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Nepal: 5 energy policy briefs

The energy policies moving Nepal’s power markets, one brief each: the problem, the mechanism, the market effect, who gains and who pays, where it stands on the path to binding law, and the official text.

Dry-season security and storage · Reservoir PPA Directive 2082 and a 9,851 MW pumped-storage pipeline still at study

Nepal · Electricity Regulatory Commission / Nepal Electricity Authority · directive · 2026

Where it stands: Reservoir purchase-sale directive issued but storage PPA pricing still at discussion-paper and cost-benchmarking stage

Nepal exports 3,965 GWh in the monsoon and imports 1,171 GWh in the dry season because its fleet is almost all run-of-river: the three Kulekhani storage plants supplied about 92 GWh of 19,078 GWh and both NEA thermal stations ran not at all. The ERC's Reservoir Plant Purchase and Sale Directive 2082 and its storage-hydro PPA pricing paper are the first attempt to price dry-season energy, while 12 pumped-storage projects of 9,851 MW were screened in FY 2025/26 and none has cleared feasibility.

The problem

Nepal's system has no dispatchable depth. Of 19,078 GWh of system energy in FY 2025/26 the three Kulekhani storage plants supplied roughly 92 GWh, about half a percent, and NEA's two thermal stations, the Duhabi multifuel plant and the Hetauda diesel plant, generated zero for the entire year. There are no grid-scale batteries in service. The result is a system that spills and exports in the monsoon and buys back in the dry season: 1,171 GWh of imports costing NRs 10.56 billion, with a system peak of 3,226 MW recorded on 6 July 2026 against a national peak of 2,479 MW on 28 June 2026. The Commission's own long-run marginal cost study prices that asymmetry precisely: at the busbar, marginal energy cost is NPR 6.89/kWh in the dry-season peak and NPR 0.54/kWh in the wet-season off-peak, and in the dry season proxy diesel sets the marginal price for about 4.6 percent of hours while Indian imports set it for about 30.8 percent. A flat PPA rate cannot procure a resource whose value varies by that much.

What it does

The Electricity Regulatory Commission has begun building a separate price for stored energy. It issued a Reservoir-type Power Plant Electricity Purchase and Sale Directive 2082, published a discussion paper on storage hydro PPA pricing, and in August 2026 published the long-run marginal cost and tariff design study that quantifies dry-season peak capacity and energy cost by voltage level, which is the input a differentiated storage rate needs. NEA's build programme follows the same logic. Its Project Development Department is studying mega multipurpose storage schemes totalling 11,483 MW, run-of-river projects of 562 MW and pumped-storage projects of 928.5 MW; from FY 2080/81 through FY 2082/83 it screened and ranked 63 pumped-storage projects with an aggregate 69,428 MW out of 220 identified sites, and 13 storage projects totalling 3,088 MW out of 24 identified. In FY 2025/26 alone it screened 12 pumped-storage projects totalling 9,851 MW from 34 identified sites and three storage projects totalling 301.7 MW, and carried out pre-feasibility work on Kolpu Storage (100.1 MW) and G-25 pumped storage (411 MW). The flagship is Hulingtar-Dumkim in Dhading and Chitwan at about 494.5 MW, where the survey licence is held and the feasibility study is under way; Syarpu Lake (334 MW) in Rukum West holds a survey licence obtained in 2023 and since extended; and Kulekhani Sisneri is in geotechnical investigation and environmental impact assessment. On conventional storage, the 670 MW Dudhkoshi project is targeting financial closure in October 2026 with commissioning envisaged by 2035, and the 821 MW Uttar Ganga project has a grid connection agreement signed with its PPA and generation licence in process. NEA also plans a 100 MW battery energy storage system and a 2.5 MW electrolyser at Hetauda, and intends to use public-private partnership for batteries and smart meters.

