Nepal's electricity supply is dominated by hydropower, while its economy-wide energy use remains dominated by biomass and commercial fuels. The transition challenge is therefore not only to add renewable generation, but to electrify end uses and coordinate energy across hours, seasons and sectors.
1. The clean-electricity paradox
DoED's operating registries list 3,915.744 MW of hydropower projects above 1 MW and 154.74 MW of solar projects, both updated 16 July 2026. Within those two registry categories, hydropower represents 96.2% of listed capacity. That percentage is a scoped registry calculation, not a complete census of every sub-1-MW, off-grid, thermal, biomass, wind or cogeneration facility. [10][11]
The reviewed 2050 paper reproduces an economy-wide energy balance totaling about 532.42 PJ: approximately 340 PJ of traditional biomass, 137 PJ of commercial fuels excluding grid electricity, 38.49 PJ of grid electricity and 16.5 PJ of modern renewables. Its Figure 1 caption labels the balance FY 2023/24, while the cited official WECS webpage is titled Energy Sector Synopsis Report 2024 (FY 2079/80). Because those period labels conflict, this review reports the numerical values but does not present either fiscal-year label as unambiguously resolved. The percentages below are author calculations from the four quantities. [1][8]
This distinction matters. A country can have a nearly renewable power grid while households still cook with fuelwood, vehicles burn imported petroleum and industry relies on coal or other thermal fuels. The transition therefore requires both clean supply and electrification of demand.
The seasonal mismatch
RoR and peaking-RoR plants dominate Nepal's hydro fleet, so output is strongly coupled to river flow. The 2026 PHES study reports about 14 TWh of RoR and peaking-RoR generation in FY 2024/25, a wet season concentrated in June–September, and dry-season river discharge typically more than 50% below monsoon flows. The same paper cites wet-season exports of roughly 500–560 GWh per month and dry-season imports of roughly 170–360 GWh per month in the FY 2024/25 balance. [2][14]
Nepal's core planning problem is a time-shift problem: move abundant wet-season energy into dry months, and move midday solar into evening demand.
In the reviewed 2050 optimization, the ambitious-hydro, low-demand cases combine 170 TWh/year of modelled hydro generation with 75 TWh/year of demand and produce the highest LCOE values: $114.11/MWh without imports and $113.99/MWh with imports. The result is model-specific evidence that capacity expansion can be costly when annual output is poorly matched to demand and flexibility. [1]
2. Targets are expanding faster than the current system
Nepal's NDC 3.0, dated 14 May 2025 and submitted to the UNFCCC in May 2025, targets 14,031 MW of renewable electricity capacity by 2030 and 28,500 MW by 2035. Mini- and micro-hydro, solar, wind and bioenergy are targeted to supply 10% of total capacity by 2030 and 15% by 2035, compared with a 2024 reference share of 5%. [9]
The same NDC targets BEVs at 90% and 95% of private-passenger-vehicle sales in 2030 and 2035, and 70% and 90% of public-passenger-vehicle sales. It also calls for adequate charging infrastructure, strengthened battery-management and recycling practices, and pilot activity by 2030. [9]
5% diversified sources
10% diversified sources
15% diversified sources
As of 16 July 2026, DoED listed 197 operating hydro projects above 1 MW totaling 3,915.744 MW and 27 operating solar projects totaling 154.74 MW. Ten additional solar projects totaling 74.6 MW held construction licenses. These are licensing-registry totals and should be cited with their category scope. [10][11][12]
Interpretation: the official targets broaden the supply mix, but the current operating registry remains hydro-centric. Reaching the NDC pathway requires faster non-hydro deployment, network reinforcement, flexible demand, and storage or trade arrangements that can manage both daily and seasonal variability.
3. Explore twelve least-cost pathways to 2050
Bhatta and Lohani evaluated twelve 2050 systems at hourly resolution. The factorial design combines three annual electricity-demand levels—2, 5 and 9 MWh per person—with two fixed hydropower pathways and either disabled or backup electricity imports. [1]
These are conditional optimization experiments, not forecasts or construction plans. They isolate how demand growth, hydropower build-out and regional trade alter the least-cost mix of PV, PHES and interconnection.
