Cross-Border Power Trade in Nepal: Bottlenecks and a Suitable Trading Framework

1. Bottlenecks in Regional Energy Trade (8 marks)

Nepal has moved from a net importer to a seasonal net exporter of electricity, but the transition to a full-fledged regional power trader is constrained by several bottlenecks:

A. Physical and technical bottlenecks

1. Limited cross-border transmission capacity. Existing interconnections with India (Muzaffarpur–Dhalkebar 400 kV, Kusaha–Kataiya 132 kV, Raxaul–Parwanipur 132 kV, Tanakpur–Mahendranagar 132 kV, etc.) are inadequate to evacuate surplus wet-season energy. The Dhalkebar–Muzaffarpur line is often constrained, and the under-construction Butwal–Gorakhpur 400 kV and other lines are delayed.
2. Weak internal transmission backbone. Congestion in the East–West Kaligandaki corridor and inadequate substation capacity mean generation cannot always reach the border points.
3. No dedicated Nepal–Bangladesh link. Bangladesh access depends on Indian territory and Indian approval (tripartite arrangement), making it politically and commercially conditional.
4. Grid stability and ancillary services. Variable run-of-river generation, limited spinning reserve and weak frequency control restrict firm, round-the-clock export commitments.

B. Market and regulatory bottlenecks 5. Absence of a competitive domestic market. Nepal Electricity Authority (NEA) remains the single buyer/seller; there is no wholesale power exchange, so IPPs cannot directly access foreign markets. 6. Restrictive Indian market access. Cross-border trade is governed by the Indian Electricity Grid Code and CBET (Cross-Border Electricity Trade) Guidelines, 2016 (amended 2021), which require Indian entity participation, restrict trading margins, and make access to the Indian Energy Exchange (IEX) conditional. Only surplus energy from already-committed plants is tradable. 7. One-sided pricing and no firm long-term contracts. Exports are largely wet-season surplus sold at low, volatile prices, while dry-season imports are costly — an adverse seasonal price asymmetry. 8. Settlement and payment risk. Transactions are routed through Indian banking and scheduling systems; delayed payment and currency (INR) settlement risk discourage IPPs.

C. Institutional and policy bottlenecks 9. Weak bilateral legal instruments. Nepal–India power trade rests on the 2014 Power Trade Agreement and administrative guidelines, but these lack firm provisions for non-discriminatory open access and binding dispute resolution, and there is no equivalent trilateral instrument with Bangladesh; Mahakali Treaty provisions also remain largely unimplemented. 10. Limited harmonization. Differences in grid codes, protection standards, metering, communication protocols and licensing between Nepal, India and Bangladesh create interoperability problems. 11. Inadequate dispute resolution mechanism. No dedicated bilateral or regional arbitration framework for power trade disputes; recourse is to ad hoc negotiation or foreign courts. 12. Institutional capacity. Electricity Regulatory Commission (ERC) and NEA lack full market-operation, forecasting and scheduling capability; IPP participation in cross-border trade is not clearly provided in law.

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2. Suitable Cross-Border Power Trading Framework (12 marks)

A workable framework should rest on five pillars: market access, scheduling, transmission access, dispute resolution and harmonization, with IPPs as legitimate participants.

2.1 Legal and institutional foundation

• Enact a Cross-Border Electricity Trade Act empowering ERC to license exporters/traders and to approve bilateral and trilateral contracts.
• Designate NEA (or a separate Market Operator) as the National Power Trading Company / Single Buyer initially, transitioning to a Nepal Power Exchange in the medium term.
• Create a Joint Cross-Border Coordination Committee (Nepal–India; later Nepal–India–Bangladesh) for operational and regulatory coordination.

2.2 Market access for IPPs

1. Direct participation: IPPs holding a generation licence and meeting technical/financial criteria may be granted a trading licence to export directly or through an aggregator.
2. Aggregation model: Small IPPs pool capacity through an authorised aggregator/trader to meet minimum contract sizes (e.g., 50–100 MW blocks) required by Indian exchanges.
3. Access routes:
   • Bilateral contracts with Indian discoms/traders under CBET Guidelines;
   • Participation in IEX / Real-Time Market through an Indian trading licensee;
   • Trilateral Nepal–India–Bangladesh contracts (e.g., the 2024 40 MW Nepal–Bangladesh export via Indian grid);
   • Future BBIN / SAARC market participation.
4. Non-discriminatory open access to cross-border transmission on payment of regulated wheeling charges, with priority for firm long-term contracts.

2.3 Scheduling framework

• Adopt a day-ahead and real-time scheduling regime aligned with the Indian grid (15-minute time blocks).
• Scheduling entities: each IPP/trader submits a day-ahead schedule to the National Load Dispatch Centre (NLDC), which reconciles it with the Indian RLDC through the Joint Coordination Committee.
• Deviation settlement: apply a frequency-linked deviation settlement mechanism (DSM) with a dead band (e.g., ±0.05 Hz) and graded penalties to discourage over/under-injection.
• Metering and communication: install interface meters at border substations with remote telemetry to both NLDC and RLDC; data used for energy accounting and settlement.
• Dry-season management: reserve contracted capacity for domestic supply first; export only certified surplus, with a reserve margin (e.g., 10–15%) maintained.

2.4 Transmission and open access

• Fast-track 400 kV cross-border lines (Butwal–Gorakhpur, Inaruwa–Purnia, Dodhara–Chandani) and dedicate capacity for trade.
• Introduce transmission access regulations specifying priority, curtailment rules and compensation for curtailment of firm contracts.
• Allow merchant transmission by IPPs/private investors under ERC licence to reduce the financing burden on NEA.

2.5 Dispute resolution mechanism

• Tiered approach:
  1. Negotiation between parties within 30 days;
  2. Mediation by the Joint Coordination Committee;
  3. Arbitration under UNCITRAL Rules, seat in Kathmandu or a neutral SAARC location, governed by Nepali law for domestic contracts and by the agreed governing law for cross-border contracts;
  4. Enforcement through the New York Convention, 1958 (Nepal is a signatory) for recognition of foreign awards.
• Include model Power Purchase Agreement (PPA) and model Transmission Service Agreement clauses on force majeure, change in law, and tariff adjustment to pre-empt disputes.
• Establish a Regional Power Trade Dispute Settlement Panel under the Joint Committee for technical and commercial disputes.

2.6 Harmonization of grid codes

• Adopt IEC and SAARC/BBIN standards for frequency (50 Hz ± 0.5%), voltage, protection, and communication protocols.
• Harmonize licensing, metering, and settlement cycles (weekly/monthly) across Nepal, India and Bangladesh.
• Develop a common scheduling and accounting platform (e.g., a regional SCADA/EMS interface) and mutual recognition of test certificates for equipment.
• Align with SAARC Framework Agreement for Energy Cooperation (2014) and BBIN Motor Vehicles/Energy initiatives for institutional backing.

2.7 Implementation roadmap

Conclusion

Nepal's transition from a seasonal surplus seller to a competitive regional power trader requires legal empowerment of IPPs, adequate cross-border transmission, a transparent scheduling and DSM regime, a credible arbitration framework, and harmonized grid codes. These measures will convert Nepal's hydropower potential into durable economic and diplomatic advantage.