Nepal is one of the world’s most hydropower blessed countries and has identified more than 83,000MW of resources, with some 42,000MW considered to be technically and commercially viable. Described as offering immense possibilities, hydropower can play a crucial role in the country’s drive towards energy diversification.
However, for decades Nepal has been politically and technically challenged in its ability to initiate, develop and commission large hydropower projects as planned. Due to systemic bottlenecks delaying project implementation, its vast hydropower potential remains underutilised, undermining energy security and economic growth.
Key findings from recent studies reveal that factors contributing to such prolonged timelines and cost overruns include:
- Political instability.
- Bureaucratic inefficiencies.
- Land acquisition disputes.
- Protracted environmental and social impact assessments.
- Technical and geographical challenges.
- Financial constraints.
- Contractor performance issues
As Sharma Manan and Rawat Sharma Samjhana go on to explain in the International Journal of Engineering Research and Technology, political volatility disrupts policy continuity, while overlapping institutional mandates create decision-making bottlenecks. Land acquisition struggles stem from inadequate compensation and community resistance, and flawed EIA/SIA processes exacerbate delays. Projects in remote, geologically complex regions face logistical hurdles, and reliance on foreign financing introduces procedural delays, with natural disasters, governance failures, and socio environmental conflicts derailing progress.
Ultimately, these delays perpetuate Nepal’s reliance on electricity imports, strain public finances, and erode community trust.
Key examples of delayed projects include the 456MW Upper Tamakoshi hydropower scheme which was planned for completion in 2015, but challenges from an earthquake and the covid–19 pandemic meant it wasn’t commissioned until 2021. While the 1200MW Budhi Gandaki hydropower project was prepared more than a decade ago but couldn’t take-off due to controversies around land acquisition and financing. And then there’s the West Seti project which has been in existence for more than two decades but has suffered from investor pullout and delays, despite renewed attention regarding regional collaboration.
To tackle such systemic challenges the authors say there is a need to enhance institutional capability and inter-agency collaboration of Nepalese organisations engaged in planning and implementing hydropower projects. A proposed inter-ministerial task force or single-window project facilitation unit could help eliminate unnecessary crossovers and duplication, facilitating policy consistency.
It would also be advantageous for project performance if monitoring functions were decentralised. Regional offices and remote consultants could make more prompt decisions to help fast track dispute resolution. In addition transparency and accountability in the management and acquisition of environments and land are vital.
The authors also suggest Nepal looks for sources other than bilateral loans with political conditions for funding. Investments in developing local technical capacities – through university education and training of engineers and a technical workforce, as well as through knowledge transfer – would also decrease reliance on foreign companies and enhance the sustainability of the projects.
Policy shift
In June this year the Nepalese energy sector was said to have been ‘rocketed’ by a shift in government policy that critics believe had the potential to derail Nepal’s hydropower ambitions.
Fundamentally changing the risk dynamics for run-of-river projects, and shifting the risk of low demand or transmission congestion to private power producers, the government announced that PPAs for run-of-river hydropower projects will now be executed under the Take and Pay model.
This would mean the country’s sole electricity buyer, the Nepal Electricity Authority (NEA), will only pay for the electricity it actually purchases, and is in stark contrast to the previously followed Take or Pay model, which guaranteed payment for contracted amounts of electricity – regardless of actual consumption. The Take or Pay model has been described as historically being key to attracting private investment in Nepal’s hydropower sector.
This new policy move sparked great concern among energy developers, investors, and financial institutions. They warned although it may appear fiscally prudent for NEA in the short term, it could have long-term consequences for Nepal’s energy economy.
Without the certainty of the Take or Pay model it was feared banks wouldn’t finance projects and over 350 schemes, equating to more than 17,000 MW of upcoming hydropower, could be at risk. There are also knock on implications of project delays leading to job losses and threatening national energy goals.
Critics also pointed to structural flaws in the Nepalese power market. As the NEA is the only buyer and there are no alternate buyers or power exchanges, they say the Take and Pay policy becomes one-sided and unjust, killing the concept of a level playing field.
With growing backlash from industry groups, banks, and experts, the government was asked to reconsider and reverse the policy. Then on 23 June, the Minister for Energy, Water Resources and Irrigation announced it will be amended. It was recommended reverting to the ‘take-or-pay’ model for small hydropower plants with a capacity of up to 10MW and for run-of-river projects that have guaranteed domestic consumption or export agreements.
Australian pumped storage
Although there is a huge appetite for pumped storage across Australia, very few projects have achieved final investment decision (FID). Indeed many pumped storage projects are in the pre-FID/feasibility stage awaiting further clarification on government support. And as the International Hydropower Association warns, the industry has invested heavily in pumped storage feasibility studies for projects that won’t necessarily go ahead, discouraging potential investors even further.
“Australia’s current market design won’t deliver LDES required with arbitrage alone,” IHA President Malcolm Turnbull acknowledged. “The energy market is not designed to reward investment in reliability and storage, and high up-front capital costs for long-lasting infrastructure. It’s not a choice between batteries and pumped hydro, we need both, but we need to act now.”