| Model element | Representation | Interpretive consequence | Validation |
|---|---|---|---|
| Demand | 2, 5 or 9 MWh/person/year; national annual demand of 75, 187 or 337 TWh | Scaling the same normalized hourly profile does not capture future end-use reshaping from EVs, cooking and industry. | paper ↗ |
| Hydropower | Reference pathway ≈13.27 GW in Table 1 (3.24 GW operating plus a 10.03 GW licensed-construction pipeline); ambitious pathway ≈37.545 GW | Hydro capacity is fixed within a pathway; rising demand is met by PV, PHES and imports. | Table 1 ↗ |
| Imports | Backup supply used only when domestic generation and storage cannot meet load | Import-enabled cases represent flexibility access, not unconstrained replacement of domestic generation. | methods ↗ |
| Storage | PHES only in the least-cost model | Battery and other short-duration options are intentionally excluded; results cannot be read as proof that PHES is optimal for every grid service. | methods ↗ |
| Finance | 5% baseline discount rate; sensitivity from 3% to 10% | Capital-intensive PV, hydro and PHES economics change materially with financing conditions. | sensitivity ↗ |
What the scenario space shows
- Solar scales with demand in most pathways. In A3-NoImport, 337 TWh/year of demand requires 345 GW of PV and 91 GW of PHES. Allowing backup imports reduces those capacities to 234 GW and 52 GW.
- Hydropower expansion can be underutilized at low demand. The two B1 cases model 170 TWh/year of hydro generation against 75 TWh/year of demand and have the highest LCOE values in Table 4.
- Trade substitutes for part of domestic balancing infrastructure. Across medium- and high-demand pairs, import access cuts modelled PHES power by about 43% to 79%; the exact reduction depends on the hydro pathway.
- Financing is a first-order variable. For A2-Import, the paper reports LCOE rising from about $61/MWh at a 3% discount rate to about $84/MWh at 10%. The rounded endpoints imply a 37.7% increase; the paper describes the change as about 37%.
The A2-Import one-at-a-time sensitivity analysis uses a baseline LCOE of $66.89/MWh. A ±25% change in PV cost moves LCOE to roughly $61.8–72/MWh, while the broader discount-rate sweep from 3% to 10% moves LCOE from about $61/MWh to $84/MWh. These results support the paper's emphasis on PV procurement and financing, but they remain conditional on all other model inputs. [1]
4. A storage portfolio, not a single storage winner
Taken together, the reviewed studies support a portfolio interpretation rather than a universal technology ranking: PHES for bulk long-duration shifting; batteries for fast, modular and distributed services; second-life EV packs where state-of-health and safety can be managed; hydrogen where a molecule or long-duration sector link has value; and trade or flexible demand where they avoid physical overbuild. This is an editorial synthesis across studies with different scopes, not the output of one co-optimization model. [1][2][3][5]
daily + seasonal shifting
fast + distributed balancing
sector coupling
Distributed flexibility: the Thakle microgrid lesson
National planning models determine how generation, storage and trade can balance Nepal's power system, but distribution-level projects determine whether reliable electricity reaches remote communities. Shah et al. examined this lower level of the transition through a HOMER Pro analysis of Thakle Namuna Basti, a post-earthquake settlement in Melamchi Municipality comprising 32 households and approximately 130 residents. The field-survey-based load profile is transcribed from the paper's HOMER load-profile figure as 236.99 kWh/day with an approximately 41.5 kW peak; these two values are graph-derived rather than stated in machine-readable body text. The mean solar resource is explicitly stated as 4.97 kWh/m²/day. [16]
Under the paper's initial grid-connected assumptions, HOMER identified a lowest-net-present-cost architecture combining approximately 5.89 kW of micro-hydro, 10.9 kW of solar PV and an 8 kW converter with the utility grid. The reported optimized case had a net present cost of about $70,507 and a levelized cost of electricity of approximately $0.0588/kWh. The analysis also found that project economics improved when river flow and the electricity sell-back rate were higher, and deteriorated when purchased-power price or hydropower cost increased. [16]
Why this belongs in a national flexibility review. The Thakle study does not establish a national least-cost pathway. It demonstrates a complementary principle: site-specific combinations of micro-hydro, PV, storage, converters and grid exchange can reduce the cost and reliability burden at the distribution edge. Such systems can serve settlements before major transmission reinforcement arrives, while also creating controllable local generation and demand that may participate in a more flexible national grid.
The result should not be generalized without qualification. It depends on the surveyed load, assumed component costs, river-flow availability, grid tariff, sell-back price and HOMER's 25-year project representation. The paper also modelled lead-acid storage, so its battery conclusions should not be transferred directly to contemporary lithium-ion systems. The case is most useful as a reproducible planning template rather than a universal tariff benchmark. conference paper DOI ↗ full ML·Energy·Bio review ↗
5. Pumped hydro: from atlas points to field-validated sites
The ANU atlas is a topographic screening inventory, not a feasibility study. Dhakal et al. therefore applied district-boundary, land-cover and terrain filters in ArcGIS, verified reservoir boundaries and contours, cross-checked elevations with handheld GPS measurements whose typical open-sky vertical accuracy was stated as ±5 m, and conducted field visits. This workflow reduced 142 atlas reservoirs in Kavrepalanchwok to two physically suitable candidate pairs for prefeasibility analysis. [2][13]
Banepa–Dhulikhel
Roshi
The economic result depends on charging electricity
For the field-validated Roshi configuration, the study used a 793 m head and 1.3 hm³ active reservoir volume, estimating 720 GWh/year discharged and 888 GWh/year pumped. The $238.5 million initial capital estimate includes construction, 20% risk and contingency, transmission, 10% miscellaneous cost, and 2.5% design and consultancy. LCOS is $105/MWh with RoR PPA-priced charging, $99/MWh with solar-PV charging, and $65/MWh with subsidized charging. [2]
Initial capital cost: $238.5 million
Interpretation: because charging electricity is an LCOS input, tariff design and access to low-value surplus energy materially affect the storage case. Capacity, ancillary-service and avoided-curtailment revenue would require a separate market-value analysis.
