remains the binding constraint in most river basins. Open access is worth building into a longer-horizon financing narrative. It is not yet something we would underwrite around for a project reaching financial close in the next twelve months.

Bargaining power and NEA backstop resistance.

NEA’s negotiating position reflects its monopsony status. In our experience this shows up most sharply in two places: NEA’s consistent resistance to providing meaningful backstop or payment-guarantee support beyond the PPA itself, in contrast to sovereign-backed guarantee structures more commonly seen in comparable South Asian markets, and the asymmetry of amendment leverage once a PPA is signed, since NEA’s standardised templates leave comparatively little room to renegotiate core risk allocation later even where market conditions or project-specific facts would justify it. Sponsors with genuine negotiating leverage, whether from scale, strategic project location, or IBN-route status, have secured somewhat better terms on these points than the DoED-route standard template allows. Smaller RoR developers generally have not.

Land, lease and the 50% collateral ceiling

Enforcing Land Mortgage

This is the area where Nepal’s legal infrastructure diverges most from what international lenders expect. The Secured Transaction Act, 2063 (2006) governs security interests in movable and intangible property, and requires registration at the Secured Transactions Registry Office to be enforceable against third parties, a filing-based priority system broadly comparable in structure to Article 9 of the US UCC. Where it genuinely helps lenders is in giving reasonably clear, self-executing enforcement mechanics over plant, equipment, receivables and similar movable collateral once properly registered. Where it does not help is immovable property: Nepal has no mechanism allowing a secured creditor to take possession of land on default without going through the court system, so mortgage enforcement still runs through a District Court decree and a court-supervised auction under the Muluki Civil Code, 2074. For a hydropower project, where the powerhouse, penstock alignment, and dam structure all sit on or attach to land, this means a meaningful part of the effective security package still depends on judicial enforcement, with the delays that implies, even where a comprehensive security interest has been properly filed.

The 50% land-mortgage ceiling

A point every financier should have on their checklist before assuming land will simply be available as collateral is that the Industrial Enterprises Act, 2076 (2020) restricts an industry from mortgaging more than 50% of its total land to a bank or financial institution to secure a loan. This is not a dormant provision. It was expressly revisited in the Act to Amend Some Nepal Acts Relating to Improving Economic and Business Environment and Enhancing Investment, 2081 (2025), which added a specific exemption from the 50% ceiling for two situations that describe most hydropower financings directly: loans secured for project financing, and projects developed under an agreement with the government or a government agency that will be transferred to that government or agency at the end of a specified period, which is precisely how a BOOT-model generation licence works.

Critically, the amendment also confirms that using the land as collateral under this exemption does not impose any loan liability on the government or the agency itself. For a properly structured hydropower project financing, this exemption should in principle unlock full mortgage cover over project land rather than leaving lenders capped at half. In our experience, though, this needs to be confirmed and documented at the licensing and loan-approval stage rather than assumed, because the exemption is conditional on the financing being correctly characterised and the underlying BOOT or PDA-style government agreement being in place and referenced in the security documents.

Sponsor commitment Still Key Security
Where a project falls outside the exemption discussed earlier, or where a lender simply wants more comfort than the land package alone can offer, the practical answer we see developers turn to is enhanced sponsor-side support rather than a larger land mortgage. This typically takes the form of a sponsor completion guarantee or bank guarantee (BG) covering the construction period, a cash-deficiency or cost-overrun undertaking from the sponsor group, or additional equity commitment letters backed by a parent-company or bank guarantee rather than land. Lenders structuring around the 50% ceiling, or around the practical delays in immovable-property enforcement generally, should treat sponsor support instruments as a substitute for missing collateral value, not merely as a comfort layer on top of an already-complete security package.

Land Registration fees is Not Cheap
Mortgage registration at the Land Revenue Office is not a flat, uniform cost. Foreign lenders have historically been charged a materially higher registration fee, commonly cited at around 1% of the loan amount or secured property value, while domestic licensed banks and financial institutions register mortgages against a comparatively nominal, largely fixed fee schedule. Fee schedules at Land Revenue Offices can also vary at the provincial level and determined by provincial fiscal legislation, so the actual cost should be confirmed against the specific office where the project land sits rather than assumed from a national average.

On a syndicated facility with both foreign and domestic lenders, it directly affects how the security trustee or security agent structures the mortgage, since registering the full facility amount in the name of a foreign-heavy syndicate can be materially more expensive than structuring the domestic tranche separately or channelling the registered mortgage through a domestic security agent or a domestic lender of record. We would treat the fee structure as something to check and price into the security package at term sheet stage, not as a closing-mechanics afterthought, and would confirm the applicable fee suits every lender in the syndicate rather than only the lead arranger.

Local shares: Always a Sensitive Issue

Nepali hydropower companies are required to reserve a tranche of equity, typically around 10% of issued capital, for project-affected local communities, on top of the standard promoter and public IPO split SEBON otherwise applies. Beni Hydropower’s IPO earlier this year is a useful current example of how this is actually structured in practice: 10% of issued capital reserved for project-affected residents of the relevant district, with the allocation weighted by proximity to the project, alongside a separate tranche for Nepalis in foreign employment and the general public. Developers commonly finance projects with roughly 70% bank debt and the remaining 30% raised through public share issuance, including the local tranche, which is precisely why the equity side of that structure matters so much to lenders underwriting the debt.

This is where 2026 has produced a live and material bankability risk that did not exist in the same form a few years ago. SEBON’s IPO approval process for hydropower companies has been running through a prolonged backlog, with close to a hundred companies awaiting approval as of May 2026 and hydropower developers among the worst affected, because financing plans built around expected IPO proceeds cannot close when the IPO itself is stuck in the queue. Lenders who have priced a facility assuming timely local-share and public-tranche mobilisation should treat that assumption as genuinely at risk under current SEBON processing timelines, not as a formality that will resolve itself before drawdown.

