PUB00037

• Year: 1988
• Title: Colorado Joint Planning Study Economic Potential of Pumped Storage
• CWCB Section: Interstate & Federal
• Author: Colorado Water Resources and Power Development Authority
• Description: Assessment of whether pumped storage facilities are economically attractive to Colorado utilities
• Publications - Doc Type: Water Resource Studies

I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I

(NDT) which is dependent on the time of day, wind speed, solar intensity, or is
correlated with customer's steam demand. The next two types are purchases and
sales, where the demand and energy may be scheduled on an hourly, monthly, or
time-of-use basis, and price is specified for each of these transactions.

Each generating unit of the utilities in the study was modeled as one of these six types
of units. Operating, emergency, and reserve capacities were modeled for each
generating unit. Two additional factors affected the modeling of the individual
generating units: the percentage of the unit owned by the utility being modeled and an
option for NDTs where units can be grouped together. Other input data needed to
model each unit included heat rate curves, loading blocks, forced outage rates,
maintenance schedules, design capacity factor, energy limitations, storage efficiency,
charging capacity (storage units). and utilization factors.

Costs associated with generating units are divided into two categories: fixed and
variable. Fixed costs include capital installation costs, levelized carrying charges, and
fixed operation and maintenance costs. Variable costs represent the direct expenses
of generating energy, including fuel costs and variable operation and maintenance
costs. Actual production cost information was used for existing generating units. For
planned units, cost data were taken from the utilities' existing expansion plans. For
alternative expansion plans, including those using pumped storage, generic plant
characteristics and cost data were used. (Assumptions for the pumped storage
facilities are provided in Section 2.4.)

For the base case analyses, future generation facilities that would meet load growth
and reserve requirements at the lowest cost were identified. Currently planned
additions were utilized first in the program's selection of alternatives. Using a dynamic
program algorithm that evaluated thousands of different combinations of alternatives
over the study period through comparisons of cumulative present worth values, the
EGEAS program then optimized the mix of types of future generation resources to
select the most economic expansion plan. For each year the model computes the total
annual system costs (fixed capacity costs--cost of money, depreciation, income taxes,
property taxes and insurance--related to future plant investments, fixed and variable
operation and maintenance costs, and fuel costs). Financial criteria, load forecasts,
planned generation resources, heat rates, (a measure of a thermal power plant's
efficiency), fuel costs and other pertinent data were carefully treated to assure
consistency with actual conditions and practices in Colorado. In constraining the
2-2