Technology choice in a least-cost expansion analysis framework: Implications for state regulators Page: 4 of 29
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2.0 Analysis Framework
2.1 Methodology
The WASP Package uses dynamic programming to develop a least-cost
optimization plan for a period of up to 30 years, on the basis of user-supplied constraints
such as the cost of unserved energy, reserve margin limits, and a loss-of-load probability
(LOLP). In WASP, the optimal solution is the minimum discounted system, costs over
the study period. The system costs include the capital investment for new units, the
salvage value associated with new units, fuel costs, operation and maintenance (O&M)
costs, and the cost of energy not served. WASP evaluates these components in terms of
their net present value to compare the cost of alternative system expansion plans. The
model uses probabilistic simulation to calculate the system production costs and reliability
level.2'3
2.2 Model Constraints
Constraints were imposed to bound the simulation problem and ensure a realistic
solution. The reserve margin for each pool was constrained to be between 15% and 25%.
The level of reserve margin maintained within a pool is determined by the model in
conjunction with the amount and cost of unserved energy. No LOLP constraint was
imposed (although it was examined in each simulation for reasonableness). WASP
calculates the financial tradeoff between building new generating units or paying a cost
for each kilowatt-hour (kWh) of unserved energy. Unserved energy was assigned a cost
of $0.10/kWh. There were no constraints imposed on the number of new units that could
be added in any year. In addition, each new technology was considered to be available
and fully functional starting January 1, 1995.
2.3 Input Data Sources
The data requirements for WASP fall into two basic categories, load data and unit
data.
Load Data. The load data requirements are seasonal load duration curves and
seasonal and annual peak loads. The annual peak loads for each pool were selected from
the 1988 regional North Electric Reliability Council reports for the years 1995-1997. The
annual peak loads beyond 1997 were assumed to increase at 1.9% per year in each pool
until the end of the study based on a national electricity demand forecast.4
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Guziel, K.A. & South, D.W. Technology choice in a least-cost expansion analysis framework: Implications for state regulators, article, January 1, 1990; Illinois. (https://digital.library.unt.edu/ark:/67531/metadc1104481/m1/4/: accessed July 18, 2024), University of North Texas Libraries, UNT Digital Library, https://digital.library.unt.edu; crediting UNT Libraries Government Documents Department.