Nationwide potential remains much larger than modelled need
A separate national reservoir-pairing study estimated 3,012 GWh of theoretical PSH potential and 1,269 GWh of technically feasible potential. Its flat-land-to-river configuration contributed 2,716 GWh theoretical, 1,198.8 GWh technically feasible and 897.9 GWh exploitable under the study's grid, infrastructure and environmental filters. [4]
The 1,269 GWh result and the approximately 50 TWh reported for the Global Greenfield Atlas are not competing estimates: they use different reservoir configurations, elevation limits, pairing rules and screening criteria. The robust conclusion is that mapping must be followed by site-specific geological, environmental, social, network and financial assessment.
6. Second-life EV batteries: transport becomes grid infrastructure
The 2026 EV-battery study defines end of first vehicle life at 80% of nominal capacity and models LFP, LMO and NMC degradation under assumed Nepal usage and environmental conditions. Estimated first-life durations are about 7.0 years for LFP, 3.3 years for LMO and 3.7 years for NMC. Those timings determine when packs enter a potential second-life stock. [3]
Across EV-growth and chemistry-mix scenarios, cumulative second-life capacity reaches 145–184 GWh by 2043. For 2040, the study estimates 67% to more than 94% coverage of average daily wet-season surplus in its higher-surplus S-1 cases; in lower-surplus S-2 cases, projected second-life capacity exceeds the average daily surplus. These are energy-capacity comparisons, not demonstrations of seasonal firming, deliverable power, network access or economic dispatch. [3]
Lithium iron phosphate (LFP)
The LFP timing paradox
LFP has the longest modelled first-life duration of the three chemistries. A higher LFP market share therefore delays the arrival of retired packs within the 2040 planning window and slightly reduces near-term second-life stock—not because LFP performs worse, but because it remains above the vehicle-retirement threshold longer.
The practical storage resource will also depend on pack collection, traceability, state-of-health diagnostics, repurposing design, inverter compatibility, thermal management, fire codes, warranties and end-of-second-life recycling. The national energy-capacity estimate should therefore be treated as an upper-level resource assessment, not deployable capacity.
7. Hydrogen is valuable when it connects sectors
The 2022 study represents Nepal with 52 nodes, 68 transmission lines and 8,760 hourly time steps. It estimates about 32 GW of installed generation for domestic electricity demand by 2050 and about 14 GW of additional hydropower when road transport is fully electrified in the model. [5]
For the export-oriented scenario with equal battery-electric and hydrogen-vehicle shares, the paper's abstract reports 5.7 GW of electrolyzers, 12 GW of hydrogen-storage-tank capacity and 23 GW of storage-based hydropower. The body text separately describes export-oriented hydro-storage deployment as “about 27 GW.” Because the source is internally inconsistent, this review does not treat 23 GW or 27 GW as an independently resolved exact value. The robust result is that large storage-hydro deployment occurs mainly in the export-oriented case, while hydrogen-system deployment is negligible in scenarios without hydrogen vehicles under the paper's cost assumptions. [5]
A 2021 Nepal perspective reports electricity–hydrogen–electricity round-trip efficiency of roughly 20–30%, compared with about 80–90% for batteries or PHES. This supports selective use of hydrogen where long-duration storage or the hydrogen molecule itself provides sector value. The examples of fertilizer, industrial feedstock, high-temperature heat and heavy transport are editorial applications, not outputs of the 2022 power-grid model. [5][6]
| Option | Best-fit timescale | Primary value | Nepal-specific evidence | Main constraint |
|---|---|---|---|---|
| Closed-loop PHES | Hours to days; potentially seasonal | Bulk energy shifting, reserve, frequency response, long asset life | Two field-validated Kavrepalanchwok sites; Roshi LCOS $65–105/MWh | High initial capital, site validation, land and transmission |
| Second-life EV batteries | Seconds to hours; distributed daily cycling | Fast response, local congestion relief, circular use of imported batteries | 145–184 GWh projected by 2043; 67–94% of S-1 daily surplus in 2040 | State-of-health uncertainty, aggregation, fire safety, warranties |
| New battery systems | Seconds to sub-day balancing | Frequency control, peak shaving, solar time shifting, weak-grid support | The PHES paper cites battery cost escalation beyond roughly 4–6 h; chemistry inputs in the EV study exceed 95% for charge and discharge steps. | Replacement cycles, import dependence, recycling |
| Green hydrogen | Long duration and sector coupling | Fuel and feedstock for transport and industry; curtailment conversion | Hourly grid model shows reduced RoR/PROR curtailment and 5.7 GW electrolyzers in an export-oriented scenario | Low power-to-power efficiency and high infrastructure cost |
| Regional trade + flexible demand | Real-time to seasonal | Shares diversity across geography; avoids some storage and curtailment | In medium/high 2050 scenario pairs, import access reduces PHES power by about 43–79%, depending on hydro pathway. | Market rules, transmission, geopolitical and contractual risk |
8. An evidence-informed 2026–2035 roadmap
The following sequence is the author's synthesis of the evidence and identified implementation gaps. It is not an adopted Government of Nepal plan and should be evaluated through stakeholder consultation, system studies and project-level safeguards.
