Nepal possesses an estimated economically exploitable hydropower potential of approximately 43,000 MW. However, realizing this potential is critically dependent on the construction of high-voltage transmission corridors capable of evacuating power from remote generation sites to domestic load centres and cross-border export points. As of 2025, Nepal’s generation capacity continues to grow at a pace that significantly outstrips the expansion of its transmission network, creating systemic bottlenecks that threaten to strand billions of dollars of clean energy investment.
Recognising the scale of the investment required – estimated at approximately USD 7.4 billion for 11,700 circuit kilometres of new transmission lines and 33,000 MVA of substation capacity under the Energy Development Roadmap to 2035 – the Government of Nepal has adopted the Public-Private Partnership (PPP) modality for strategic transmission projects. Rastriya Prasaran Grid Company Limited (RPGCL), as the designated national transmission grid company, is leading the development of several flagship corridors under this framework.
The West Seti 400 kV Transmission Line Project, designed to evacuate approximately 2,500 MW from the far-western Sudurpaschim Province, represents one of the most significant test cases for the PPP transmission model in Nepal. With an estimated cost of USD 204.27 million and a planned route spanning 213 kilometres of challenging Himalayan terrain, the project embodies both the promise and the complexity of infrastructure-led energy development.
Section A: Project Overview and Status
Q1. What is the West Seti 400 kV Transmission Line Project?
The West Seti 400 kV Transmission Line Project is a strategic high-voltage transmission corridor planned across 213 kilometres in Sudurpaschim Province. It is designed to evacuate approximately 2,500 MW of hydropower from multiple generation projects in the West Seti basin, including the West Seti Hydroelectric Project. RPGCL is developing this project under a PPP framework through a Special Purpose Vehicle (SPV) with mixed public-private equity participation. The total estimated project cost is approximately USD 204.27 million, with a target completion by fiscal year 2088/89 BS.
Q2. What is the current status of the project?
As of the latest available information, the project has completed its survey and environmental study phase. Key milestones achieved include:
- Survey Licenses: The Department of Electricity Development (DoED) issued survey licenses for all three segments: West Seti–New Attariya (2077/10/06 BS), West Seti (Banlek)–Dodhara (2079/07/20 BS), and Bajhang–Banlek (2079/12/20 BS).
- Environmental Compliance: The Initial Environmental Examination (IEE) report was formally approved by the DoED on Magh 20, 2081 BS.
- Corporate Structuring: RPGCL executed non-binding Memorandums of Understanding (MoUs) with several Independent Power Producers (HIDCL, CJCL, CSHC, and SEL) on 2082/04/05 BS and published a public Expression of Interest (EOI) notice on 2082/05/23 BS to onboard additional equity investors for the SPV.
The project is currently classified as “Study Completed” and is in the process of transitioning to the SPV formation and financial structuring phase.
Q3. What are the major transmission line projects being undertaken by RPGCL?
RPGCL is overseeing a portfolio of 11 major transmission line projects at various stages of development. These projects collectively represent approximately USD 865 million in estimated investment – roughly 12% of Nepal’s total transmission build-out requirement to 2035. The following table summarises the key projects:
| Project | Status | Voltage | Length | Capacity | Target | Est. Cost (USD) |
| Karnali Corridor | Under Construction | 400 kV | 120 km | 2,500 MW | 2085/86 | 200 M |
| West Seti Corridor | Study Completed | 400 kV | 213 km | 2,500 MW | 2088/89 | 204.27 M |
| Bheri Corridor | Study Completed | 400 kV | 93 km | 2,400 MW | 2086/87 | 160 M |
| Humla–Phukot | Under Study | 400 kV | 85 km | 2,250 MW | 2088/89 | 138 M |
| Haitar–Sitalpati | PPP | 400 kV | 35 km | 2,260 MW | 2087/88 | 69.65 M |
| Lambagar–Barhabise | PPP | 220 kV | 43 km | 1,240 MW | 2087/88 | 28.78 M |
| Tamor–Dhungesanghu | PPP | 220 kV | 32 km | 700 MW | 2087/88 | 21.44 M |
| Mewa–Change | Under Construction | 132 kV | 20 km | 154 MW | 2083/84 | 10.3 M |
| Kerabari–New Marsyangdi | Under Construction | 132 kV | 32 km | 120 MW | 2083/84 | 12.8 M |
Q4. What are the three major hydropower evacuation corridors these projects form?