Market effect

The commercial consequence of the seasonal asymmetry is that Nepal sells its surplus at monsoon prices and buys its scarcity at dry-season prices, on an exchange it does not control. Export revenue of NRs 29,314 million against import cost of NRs 10.56 billion nets positive today, but every new run-of-river megawatt widens the spread the system has to trade through. A cost-reflective reservoir and pumped-storage PPA rate would change the merit order of what gets built: at a dry-season peak marginal energy cost of NPR 6.89/kWh at the busbar and a marginal capacity cost of NPR 2,836 per coincident kW per month, storage and peaking capacity are worth multiples of what a flat run-of-river contract pays, which is precisely why 227 run-of-river IPP plants exist and not one pumped-storage plant does. For developers and lenders the gating item is not the resource — 220 pumped-storage sites have been identified — but a bankable tariff and a counterparty: none of the 12 projects screened in FY 2025/26 has cleared feasibility and the flagship 494.5 MW scheme is still in study. Until that changes the dry-season balance stays outsourced to India under discretionary approvals, and the 1,400 MW of agreed import capability on the Dhalkebar corridor is the country's real reserve margin.

Key numbers

Storage output
About 92 GWh from the three Kulekhani plants out of 19,078 GWh of system energy; both NEA thermal stations generated zero
Dry-season imports
1,171 GWh costing NRs 10.56 billion in FY 2025/26
Seasonal marginal energy cost
NPR 6.89/kWh dry-season peak vs NPR 0.54/kWh wet-season off-peak at the busbar
Pumped-storage pipeline
12 projects totalling 9,851 MW screened in FY 2025/26 from 34 sites; 63 projects and 69,428 MW screened over three years; none past feasibility
Storage projects in development
Dudhkoshi 670 MW, financial closure targeted October 2026 and commissioning 2035; Uttar Ganga 821 MW

Who gains and who pays

  • Reservoir and pumped-storage developers (gains): A differentiated storage PPA rate is the precondition for financing; 9,851 MW screened in FY 2025/26 alone.
  • Nepal Electricity Authority (obligation): Carries the dry-season balancing risk and NRs 10.56 billion of import cost with about 92 GWh of storage output to work with.
  • Run-of-river IPPs (costs): A cost-reflective seasonal rate reduces the relative value of flat wet-season energy.
  • Industrial consumers and dry-season load (mixed): Exposed to dry-season scarcity pricing but would gain firm supply from storage and batteries.
  • Battery and pumped-storage equipment suppliers (gains): A 100 MW battery system and a 2.5 MW electrolyser are planned, with PPP procurement intended.

Implementation

The Reservoir Plant Electricity Purchase and Sale Directive 2082 and the storage-hydro PPA pricing discussion paper sit with the Commission alongside the hydropower generation and operational cost benchmarking studies; together they are meant to produce a storage and peaking tariff distinct from the run-of-river rate. NEA's pumped-storage projects are at survey-licence and feasibility stage with the Department of Electricity Development, and survey licences must be extended year by year — the Syarpu Lake licence obtained in 2023 has already been extended once, and the Upper Tila survey licence runs only to 3 October 2026. Dudhkoshi's targeted October 2026 financial closure with ADB support is the nearest real test of whether a Nepali storage project can be financed, and the Uttar Ganga PPA is the nearest test of whether a storage rate exists to sign against. The 100 MW battery system is stated as an intention rather than a procurement.

Concerns

  • No pumped-storage project has cleared feasibility despite 220 identified sites and three years of screening
  • Dry-season adequacy depends entirely on Indian imports under discretionary Power Exchange Committee approvals
  • No grid-scale battery in service and the 100 MW system is an intention rather than a tender
  • Reservoir and pumped-storage PPA pricing is still a directive and a discussion paper, not a published rate
  • Survey licences for storage schemes expire annually and must be extended, adding development risk
  • Kulekhani reservoir inflow and sedimentation limit the only existing storage the system has

