2008年-世界发展银行全球_Review_of_Power_System_Expansion_Planning_in_Vietnam_13页_599kb

Summary of Power System Expansion Planning in Vietnam

1. Introduction

This report evaluates current power system expansion planning practices in Vietnam, focusing on technical aspects and recent planning studies. It includes an overview of load forecasting, planning guidelines, computational tools, and generation expansion plans. The report also proposes sensitivity scenarios to assess the viability of specific projects such as the Trung Son hydro and Nghi Son thermal projects.

2. Load Scenario

• Load Forecasting: Conducted in two steps:
  • Short-term (2006–2010): Based on regional projections derived from industrial development, infrastructure investments, and household consumption.
  • Mid-term (2011–2025): Uses elasticity coefficients that relate electricity consumption to GDP growth. These coefficients are expected to decrease over time due to economic growth and changing consumption patterns.
• Elasticity Coefficients: Table 3.1 outlines the assumptions for GDP and load growth rates, with elasticity decreasing from 1.88 in the first period to 1.00 in the last period.
• Peak Load Forecasting: Assumes a stable daily load shape, with Figure 3.1 showing the growth rates for the base scenario.
• Consultant's Opinion: A more sophisticated load forecasting scheme is difficult to implement due to data limitations and the rapid transformation of the economy. The current approach clearly outlines exogenous assumptions.

3. Planning Guidelines and Practices

3.1 Planning Guidelines

• Regional Balance: Power generation should be developed proportionally in the North, Center, and South regions, ensuring both regional and national system reliability.
• Diversification: Prioritize development of gas-fired plants in the South, hydropower (especially multipurpose), and coal-fired plants in the North.
• Imported Power: Encourage power imports from Laos, Cambodia, and China, especially hydro plants, to reduce fossil fuel dependence and CO₂ emissions.
• Renewables: Support small hydro (≤30 MW), wind, solar, biomass, and geothermal projects.
• Construction Delays: Account for delays by including an extra reserve capacity margin.
• Ownership and Market: EVN will manage key projects like Son La and nuclear, while other plants will be managed by JSC, private sector, and foreign investors. A competitive market is to be developed gradually.
• Cost Minimization: The objective is to minimize the present value of investment and operation costs while ensuring supply reliability.

3.2 Planning Practices

• Limited Options: Generation planning in Vietnam has limited degrees of freedom due to government-defined projects (e.g., MoUs) and regional constraints.
• Hydro Projects: Relies heavily on studies from construction companies, with limited detailed data on hydro inflows, storage, and operating characteristics. Instead, data is summarized using quantiles.
• Fuel Prices: Coal and natural gas prices used in planning are lower than international levels, likely due to government control and coordination issues between sectors.
• Fuel Security: Projects using imported coal require 15-year firm fuel contracts.
• Dynamic Programming (DP): Used to determine the least-cost expansion plan. It works well for thermal plants but is less effective for hydro due to non-modular characteristics.

4. Planning Objective and Computational Tools

• Least-Cost Planning: The primary objective is to minimize the present value of investment and operation costs, subject to reliability constraints.
• Computational Tools:
  • Production Costing: Uses probabilistic simulation to estimate operation costs, considering generation availability, hydro inflows, and load levels. Tools include WASP III, Strategist, and PDPAT 2.
  • Reliability Evaluation: Calculates supply reliability indices such as LOLH (Loss of Load Hours). The current target is ≤24 hours per year.
  • Least-Cost Expansion Plan: DP is used, but hydro projects are pre-ranked based on cost-benefit indices, which may not yield optimal results.

5. Generation Expansion Plan

5.1 Assessment Criteria

• Stability of Reserve Margin: Should remain relatively stable over time, with the base case showing stabilization around 35% after initial years.
• Supply Reliability Indices: LOLH should be consistent across regions and years. In the base case, the North region meets the target, while the South region often exceeds it, and the Central region shows zero LOLH.
• Equality of Marginal Costs: Short-run marginal cost (SRMC) should equal long-run marginal cost (LRMC) in the optimal plan. In the base case, SRMCs for the North and South are balanced, but the Central region shows anomalies.

6. Sensitivity Scenarios

• Fuel Price Escalation: The first sensitivity scenario considers increased coal and natural gas prices (80 US$/ton and 7 US$/MMBTU respectively), which may improve the competitiveness of hydro projects.
• Project Entrance Dates: The second and third scenarios fix the Trung Son hydro and Nghi Son thermal projects at their earliest possible dates and compare the total cost with the reference plan.
• Construction Delays: The fourth scenario evaluates the impact of one-year delays in plant construction on the optimal plan, affecting both reliability and production costs.

7. Conclusions

• Computational Tools: The tools used for production costing and reliability evaluation are well-established, but their accuracy in representing hydro and wind power needs validation.
• Modeling Inaccuracies: The current use of analytical convolution for hydro and wind may not capture optimal operation policies or chronological variations, which could affect the economic evaluation of generation sources.
• Dynamic Programming: Effective for thermal plants but may not yield optimal results for hydro due to pre-ranking based on cost-benefit indices.
• Recommendations:
  • Validate current modeling approaches using chronological hydrothermal simulation tools.
  • Consider more realistic construction timelines in planning studies.
  • Reassess the competitiveness of hydro and thermal projects under new fuel price assumptions.