These projects are not ad hoc grid expansions. They form three strategic hydropower evacuation corridors designed to unlock Nepal’s largest untapped generation basins:
- Karnali Basin Corridor: Comprising the Karnali Corridor, Bheri Corridor, and Humla–Phukot lines, this cluster is designed to unlock an estimated 7,000–8,000 MW of hydropower potential from the Karnali river system.
- Arun–Tamor Basin Corridor: Comprising the Haitar–Sitalpati, Tamor–Dhungesanghu, Sitalpati–Dhungesanghu, and Mewa lines, this corridor supports the Upper Arun, Lower Arun, Kimathanka Arun, and Tamor cascade projects.
- Far-West Seti Basin Corridor: Comprising the West Seti Corridor and Sanfebagar regional lines, this corridor enables the West Seti and Chainpur Seti hydropower projects.
Approximate investment metrics: USD 67,000 per MW of evacuation capacity; USD 1.12 million per kilometre of transmission line – broadly consistent with high-voltage mountainous infrastructure in Himalayan terrain.
Section B: Regulatory and Legal Challenges
Q5. What regulatory uncertainties does the proposed Electricity Bill 2080 introduce?
The Electricity Bill 2080 BS, currently under parliamentary consideration, proposes several structural changes that introduce significant policy risk for transmission PPP projects:
- Reduced License Duration: The maximum transmission license term is reduced from up to 50 years (under the Electricity Act 1992) to 25 years. However, generation-linked transmission licenses may match the duration of the associated generation license.
- Transmission Royalty: A new 5% royalty on transmission revenue (wheeling charges) is introduced for the first time, adding a direct cost burden to transmission operators.
- Mandatory Open Access: The Bill mandates non-discriminatory grid access for all generation, trade, and distribution licensees, potentially altering tariff structures and revenue predictability.
- Mandatory Asset Transfer: Upon license expiry, all transmission infrastructure must be handed over to the government free of cost and in running condition, confirming a Build-Own-Operate-Transfer (BOOT) structure.
- Strict Unbundling: A single entity can no longer hold generation, transmission, and distribution licenses simultaneously. Existing multi-function entities must unbundle within five years of the Bill’s enactment.
These provisions collectively increase policy risk and investor uncertainty, particularly for long-gestation infrastructure projects that depend on regulatory stability over multi-decade timeframes.
Q6. How does the proposed Bill compare to the existing Electricity Act 1992?
The following table provides a side-by-side comparison of the key provisions:
| Provision | Electricity Act 1992 | Proposed Bill 2080 |
| License Duration | Up to 50 years | Up to 25 years (standard); generation-linked TL may match generation license |
| Unbundling | Single entity may hold generation, transmission, and distribution licenses | Strict functional unbundling; existing entities must separate within 5 years |
| Open Access | No explicit provisions | Mandatory non-discriminatory grid access with ERC-determined wheeling charges |
| Right of Way | General land acquisition provisions | Explicit ROW based on voltage capacity; mandatory compensation for ROW land |
| Grid Operation | Government designates national grid | Dedicated government entity to operate grid; National Load Dispatch Centre established |
| Asset Transfer | Transfer for >50% foreign-invested lines post-license | Mandatory free transfer of all transmission infrastructure upon license expiry |
| Royalty | Capacity-based royalty for generation | 5% royalty on transmission wheeling revenue |
| Infrastructure Sharing | Not addressed | Licensees may share towers and poles with telecom and other providers |
Q7. What is the current status of wheeling charge determination in Nepal?