Dates to watch

  • 2026-10: Targeted financial closure of the 670 MW Dudhkoshi storage project
  • 2027: ERC decision on a differentiated reservoir and pumped-storage PPA rate
  • 3 October 2026: Expiry of the Upper Tila survey licence, indicative of the annual renewal risk across the storage pipeline

Sources

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Transmission build-out · 7,110 circuit-km today, 1,650 km under construction and a 40 GW master plan to 2040

Nepal · Nepal Electricity Authority / Rastriya Prasaran Grid Company Limited · plan · 2026

Where it stands: Licences and financing in place; 1,650 circuit-km and 6,261 MVA under construction; cross-border lines nearing commissioning

Nepal ended FY 2025/26 with 7,110 circuit-kilometres of 66-400 kV line and 15,541 MVA of grid substation capacity, with a further 1,650 circuit-kilometres and 6,261 MVA under construction. The Butwal-Gorakhpur and Dhalkebar-Sitamarhi 400 kV cross-border lines are near completion, RPGCL's master plan sizes the eventual network to wheel 40 GW by 2040 at about USD 6.04 billion, and NEA has begun tendering transmission under a tariff-based competitive bidding framework.

The problem

Nepal's generation sits in the high hills while its load and its export market sit in the Terai and across the Indian border, so every megawatt of hydropower depends on a line being there first. The gap has been chronic: plants have reached commercial operation and then spilled water for want of evacuation, the Hetauda-Dhalkebar 400 kV line was stalled for a decade, and the eastern and Karnali corridors were built at 132 kV. With 213 projects totalling 6,472.21 MW already under construction after financial close and a national goal of 28,500 MW of installed capacity by 2035, the binding constraint on Nepali generation economics is transmission, not hydrology and not capital.

What it does

NEA's Transmission Directorate and the state transmission company Rastriya Prasaran Grid Company Limited, established on 12 July 2015, are building two networks at once: a domestic 220-400 kV backbone and a set of cross-border corridors. In FY 2025/26 the Khimti-Barhabise 400 kV line, the Markichowk-Bharatpur 220 kV line, the Kohalpur-Surkhet line that connected Karnali province to the 132 kV network for the first time, and the Dhalkebar-Balganga, Tamghas-Burtibang, Lalbandi-Salimpur and Kaligandaki-Ridi 132 kV lines were commissioned, adding 1,418 MVA of substation capacity and taking the network to 7,110 circuit-kilometres and 15,541 MVA. The decade-long dispute blocking the Hetauda-Dhalkebar 400 kV line was resolved and construction resumed, with 376 of 378 towers erected on that section. On the border, the Nepal segment of the Butwal-Gorakhpur 400 kV line is being built by MCA-Nepal with Millennium Challenge Corporation funding — the 40th MCA-Nepal Board meeting on 6 March 2024 separated the 18 km Nepal segment from the larger 315 km project to meet the cross-border trade commitment — while the Indian segment is a joint venture between NEA and Power Grid Corporation of India Limited. The Dhalkebar-Sitamarhi 400 kV line is also near completion. Further projects are in procurement: the Inaruwa-Anarmani 400 kV line, 89.6 km with a 2x315 MVA GIS substation at an estimated USD 121.88 million, with Asian Infrastructure Investment Bank funding anticipated by end-2026 and construction from end-2027; the Arun Hub-Inaruwa 400 kV line, 95.6 km at USD 80.70 million, and Arun Hub-Tingla-Dudhkoshi, 115 km at USD 100 million; the New Butwal-Lamahi 400 kV line, now in bidding; the Chameliya-Jauljibi 220 kV line to India, agreed at the twelfth Nepal-India Joint Steering Committee on 11 February 2025 for completion by December 2027; and the Chilime-Rasuwagadhi-Kerung 220 kV line, Nepal's first grid link toward China. RPGCL's master plan sizes the eventual network at 3,192 km of 400 kV, 1,160 km of 220 kV and 2,515 km of 132 kV line with 58 substations and 30 GVA of transformer capacity, to wheel 40 GW by 2040 against 18 GW of domestic load and 16 GW of export, at a total cost of USD 6,037.68 million.