Pricing of the local-share tranche is also an active dispute in 2026. The Independent Power Producers’ Association has been pressing, as recently as this month, for local shares to be issued strictly at face value of NPR 100 rather than at a premium some developers have proposed, and Parliament’s Finance Committee has weighed in on the same question. This is not a new issue in substance. Local-share disputes have stalled or destabilised projects before, most notably the long-running Chilime local-share litigation, where affected communities pursued their claimed equity entitlement through years of concurrent litigation and protest while the project was operating. In our experience, developers who treat the local-share tranche as a community-relations and governance issue from the outset, with clear beneficiary identification, transparent allocation criteria, and early engagement with affected municipalities, spend materially less time and legal cost on it later than developers who treat it as a late-stage SEBON compliance filing.

Tax benefits is always date-sensitive

The Industrial Enterprises Act, 2076 (2020) and Income Tax Act, 2058 incentive package for hydropower remains one of the more genuinely attractive features of the Nepali regime, and it is worth stating precisely because the deadlines move with each budget.

• General hydropower, solar, wind and bio-substance projects: 100% income tax exemption for the first 10 years of commercial operation, and a 50% exemption for the following 5 years, available where commercial production commences by the end of Chaitra 2084 (mid-April 2028), per the FY 2082/83 budget.
• Reservoir and semi-reservoir projects above 40 MW, including lower-cascade projects operated in tandem with them: 100% exemption for the first 15 years, and 50% for the following 6 years, available where financial closure is achieved by the end of Chaitra 2085 (mid-April 2029).
• Customs concessions: a reduced 1% customs rate applies to construction materials, machinery, equipment, spare parts and penstock imported for hydropower construction under the current master-list arrangements.

These windows have moved before. The reservoir deadline was previously Chaitra 2082, then Chaitra 2083, and is now Chaitra 2085. Financiers should build deadline risk into the base case rather than assume the currently legislated date survives to the sponsor’s actual financial close, and should confirm the applicable window against the licence-issuance date, since the Act preserves the incentive terms in force at the time a given licence was granted.

Mandatory handover, the BOOT model, and a cautionary lesson from outside the sector

Nepali generation licences are issued on a Build-Own-Operate-Transfer basis. At the end of the licence term, the asset reverts to the state, typically without compensation, a structure every project company and its lenders sign up to from day one and price into their return expectations. That much is well understood.

What deserves fresh attention, and this is genuinely new context for anyone advising on hydropower bankability in 2026, is the Smart Telecom case, which has dominated Nepali financial and legal commentary through the first half of this year. Smart Telecom’s telecom licence was revoked in 2023 for unpaid dues. The Nepal Telecommunications Authority then asserted that the company’s assets came under state ownership by operation of the licence-cancellation provisions, while a secured commercial bank separately pursued collateral enforcement and an asset auction based on its registered charge.

The two claims collided in the courts, in Parliament, and very publicly in the press, with senior lawyers on both sides invoking conflicting precedent on whether a first-charge secured creditor’s rights survive a licence-based state ownership claim, and the dispute has since expanded into a criminal case involving bank officials and a NPR 96 billion civil claim. The case is telecom, not hydropower, and we would caution against overreading it. But the underlying tension it exposes is directly relevant to any BOOT-model infrastructure sector i.e. a regulator’s licence-based claim to project assets can, in a live and unresolved dispute, be asserted against a secured lender’s collateral rights, and Nepal’s courts have not yet settled which takes priority for BOOT projects. For hydropower lenders, whose downside protection typically assumes that project assets remain available as collateral for the life of the licence and are cleanly released to the state only at the scheduled handover date, this is worth active monitoring rather than filing away as a telecom-sector curiosity. We are watching how this resolves, and expect it to inform how the next generation of hydropower security documents are drafted.

Direct agreements are not Default

A direct agreement, giving lenders step-in rights, project-document access, and a tripartite relationship with the government and the developer, is standard international project finance practice, and Nepal has now delivered it on more than one route. On the IBN side, the Direct Agreement executed for Upper Trishuli-1 project with multilateral financiers  is the clearest recent example, explicitly framed by IBN itself as aligning with global project finance norms. What we would still flag to developers and financiers is that this remains a negotiated, deal-specific outcome rather than a standard term available off the shelf. Where a direct agreement matters to a financing structure, in our experience it needs to be raised, negotiated, and secured as an explicit deliverable early in the government-relations track, with the government counterparty and the specific project agreement identified from the outset, rather than assumed as a default feature of the Nepali PPA and licensing framework.

In our experience: putting the pieces together

None of these issues is individually disqualifying. Nepal has financed and commissioned well over a hundred hydropower IPPs, including several genuinely large IBN-route and PDA-route projects with international lender syndicates. What distinguishes a bankable structure from a stalled one, in the transactions we have advised on, is sequencing. Resolving land and local-share issues before they become financing-timeline problems, sizing debt against the 17% regulatory return ceiling rather than an unconstrained base case, confirming whether the project genuinely qualifies for the 50% land-mortgage exemption and building sponsor guarantee support around any shortfall, pricing mortgage registration correctly across a mixed foreign and domestic syndicate, and raising direct-agreement and backstop-support asks early enough in the government-relations process that they can actually be negotiated rather than requested as an afterthought at financial close.

For a fuller treatment of project company structuring, security documentation, and the government-approval regime  for Nepali infrastructure financings generally, see our companion project finance guide: Project Finance in Nepal.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.