The absence of a detailed and standardised methodology by the Electricity Regulatory Commission (ERC) for determining wheeling charges and transmission tariffs represents one of the most significant regulatory gaps for PPP transmission projects. This uncertainty directly undermines the revenue model and bankability of projects like the West Seti corridor.
The following specific challenges have been identified:
- Multiple Competing Methodologies: Several tariff approaches coexist without harmonisation, including the Regulated Asset Base / Annual Revenue Requirement (ARR) model, the Postage Stamp Tariff, and project-specific Transmission Service Charges (TSC).
- Discretionary Tariff Resets: Tariff adjustments depend on periodic regulatory review rather than automatic, formula-based escalation mechanisms, creating unpredictability for long-term financial planning.
- Cost Disallowance Risk: The ERC retains the authority to disallow costs it deems imprudent, introducing the possibility that legitimate project expenditures may not be fully recovered through the tariff.
- Cross-Subsidisation Through Postage Stamp Tariffs: Socialised tariffs may systematically under-recover the higher costs of remote, mountainous 400 kV lines, effectively subsidising urban and low-cost corridors at the expense of projects like West Seti.
- Lender Concerns: The lack of long-term tariff certainty is a fundamental obstacle to achieving financial closure, as commercial lenders require predictable revenue streams over the loan tenor.
Section C: SPV Structure and Investment Modality
Q8. What is the planned equity architecture for the West Seti SPV?
The RPGCL Board of Directors resolved (158th meeting, 2082/04/11 BS) to develop the project through a Special Purpose Vehicle (SPV) with mixed public-private equity participation. The target equity architecture is structured as follows:
| Category | Share | Details |
| Public Control | 51% | RPGCL: minimum 26% (negative control over special resolutions). Government shareholders: 25% (various ministries and entities holding existing RPGCL equity). |
| Private & Public Investors | 49% | IPPs via MoUs (HIDCL, CJCL, CSHC, SEL). Third-party investors via EOI/RFP. Project-affected communities: statutory 10%. General public and employees: 10–49% (public), up to 5% (employees), 10% of IPO pool (migrant workers). |
Q9. What is the challenge with community share participation?
Article 59(5) of the Constitution of Nepal grants local communities priority investment rights regarding the commercial utilisation of their natural resources. However, this constitutional provision has not yet been translated into a specific parliamentary enactment, and the law currently lacks an explicit definition for what constitutes a “local community.”
The only existing statutory mechanism for community share allocation is found under the Securities Registration and Issuance Regulations, 2073, which mandates that public companies allocate 10% of issued capital to project-affected communities (as identified by the EIA/IEE). However, this obligation applies only at the time of an Initial Public Offering (IPO), not at the time the SPV is initially formed. There is no statutory mechanism that compels developers to structure or reserve community shares at the point of SPV incorporation.
To mitigate social risk, the legal assessment recommends:
- Voluntary Early Commitment: RPGCL should voluntarily reserve a specific percentage of shares for project-affected communities at the time of SPV incorporation, even though formal issuance occurs later during the IPO.
- Public Company Formation: The SPV must be incorporated as a public limited company (not private) to facilitate eventual share issuance.
- Legislative Reform: Amendment of the PPPIA or the Electricity Act to introduce statutory provisions guaranteeing community shares arising from natural resource exploitation, ensuring structured participation well before the IPO stage.
Section D: The IPO Debate for Transmission Assets
Q10. Why is an IPO being considered for the West Seti SPV?
The requirement to issue an Initial Public Offering stems from two factors: the need to raise capital for the project, and the statutory obligation under the Securities Registration and Issuance Regulations to distribute shares to project-affected communities, the general public, migrant workers, and employees. Since the SPV is recommended to be incorporated as a public limited company, it will be legally positioned to issue shares to the public.