Market effect

Line capacity is now the price-setting variable in Nepali power. The thirteenth Joint Working Group and Joint Steering Committee on 14-15 July 2026 fixed the combined transfer capability of the Dhalkebar-Muzaffarpur and Dhalkebar-Sitamarhi 400 kV lines at 1,650 MW for export and 1,400 MW for import, against an approved export quantum of only 1,200.01 MW today, so commissioning Sitamarhi directly enlarges the volume NEA can sell into the Indian exchange while the import headroom is what secures the dry season. The same meeting agreed that Butwal-Gorakhpur will initially be energised at 220 kV, with Nepali imports through it capped at 130 MW and exports at 200 MW until the 400 kV level is commissioned, which defers part of the expected uplift. Domestically, the Khimti-Barhabise and Markichowk-Bharatpur lines let Tamakoshi, Sunkoshi and Marsyangdi basin plants run at rated capacity instead of being constrained, converting sunk generation capex straight into saleable energy. The financing model is the other change: NEA has been designated a bidding agency under a government-approved Tariff Based Competitive Bidding framework for transmission projects and has invited expressions of interest for four transmission line projects on a build-own-operate-transfer basis, the first time private capital has been offered Nepali transmission revenue.

Key numbers

Network at end FY 2025/26
7,110 circuit-km of 66-400 kV line and 15,541 MVA of grid substation capacity
Under construction
1,650 circuit-km of line and 6,261 MVA of grid substations
Cross-border transfer capability agreed 14-15 July 2026
1,650 MW export and 1,400 MW import combined on Dhalkebar-Muzaffarpur and Dhalkebar-Sitamarhi
Butwal-Gorakhpur interim limits
Operated at 220 kV; Nepali import capped at 130 MW and export at 200 MW
RPGCL master plan
3,192 km of 400 kV line and 40 GW of wheeling capacity by 2040 at USD 6,037.68 million

Who gains and who pays

  • Independent power producers in the Tamakoshi, Sunkoshi, Marsyangdi and Arun basins (gains): New 220-400 kV evacuation lets plants run at rated capacity rather than constrained output.
  • Nepal Electricity Authority (obligation): Carries the capex and the foreign-currency debt; 1,650 circuit-km and 6,261 MVA are still under construction.
  • Transmission service providers and EPC contractors (gains): Expressions of interest invited for four BOOT transmission projects under the TBCB framework.
  • Landowners and communities along corridors (costs): Right-of-way, forest clearance and land acquisition remain the main schedule risk on every project.
  • Indian and Bangladeshi offtakers (gains): Dhalkebar-Sitamarhi and Butwal-Gorakhpur raise combined cross-border transfer capability toward 1,650 MW.

Implementation

Each line needs a Department of Electricity Development construction licence, an initial environmental examination or environmental impact assessment approved by MoEWRI or the forest ministry, forest clearance and tree enumeration, and private land acquisition. Those steps, not construction, have historically dominated schedule slippage. Funding is almost entirely concessional, from the World Bank, ADB, JICA, AIIB, KfW, NORAD, the European Union, the European Investment Bank, the Millennium Challenge Corporation and the Export-Import Banks of India, China and Korea, which is also the source of NEA's NRs 11,517 million foreign exchange loss in FY 2025/26. Near-term milestones are completion of the Hetauda-Dhalkebar 400 kV line, expected within months; commissioning of Dhalkebar-Sitamarhi and of Butwal-Gorakhpur at 220 kV; an AIIB funding decision for Inaruwa-Anarmani by end-2026 with construction from end-2027; and award of the first BOOT transmission concessions under the TBCB framework. Substation automation is being extended to 39 existing and 15 new grid substations with integration to the Syuchatar load dispatch centre in FY 2026/27.

