Hydropower Engineering

Site selection criteria for a hydroelectric power project

Selecting a site for a hydroelectric project is a multi-disciplinary decision. A site that looks attractive hydraulically may fail on geology, economics, or social grounds. The parameters examined during feasibility study are grouped below.

1. Hydrological parameters

• Streamflow (discharge): Long-term flow data (usually 10–30 years) to establish Q40, Q65, dry-season flow, and flow duration curve. Firm capacity depends on lean-season flow.
• Catchment area and rainfall/snowmelt: Determines runoff volume and its seasonal pattern.
• Head: Gross head from topographic survey; net head after losses. Power potential P = ρgQHη, so both Q and H matter.
• Flood magnitude: Design flood (e.g., 1-in-100 or 1-in-1000 year) for spillway and protection works.
• Sediment load: Affects desilting basin design and turbine wear, especially in Nepal's young, erodible Himalayan terrain.

2. Topographical parameters

• Steep gradient over a short distance (high head per unit length of canal/tunnel).
• Availability of a natural drop, gorge, or bend that can be cut by a headrace tunnel.
• Suitable site for diversion weir/barrage and for a forebay and powerhouse on stable ground.
• Accessibility of the site by road for transporting heavy equipment (turbines, generators, transformers).

3. Geological and geotechnical parameters

• Competent bedrock for dam/weir foundation; absence of faults, shear zones, and landslide-prone slopes.
• Tunnel alignment through stable rock; low risk of squeezing, water ingress, or slope failure.
• Seismic zone consideration — most of Nepal lies in high seismic hazard zones.
• Slope stability at powerhouse, penstock, and switchyard locations.

4. Hydrological and environmental flow requirements

• Minimum environmental/ecological release downstream to protect aquatic life and downstream users.
• Impact on downstream water rights, irrigation, and drinking water supply.

5. Socio-economic and resettlement parameters

• Number of households affected, land acquisition requirements, and resettlement/rehabilitation cost.
• Impact on local livelihoods, cultural and religious sites, and community acceptance (social licence to operate).
• Benefit-sharing and local employment potential.

6. Infrastructure and grid parameters

• Distance to the nearest transmission line or substation and cost of evacuation infrastructure.
• Availability of access roads, construction power, water, and communication.
• Proximity to load centres or to the national grid.

7. Economic and financial parameters

• Cost per MW and per kWh of energy generated; benefit–cost ratio, IRR, and payback period.
• Comparison of alternatives (run-of-river vs. storage, different headrace alignments) to select the least-cost option.
• Tariff and energy market conditions, including dry-season/wet-season energy value.

8. Legal, policy, and institutional parameters

• Compliance with the Electricity Act, Water Resources Act, Environment Protection Act, and IEE/EIA requirements.
• Availability of a water use licence, land use clearance, and forest clearance.
• Consistency with national energy policy and provincial/local government plans.

9. Technical and operational parameters

• Suitability of the site for the chosen type of scheme (run-of-river, storage, pumped storage).
• Ease of construction, availability of construction materials (aggregate, sand) nearby.
• Operation and maintenance accessibility, and safety against natural hazards (GLOF, landslide, earthquake).

Conclusion A hydro site is selected only after a comparative feasibility study of alternatives, weighing hydrological potential, geological safety, environmental and social acceptability, grid access, and financial viability. In Nepal, where terrain is young and seismically active, geological and sediment-related parameters often become the deciding factors, while resettlement and environmental flow requirements increasingly determine project viability.

Introduction

Transmission lines carry electricity from power plants to load centres. In Nepal, delayed lines leave completed plants unable to evacuate power. Developers then pay interest on loans without earning revenue, deemed-generation and take-or-pay disputes arise, and domestic supply and per capita consumption (about 400 kWh) stay low. Most of the delays come from local issues on the ground, not from engineering.

Key local issues and critical analysis

1. Land acquisition and compensation

• Tower pads and substations need land under the Land Acquisition Act 2034, and the compensation rates fixed by the Compensation Fixation Committee often differ greatly from market value.
• Owners dispute rates, and the process of notice, valuation and payment is slow.
• Critical view: for tower pads the permanent loss is small, but disputes over it hold up the whole line, and a single unresolved tower stops the entire span.

2. Right-of-way (corridor) and crop and tree damage

• Under the Electricity Act 2049, the licensee may use land for the line, and the owner receives compensation for damage but keeps ownership.
• Landowners do not accept restricted use under the line and demand full land purchase.
• Standing crops and trees are valued inconsistently.
• Informal settlements and encroachment in the corridor complicate clearance, especially in the Terai and urban fringe.

3. Local resistance, obstruction and demands

• Communities, local leaders and sometimes political groups obstruct work and demand jobs, local contracts, donations or free electricity.
• Threats of bandh and stoppages cause long idle periods, and security support is irregular.
• Critical view: resistance usually shows that people were not consulted early and see no benefit, so it is mostly a trust problem and not an opposition to development.

4. Forest, protected area and environmental clearance

• Crossing national forest, community forest, buffer zones or protected areas needs approval under the Forest Act 2076, the National Parks and Wildlife Conservation Act 2029 and the Environment Protection Act 2076 (IEE or EIA).
• Approvals pass through many offices, and tree-felling permits and the replacement planting requirement (usually 25 saplings for each tree) take long.
• Critical view: the rules are justified, but sequential approvals instead of a joint process cause the delay.

5. Compensation and rehabilitation delays

• Late payment, lack of funds with the utility, and disputes over who is eligible (tenants, squatters) provoke further protest.
• Compensation for houses near the corridor, safety clearance and loss of use is poorly defined.

6. Multiple and disputed ownership

• Fragmented plots, absent owners, unregistered land and joint ownership make notice and payment difficult.

7. Coordination and institutional weaknesses

• The Ministry of Energy, Water Resources and Irrigation, the Ministry of Forests, local governments, District Administration Offices, the Land Revenue Offices and NEA do not work to a shared timetable.
• Local governments, now with their own powers under the Local Government Operation Act 2074, sometimes impose their own fees or conditions.
• Contractor performance, poor design changes and difficult terrain add to the delays.

Remedial measures based on current legal provisions

Further reforms include amending the Electricity Act so evacuation lines have a clear priority and time-bound approvals, and involving the Electricity Regulatory Commission in allowing the costs of delays and in compensating developers fairly where the delay is caused by the utility.

Conclusion

The delay in transmission lines is caused chiefly by land and right-of-way disputes, weak community engagement, slow clearances and poor coordination, not by technical problems. The existing laws are adequate in outline but are applied slowly and inconsistently. Early engagement, fair and timely compensation, parallel clearances, and one lead agency accountable for the corridor can free the evacuation of power, save developers from financial loss and raise domestic consumption.