The mandated IPO share allocations are:
- Project-affected communities: 10% of issued shares
- General public: minimum 10% to maximum 49%
- Migrant workers: 10% of specifically allocated IPO shares
- Regular employees: up to 5% of specifically allocated IPO shares
Q11. What are the statutory preconditions for the IPO?
Before the SPV can legally launch an IPO, it must fulfil the following conditions under Rule 9(3) of the Securities Registration and Issuance Regulations:
- All necessary licenses (transmission license, industry registration) and approvals must be obtained.
- Promoters (RPGCL and investment partners) must have fully paid for their committed shares.
- The SPV must have successfully completed financial closure of the project.
Q12. Why might an IPO be an inappropriate mechanism for a BOOT-model transmission SPV?
The core argument against an IPO for a BOOT-model SPV is the fundamental mismatch between perpetual equity instruments and a time-bound concession asset. Under the proposed Electricity Bill 2080, transmission licenses have a maximum term of 25 years, after which all infrastructure must be transferred to the government free of cost. This means the SPV’s sole revenue-generating asset has a legally predetermined terminal value of zero.
An IPO introduces shares that are designed to trade indefinitely on the stock exchange as perpetual ownership claims, while the asset backing those shares is contractually destined to expire. Pricing such shares as if they were infinite-lived enterprises exposes retail investors to a structural mispricing – one where eventual capital loss is not a risk but a legal certainty.
The IPO mechanism systematically shifts long-term risk from sophisticated insiders (promoters) to unsophisticated public shareholders, creating conditions for promoter opportunism and retail investor loss.
Q13. What is the “Promoter Exit Abuse Pattern”?
The promoter exit abuse pattern refers to a well-documented dynamic in single-asset SPV listings. Promoters typically retain 60–80% ownership during the high-risk construction phase. However, the mandatory three-year lock-in period expires precisely when the project reaches operational stability and peak valuation certainty. This timing allows promoters to monetise their stake through secondary market sales at market peaks, extracting value while leaving retail investors holding equity whose underlying asset continues its countdown toward mandatory government transfer.
Q14. How do transmission SPVs differ from generation projects in terms of investor appeal?
Transmission assets have fundamentally different risk-return profiles compared to generation projects:
| Factor | Transmission SPV | Generation Project |
| Return Profile | Regulated, capped at 8–10% | Variable, potentially high |
| Growth Potential | Limited (fixed tariff) | Expansion possible |
| Volatility | Very low | Moderate to high |
| Retail Investor Appeal | Low (fixed returns only) | High (upside narrative) |
| Speculative Trading | Unlikely | Common |
Q15. What is the preferred alternative to an IPO?
The preferred alternative is institutional ownership through qualified investors:
- Pension funds, insurance companies, sovereign wealth funds, development finance institutions (DFIs), and strategic infrastructure funds.
- Exit mechanism: secondary sale to another qualified institutional investor, rather than open-market liquidation.
The recommended regulatory approach includes:
- Restricting shareholding to qualified institutional investors.
- Requiring promoter lock-in for the full project life (minimum 15 years).
- Prohibiting share transfers without ERC approval.
- Requiring shareholder agreements aligned with the project’s operational longevity.
Q16. Has this problem been observed in Nepal’s hydropower sector?
Yes. The hydropower sector has already demonstrated the risks of applying the IPO model to BOOT-concession SPVs. Generation companies with 25–35 year licenses have listed shares on the Nepal Stock Exchange that trade as perpetual claims despite having a legally predetermined expiry date. The absence of sinking funds, capital redemption reserves, or clear disclosure of the countdown to transfer has created a “going concern” illusion in the market. Replicating this model in transmission infrastructure would transfer the identical structural problem – terminal equity collapse – into a new and critical infrastructure sector.
International precedent demonstrates that jurisdictions successfully avoid this problem by using diversified holding company structures, Infrastructure Investment Trusts (InvITs), or project bonds with maturities aligned to license terms, rather than single-asset SPV IPOs.