Concerns

  • Right-of-way, forest clearance and land acquisition remain the dominant cause of delay on almost every corridor
  • Butwal-Gorakhpur energised only at 220 kV initially, deferring the expected export uplift
  • Concessional foreign-currency debt exposes NEA to exchange losses that reached NRs 11,517 million in one year
  • No domestic manufacture of high-voltage equipment; every 400 kV package depends on foreign EPC supply chains
  • The tariff-based competitive bidding framework for transmission is untested, with no concession yet awarded
  • Master-plan targets of 40 GW of wheeling by 2040 assume export demand that is not yet contracted

Dates to watch

  • 2026-Q4: Completion of the Hetauda-Dhalkebar 400 kV line and commissioning of Dhalkebar-Sitamarhi
  • 31 December 2026: Expected AIIB funding decision for the Inaruwa-Anarmani 400 kV line
  • 2027-12: Target completion of the Chameliya-Jauljibi 220 kV cross-border line agreed at the twelfth Joint Steering Committee

Sources

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Cross-border power trade with India · CBTE Regulations as amended 9 December 2025 and 1,200 MW of Nepali approvals

Nepal · Central Electricity Regulatory Commission (India) / Nepal Electricity Authority · regulation · 2025

Where it stands: Trading live since 2021; CERC framework amended 9 December 2025; 1,200.01 MW approved as of FY 2025/26

Nepal's entire wholesale market is cross-border. Under the 2014 Nepal-India power trade agreement and India's CERC Cross Border Trade of Electricity Regulations 2019, amended in 2023 and again on 9 December 2025 to move access onto General Network Access, NEA holds 37 Indian approvals covering 1,200.01 MW and exported 3,965 GWh worth NRs 29.31 billion in FY 2025/26, including the first 40 MW of round-the-clock supply to Bangladesh across Indian territory.

The problem

Nepal has no domestic wholesale market: NEA is the single buyer, and the only place surplus energy can be sold at a price is India. The 4.1 GW fleet is about 95 percent hydro and overwhelmingly run-of-river, so output collapses in the dry season and floods the system in the monsoon — NEA still imported 1,171 GWh of dry-season energy in FY 2025/26 while exporting 3,965 GWh. Access to the Indian market is not a Nepali entitlement. It is granted under Indian regulation, project by project and line by line, by a designated authority and the Indo-Nepal Power Exchange Committee, which means Nepal's export revenue and its dry-season security both rest on one counterparty's discretionary approvals.

What it does

The Agreement between the Government of Nepal and the Government of India on Electric Power Trade, Cross-Border Transmission Interconnection and Grid Connectivity, signed 21 October 2014, commits the parties to non-discriminatory access to cross-border interconnections and to a coordinated procedure for scheduling, dispatch, energy accounting, settlement and unscheduled interchange. India's operative rulebook is the CERC (Cross Border Trade of Electricity) Regulations 2019, notification 13/2/7/2015-PM/CERC of 8 March 2019, made under sections 178 and 66 of the Electricity Act 2003 and the Ministry of Power's 2018 Guidelines on Import/Export (Cross Border) of Electricity. A First Amendment followed in 2023 and a Second Amendment was notified on 9 December 2025: it replaces long-term access with General Network Access and transitional GNA throughout the regulations, and widens the definition of a selling entity to include Indian trading licensees and generating stations electrically connected to a neighbouring country through dedicated transmission lines. Under that framework Nepal has traded on the Indian Energy Exchange since 1 May 2021 and exported through NTPC Vidyut Vyapar Nigam as nodal agency since 3 November 2021. As of FY 2025/26 NEA holds 37 approvals totalling 1,200.01 MW: 11 approvals for 486.57 MW on the day-ahead and real-time exchange markets, 24 medium-term bilateral approvals for 673.44 MW, and two approvals for 40.00 MW to Bangladesh routed over the Dhalkebar-Muzaffarpur 400 kV line. The medium-term book is two agreements of 200 MW each supplying Haryana discoms for five years and up to 200 MW to Bihar State Power Holding Company for three years, extendable to five. Round-the-clock export of 40 MW to Bangladesh began in June 2026 and delivered 148 GWh in the fiscal year.