Correct the planning objective
Optimize for reliable energy delivered across seasons and sectors, not simply installed megawatts. Publish hourly and seasonal supply-demand data, curtailment and reservoir operating information.
Accelerate solar beyond a token share
Use utility solar, rooftops, canal and reservoir surfaces, brownfields and agrivoltaics. The 2050 model suggests solar may provide roughly 40–60% of generation in deeply electrified pathways, well above current policy shares.
Move PHES from atlas screening to bankable pilots
Complete geotechnical, hydrological, environmental and social studies for priority closed-loop sites. Establish market products for capacity, ancillary services and avoided curtailment — not only energy arbitrage.
Create a second-life battery regime before mass retirement
Require digital battery passports, health diagnostics, repurposing certification, fire codes, installer training, extended producer responsibility and end-of-second-life recycling.
Use hydrogen selectively
Prioritize pilots where hydrogen displaces imported fossil feedstock or fuels, rather than treating it as the default electricity-storage medium. Co-locate electrolyzers with constrained renewable generation and industrial demand.
Strengthen regional trade without outsourcing security
Expand transmission and transparent trading arrangements while maintaining sufficient domestic storage and reserve. Trade should reduce cost, not create a new single-point dependency.
De-risk capital
Use concessional finance, guarantees, standardized PPAs and competitive procurement. The least-cost model is highly sensitive to discount rate; financing reform can change the optimal system as much as technology cost.
Grow productive electricity demand
Coordinate EVs, electric cooking, heat pumps, industrial furnaces, cold chains and irrigation with renewable availability. Flexible demand is an asset when tariffs reward consumption during surplus periods.
9. What the evidence does — and does not — establish
The 2050 capacity results depend on demand, cost, climate and trade assumptions. They show system relationships, not a precise construction schedule.
Most mapped PHES sites have not undergone geology, land-tenure, biodiversity, heritage or community-consent assessment.
The 145–184 GWh estimate assumes EV adoption, charging infrastructure and battery-retirement trajectories broadly follow the modelled pathways.
Climate change, sediment, glacier retreat and extreme events can alter river flows and asset reliability. Future models need climate-adjusted hydrology.
National energy balance does not guarantee local voltage, frequency, inertia or transmission adequacy. Distribution planning remains essential.
LCOS and LCOE depend on financing, construction risk, utilization, tariff design and exchange rates. Published values are comparable indicators, not bids.
Conclusion
The reviewed resource assessments and conditional scenarios indicate that a deeply renewable Nepalese energy system is technically plausible, but they do not establish a single bankable national build plan. The implementation problem is coordination: demand growth, tariff design, site validation, transmission, financing, environmental and social safeguards, and governance of new assets such as repurposed EV batteries.
Across the studies, the recurring architecture is a complementary solar–hydro system with multiple flexibility layers. PHES is evaluated for bulk shifting, batteries for modular and distributed services, regional trade for geographic balancing, and hydrogen for selected sector-coupling cases. Their relative scale must be resolved by models that co-optimize these options under updated demand, hydrology, network and cost data.
The strategic shift is from counting renewable megawatts to designing a flexible renewable-energy system.
@misc{mlenergybio2026nepalflexiblegrid,
author = {Upreti, Saugat},
title = {From Monsoon Surplus to a Flexible Grid: An Evidence-Audited Review of Nepal's Renewable-Energy Transition},
year = {2026},
month = {July},
url = {https://mlenergybio.com/blog/nepal-flexible-grid},
note = {Evidence-audited review with interactive scenario analysis}
}