Section E: Land Acquisition and Environmental Challenges
Q17. What is the land ceiling challenge for the project?
Under Section 7 of the Land Act, 2021, strict landholding limits are enforced by geographic region. While Section 12 permits certain projects to exceed the standard ceiling, a Government Order issued on 2078/02/03 BS capped the absolute maximum at 150 ropani. Projects seeking to exceed this limit must obtain special approval under Clause 3 of the Order and complete acquisition within two years.
The situation is uniquely complicated for RPGCL because it has already acquired land for the project. When Section 12A(1A) of the Land Act introduced a six-month statutory window for entities with excess land to apply for formal regularisation, RPGCL did not secure approval within the stipulated timeframe. Because this window has now lapsed, the existing statutory framework does not expressly provide any direct legal solution to regularise the excess land RPGCL currently holds. Any SPV established to take over the project will also be bound by these land ceiling provisions.
Q18. Is there a workaround for the land ceiling issue?
Yes. The identified pathway is through the Investment Board Nepal (IBN) concession route. Since the transmission line is a large-scale infrastructure project requiring IBN approval, it qualifies for a concession under Clause 6 of the 2078 Government Order. This clause allows IBN-approved projects to negotiate exemptions to the 150-ropani limit and associated timeframes directly through the Project Development Agreement (PDA).
The legal assessment recommends embedding the land ceiling exemption formally into the PDA. Additionally, it calls for broader legislative reform: amending both the Land Act and the 2078 Government Land Ceiling Order to grant automatic exemptions for nationally prioritised energy projects and projects approved under the PPPIA.
Q19. How does the proposed Bill 2080 change the Right of Way framework?
The Electricity Act 1992 contained only general provisions for land utilisation. The proposed Bill 2080 introduces an explicit Right of Way (ROW) framework based on voltage capacity, which dictates the required clearance distance on both sides of the transmission line centre point. It strictly prohibits building any structures within this ROW. Critically, the Bill mandates that developers pay compensation for land falling under the ROW – a provision that adds a significant cost layer to transmission projects traversing populated or agricultural areas.
Section F: Banking Sector Constraints and Financing Challenges
Q20. How does Nepal Rastra Bank’s energy sector lending framework affect transmission projects?
Under the directives of Nepal Rastra Bank (NRB), energy sector lending is subject to mandatory portfolio targets. Class “A” commercial banks must allocate increasing percentages of their loan portfolio to energy, reaching 10% by mid-July 2027 (Asar 2084). However, transmission projects compete directly with hydropower generation projects for this limited sectoral allocation.
The following table shows the phased lending targets for Class “A” commercial banks:
| Deadline | Required Portfolio % |
| Mid-July 2024 (Asar 2081) | 6.5% |
| Mid-July 2025 (Asar 2082) | 7% |
| Mid-July 2026 (Asar 2083) | 8% |
| Mid-July 2027 (Asar 2084) | 10% |
Q21. Are transmission projects eligible for the concessional interest rate cap?
No. This is a critical distinction. NRB’s directive provides for a concessional interest rate of base rate plus a maximum 1% premium, but this applies specifically to reservoir-based hydropower and export-oriented generation projects during their first five years of operation. Transmission projects are not automatically eligible for this concessional rate. Instead, they are priced based on standard risk assessment, market conditions, and bank rating – typically 2–4% above the base rate.
The following table clarifies which provisions apply equally and which do not:
| Provision | Transmission | Generation |
| Single Obligor Limit | Up to 50% of core capital | Up to 50% of core capital |
| Interest Capitalisation | Allowed during construction | Allowed during construction |
| Loan Classification | 90-day overdue rule | 90-day overdue rule |
| Energy Sector Target | Counts toward 10% | Counts toward 10% |
| Base Rate + 1% Cap | NOT eligible | Eligible (reservoir/export) |
Q22. What relief exists for generation projects delayed by transmission?