Market effect

Exports rose 66.60 percent in one year, from 2,380 GWh to 3,965 GWh, turning NEA into a net exporter of 2,794 GWh with NRs 29,314 million of export revenue against NRs 10.56 billion of import cost. That is the single largest swing in NEA's income statement and the reason a utility carrying NRs 11,517 million of foreign exchange losses still cleared NRs 5,040 million of pre-tax profit. Because the trading desk bids into the day-ahead and real-time markets, Nepali wet-season energy is now priced against Indian exchange clearing prices rather than a contract rate, and NEA explicitly runs a strategy of selling into high-price periods and buying cheap off-peak power to refill the Kulekhani reservoir. The Second Amendment's move to General Network Access matters for the next tranche: it changes how Nepali sellers queue for Indian transmission capacity and, by admitting Indian generators on dedicated lines as selling entities, opens the return path for firm dry-season import contracts. The ceiling is physical and political at once — approvals are line-specific and the Power Exchange Committee can revise them.

Key numbers

Approved export quantum
37 approvals totalling 1,200.01 MW across exchange, medium-term bilateral and Bangladesh routes
Exports FY 2025/26
3,965 GWh worth NRs 29,314 million, up 66.60 percent from 2,380 GWh
Imports FY 2025/26
1,171 GWh costing NRs 10.56 billion, concentrated in the dry season
Bangladesh supply
40 MW round the clock from June 2026; 148 GWh delivered in FY 2025/26
Controlling Indian instrument
CERC (Cross Border Trade of Electricity) Regulations 2019; Second Amendment notified 9 December 2025

Who gains and who pays

  • Nepal Electricity Authority (gains): NRs 29,314 million of export revenue in FY 2025/26 and a net export of 2,794 GWh.
  • Independent power producers (gains): Export demand absorbs wet-season surplus the domestic system cannot use, supporting continued PPA signing.
  • Nepali consumers and industry (mixed): Export revenue supports the tariff, but dry-season supply depends on imports priced on the Indian exchange.
  • Indian discoms in Haryana, Bihar and Uttar Pradesh (gains): 400 MW to Haryana and up to 200 MW to Bihar under medium-term agreements.
  • Nepal Power Trading Company Limited and private traders (costs): Licensed since 2022 but not yet operational; every approval still sits with NEA.

Implementation

Trade runs on four channels at once: government-to-government supply, the Indo-Nepal Power Exchange Committee mechanism, medium-term bilateral agreements with Haryana and Bihar, and day-ahead and real-time bidding on the Indian Energy Exchange through NVVN. NEA's Load Dispatch Centre at Syuchatar schedules the flows under the Nepal Electricity Grid Code and coordinates with Indian load dispatch centres over inter-control-centre protocol links and hotlines. Approvals are renewed and expanded through the Nepal-India Joint Working Group and Joint Steering Committee: the thirteenth JWG/JSC on 14-15 July 2026 set the combined capacity of the Dhalkebar-Muzaffarpur and Dhalkebar-Sitamarhi 400 kV lines at 1,650 MW for export and 1,400 MW for import, and approved the detailed project report for a new Nijgadh-Motihari 400 kV cross-border line. The Electricity Regulatory Commission has separately engaged a consultant to prepare a cross-border transmission study report under the South Asia Forum for Infrastructure Regulation. Government statements target export of up to 10,000 MW to India over ten years under a long-term arrangement; that headline is a policy commitment rather than a contracted quantum and should be read against the 1,200.01 MW actually approved.