Infrastructure projects take time. Turnbull says the government and industry need to drive a step change in the delivery pace of pumped hydro projects, including more streamlined permitting. In Australia specifically, there is a clear need for the introduction of a co-ordinated national policy framework, supported by a national hydropower roadmap to incentivise pumped storage and hydropower investments.
The federal government is also urged to consider reviewing existing policy and market support mechanisms for PSH and hydropower, adjusting or unifying them to actualise a ‘fit for-purpose’ enabling environment that will support the Australian energy system’s long-term needs.
To achieve this, the recent IHA report looking at powering Australia’s future, recommends that the commonwealth government and the states and territories of Australia must consider the following actions:
1. Recognise that conventional and pumped storage hydropower are multi-benefit, strategic assets and should be valued accordingly by federal and state governments. Policymakers should recognise the long-term value and local community benefits that pumped storage and hydropower assets can provide for decades, beyond election cycles. Policies themselves need to be equally long term and stable and it’s important that policymakers have a thorough understanding of the specific role that hydropower and pumped storage plays in Australia’s energy mix, appreciating how that will increase in importance as thermal generation is replaced by variable renewable energy.
2. Plan for and invest in the hydropower infrastructure needed to best support energy storage targets set by federal and state governments national framework for hydropower. Policy frameworks should not only enable project development but also actively incentivise innovation that enhances PSH flexibility, co-optimises with variable renewables, and supports 24/7 carbon-free energy services.
3. Explicitly define long-duration energy storage as 8+ hours across all related policy mechanisms.
4. Streamline licensing and permitting where possible to ensure minimal delays. At the state and federal government level, departments are called upon to support the environmental, water, and electricity permitting requirements, giving appropriate consideration to any measures to provide expedience and transparency on the timing of permits.
5. Design appropriate and consistent government support mechanisms to de-risk long-life energy storage assets. Such policy and regulatory support mechanisms should be consistent and seek to enable economic growth, supply chain resilience, local industry development, and be delivered sustainably.
6. Ensure electricity markets are designed with appropriate price signals which value firming and balancing services to incentivise the development of long-duration energy storage.
India’s pumped storage pivot
India’s energy planners are increasingly turning to pumped storage hydropower (PSP) as a cornerstone for grid stability and clean energy integration. In April 2023, the Ministry of Power issued formal Guidelines to Promote Development of Pump Storage Projects (PSPs), marking a major policy step to streamline approvals, allot project sites, and rationalise environmental clearances.
Under these guidelines, 56 PSP sites totalling 73.24GW were identified across 15 states/union territories and assigned to central public sector undertakings (PSUs).
The guidelines also propose budgetary support for enabling infrastructure (roads, bridges, transmission links) and waiver of Inter-State Transmission System (ISTS) charges for PSPs commissioned under certain timeframes.
Recent developments further reinforce this momentum. The Central Electricity Authority (CEA) has approved a plan to accord “concurrence” to 13 PSPs (approximately 22GW) in 2025-26, with a target to have them commissioned within four years.
The government has also introduced tariff-based competitive bidding (TBCB) guidelines for procuring storage capacity from PSPs, defining models such as “tolling tariff” and “composite tariff” to allocate responsibilities and risks between procurers and developers.
Yet, challenges remain. India currently operates only a handful of PSPs (around 4-5GW capacity), and many of the projects in the environmental clearance pipeline have not yet begun construction.
The process of securing land, forest and environmental approvals continues to be complex, often requiring multiple clearances.
Some PSP sites are located in regions with challenging topography or ecological sensitivity, adding complexity to environmental assessments and social consent processes.
Looking forward, India’s strategy is to scale PSP deployment in line with variable renewable energy growth. The push for PSP is contained within the broader National Framework for Promoting Energy Storage Systems (ESS), which integrates PSP policy with battery storage, grid flexibility, and procurement mechanisms.
If these regulatory reforms and incentives are sustained, PSPs could play a pivotal role in helping India meet its 500 GW non-fossil capacity target and stabilise grid operation.
US challenges
Although the US hydropower sector retained access to federal tax credits in legislation passed this summer, the industry is still facing significant challenges in the form of the permitting and licensing of projects.
With hundreds of facilities coming to the end of their typically 50-year licence, the US industry is facing up to its next big wave of hydropower relicensing.
Numerous different agencies or stakeholders, up to ten or more, can be involved in the permitting process which, according to the National Hydropower Association, means it can take up to eight years to license a facility – longer than it takes to license a nuclear plant.
This is what FirstLight Power finds itself in the middle of in Massachusetts. The company is now into the thirteenth year of a supposed five-year licensing process for two of its hydropower projects. In the interim it is waiting to make upgrades to its facilities while operating them under an extension of its old license. Although FirstLight has the means to keep its Massachusetts facilities running, some smaller hydro operators haven’t survived relicensing. Over 60 facilities have surrendered their licences in recent years, according to the National Hydropower Association.
The challenge is finding investors who have the patience to wait for the length of time that it will take to recoup the investments made into rehabilitating and re-licensing of such projects.