NRB directives provide special relief for generation projects whose commercial operation is delayed due to transmission line unavailability. These projects may partially capitalise interest during the delay period, reducing the immediate financial burden of debt servicing. This provision underscores the interdependence between generation and transmission infrastructure – and the systemic risk that transmission delays pose to the entire energy sector’s financial health.
Section G: Tax and Fiscal Framework
Q23. What direct tax incentives apply to the project?
The following direct tax incentives are available to the SPV:
- Tax Holiday: 100% income tax exemption for the first 10 years from the date of commercial operation, followed by 50% exemption for the subsequent 5 years. This benefit applies if commercial operation commences by Chaitra 2084 (mid-April 2028).
- Reduced Rate: Beyond the holiday period, the applicable corporate tax rate is 10% lower than the standard rate.
- Reinvestment Benefit: A deduction of 50% of the cost of new fixed assets is available if the investment results in at least 25% capacity expansion or modernisation.
Q24. What indirect tax benefits apply?
The project benefits from preferential customs duty and VAT treatment:
Customs Duty Benefits (applicable to goods not produced in Nepal, with DoED/IBN/AEPC recommendation):
| Import Category | Duty Rate |
| Construction Equipment | 1% (vs. standard 5–30%) |
| Machinery and Tools | 1% |
| Spare Parts | 1% |
| Steel Sheets | 1% |
Q25. Why is the wheeling service subject to VAT while electricity supply is exempt?
Electricity supply is classified as a basic necessity under Schedule 1, Group 2 of the VAT Act and is therefore exempt from VAT. However, the wheeling service – the transmission of electricity through the grid – is classified as a taxable service because it is not included in the VAT exemption list. The wheeling service is therefore subject to VAT at the standard rate of 13%. This distinction adds a cost layer to the transmission business model that does not apply to the underlying commodity being transported.
Section H: Grid Planning and Capacity Mismatch
Q26. What is the generation-transmission mismatch in Nepal?
Nepal’s generation capacity is growing at a significantly faster rate than its transmission network. Despite rapid growth in hydropower projects developed by both the state and IPPs, the construction of high-voltage corridors (400 kV and 220 kV lines) has not kept pace. This infrastructure gap has turned the transmission network into the single most significant bottleneck preventing Nepal from fully utilising and exporting its clean energy.
Q27. What are the consequences of this mismatch?
The generation-transmission mismatch produces three categories of harm:
- Stranded Generation Assets and Project Delays: New hydropower plants cannot deliver electricity because evacuation routes are not ready. Without guaranteed power evacuation corridors, commercial banks and lenders frequently refuse to grant financial closure, stranding projects even in the development phase.
- Curtailment and Energy Spillage: Completed hydropower plants are forced to waste or “spill” generated electricity, particularly during the monsoon season when generation peaks but the grid cannot absorb the output.
- Financial Losses and Missed Export Opportunities: The inability to evacuate power causes financial losses for developers, triggers disputes with the Nepal Electricity Authority (NEA), and results in lost cross-border electricity export revenue.
Q28. How does this mismatch specifically affect the West Seti corridor?
The West Seti 400 kV Transmission Line and the hydropower generation projects it is designed to serve are mutually codependent. Without the transmission line, the generation assets in the West Seti basin (approximately 2,500 MW) will remain completely stranded – unable to deliver power to the national grid or export markets. Conversely, without committed generation projects, the transmission line cannot generate the wheeling revenue needed to service its own debt and justify its USD 204.27 million investment. This circular dependency makes coordinated development of both generation and transmission infrastructure essential.
The West Seti corridor illustrates a broader systemic challenge: generation developers need a confirmed transmission line to achieve financial closure, while the transmission SPV needs confirmed generation commitments to demonstrate revenue viability to lenders. Breaking this “chicken-and-egg” deadlock requires coordinated government intervention.