Concerns

  • Single-counterparty risk: every megawatt of export and almost every megawatt of dry-season import depends on Indian approvals
  • Approvals are line-specific and revisable by the Power Exchange Committee rather than a standing entitlement
  • Exchange-linked export revenue is volatile and monsoon-dependent while NEA's costs are contracted and rupee-pegged
  • Nepal Power Trading Company Limited remains non-operational, so no competitive trading layer exists behind NEA
  • The advertised 10,000 MW long-term export figure runs far ahead of approved capacity and built interconnection
  • Bangladesh supply depends on Indian transit over the Dhalkebar-Muzaffarpur line and on trilateral renewal

Dates to watch

  • 2026-Q4: Commissioning of the Dhalkebar-Sitamarhi 400 kV line and of Butwal-Gorakhpur at interim 220 kV
  • 2027: Fourteenth Nepal-India Joint Working Group and Joint Steering Committee meeting on capacity allocation
  • 2027: Expiry window of the three-year Bihar medium-term agreement unless extended to five years

Sources

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PPA regime for hydropower IPPs · ERC Regulations 2076, 545 agreements for 12,135 MW and the move to competitive rates

Nepal · Electricity Regulatory Commission / Nepal Electricity Authority · regulation · 2019

Where it stands: Regulations 2076 in force; ERC consent required for every PPA; competitive bidding introduced for solar

Every Nepali power purchase agreement is signed by NEA as single buyer and needs the Electricity Regulatory Commission's consent under the Electricity Purchase-Sale and Licensee Conditions Regulations 2076. NEA now holds 545 PPAs totalling 12,135 MW with a further 277 applications for 16,344 MW in the queue, and has begun replacing administered rates with tariff-based competitive bidding, awarding 49 solar PPAs for 675 MW that way in FY 2025/26.

The problem

Nepal's independent power build was driven by an administered PPA: a published seasonal rate with a fixed number of escalations, offered to any licensed run-of-river project, with NEA obliged to take the energy. That produced 227 operating IPP plants and 3,459 MW of private capacity, but it also produced a queue NEA cannot absorb — 277 further applications for 16,344 MW — concentrated in wet-season run-of-river output the system already cannot use, and a power-purchase bill that grew 23.97 percent in one year to NRs 96,104 million while pre-tax profit fell to NRs 5,040 million. Successive pauses on new run-of-river PPAs, imposed when grid capacity and demand could not keep up, left developers holding survey licences with no offtake. The policy question is how to price energy whose marginal value swings by a factor of about thirteen between the dry-season peak and the wet-season off-peak when the contract prices it at a flat seasonal rate.

What it does

The ERC Act 2074 makes PPA pricing a regulatory act: until a wholesale market exists, the Commission fixes the rate and process of electricity purchase and sale between a distribution licensee and a generation or trading licensee, and separately consents to each agreement between licensees. The Electricity Purchase-Sale and Conditions to be Complied by Licensees Regulations 2076 set the standard terms and the schedules that govern them, and the Commission publishes its registers of hydropower and alternative-energy PPA consents through its document management system. NEA processes applications sequentially: document screening, technical review, a grid impact study leading to a grid connection agreement, PPA drafting and negotiation, NEA management approval, Electricity Regulatory Commission approval, then signature. In FY 2025/26 NEA signed 54 new PPAs — five hydropower projects totalling 28.595 MW and 49 solar projects totalling 675 MW, the solar volume selected through a tariff-based competitive bidding mechanism rather than an administered rate. That takes the signed book to 545 agreements and 12,135 MW, against 213 projects with 6,472.21 MW already under construction after financial close and 105 projects with 2,203.65 MW still awaiting it. Twenty-three IPP projects reached commercial operation during the year, adding 528.99 MW. The Commission is now rebuilding the cost basis underneath the rate: it has commissioned a Hydropower Generation Cost Benchmarking Study and a Hydropower Operational Cost Benchmarking Study, issuing data-call notices on 8 Falgun 2082 and 2 Baishakh 2083 and a reminder on 21 Shrawan 2083, and has published a discussion paper on storage hydro PPA pricing alongside the Reservoir Plant Electricity Purchase and Sale Directive 2082.

Market effect

Competitive procurement has already moved solar: 675 MW awarded in a single year against a signed solar book of about 140 MW beforehand, the fastest capacity addition by contract count in NEA's history, and priced against bids rather than a published rate. For hydropower the effect runs the other way. NEA's average power purchase cost of roughly NPR 6.07/kWh — NRs 96,104 million over about 15,822 GWh bought from subsidiaries, IPPs and India — sits far above the NPR 1.79/kWh annual marginal energy cost the Commission's own LRMC study computes, because the contracts pay a seasonal average for energy that is worth almost nothing in the wet-season off-peak. With exports absorbing 3,965 GWh and generating NRs 29,314 million of revenue, NEA can monetise the surplus today, but every additional flat-priced run-of-river PPA lengthens that exposure. Audited generation and operating cost benchmarks are the precondition for moving hydropower onto competitive or cost-plus rates and for pricing storage and peaking energy separately from run-of-river. For developers the near-term signal is unambiguous: solar and storage get contracts, unbuilt run-of-river sits in a 16,344 MW queue.

Key numbers

Signed PPA book
545 agreements totalling 12,135 MW (FY 2025/26)
Applications in process
277 PPA applications totalling 16,344 MW
Competitive solar awarded FY 2025/26
49 PPAs, 675 MW, by tariff-based competitive bidding
NEA power purchase cost
NRs 96,104 million in FY 2025/26, up 23.97 percent; about NPR 6.07/kWh average
Construction pipeline
213 projects / 6,472.21 MW post financial close; 105 projects / 2,203.65 MW awaiting it

Who gains and who pays

  • Solar developers (gains): 49 competitive PPAs for 675 MW in FY 2025/26; a live procurement route rather than a queue.
  • Run-of-river hydropower developers in the application queue (costs): 277 applications for 16,344 MW with no assured offtake and a shift away from administered rates.
  • Nepal Electricity Authority (obligation): Single buyer for all 545 PPAs; power purchase cost rose 23.97 percent to NRs 96,104 million in one year.
  • Project lenders and HIDCL-led consortia (mixed): A PPA plus ERC consent is the bankability test; competitive rates compress equity returns.
  • Consumers and export buyers (gains): Competitive rates and cost benchmarking put downward pressure on the power-purchase component of tariff.

Implementation

Consent applications are filed with the Commission and tracked publicly through its document management registers for hydropower and alternative-energy PPA consents. NEA's Power Trade Department administers the agreements before and after commercial operation. The two benchmarking studies are the live workstream, and the repeated reminder notices are a signal that licensee cooperation has been uneven. A separate Commission discussion paper on storage hydro PPA pricing and the Reservoir Plant Electricity Purchase and Sale Directive 2082 are intended to produce a differentiated rate for storage and peaking energy. NEA has also asked the Commission to approve a memorandum of understanding releasing 100 MW of power and transmission capacity to Nepal Power Trading Company Limited for onward sale in the cross-border market, which would be the first PPA volume in Nepal sold by anyone other than NEA.

Concerns

  • A 16,344 MW application queue against a system that already exports its wet-season surplus
  • Flat seasonal PPA rates that ignore a roughly thirteenfold seasonal swing in marginal energy value
  • NEA's power purchase bill growing faster than revenue while pre-tax profit falls
  • Cost benchmarking dependent on licensee data that has required repeated reminder notices
  • No wholesale market, so a PPA with NEA remains the only bankable offtake for a domestic project
  • Competitive bidding proven so far only on solar, not on hydropower or storage

Dates to watch

  • 2027: Completion of the hydropower generation and operational cost benchmarking studies
  • 2026-Q4: ERC decision on NEA's memorandum releasing 100 MW to Nepal Power Trading Company Limited
  • 2027: Next round of tariff-based competitive bidding for grid-connected solar

Sources

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