Oahu Wind Integration Study - Hawaii Natural Energy Institute ...

decisions). The commitment of units is the selection of units, a day or week in advance, which
must operate in the future hour of interest. The dispatch of units is the power output of these
committed units in a given hour required to meet the load at that instant. The commitment and
dispatch decision depends on many variables, including the cost of each generator, the
capabilities of the transmission system, and startup constraints on cycling units, as an example.
The model includes representation of the HECO transmission system and relevant characteristics
of each generating unit, such as the maximum and minimum power output, heat rate (thermal
efficiency) as a function of production level, emissions, minimum downtime between starts,
start-up costs, operating constraints, and maintenance and forced outages.
Production cost modeling of the HECO system was performed with the GE’s Multi Area
Production Simulation (MAPS TM ) software program. This commercially available modeling tool
has a long history of governmental, regulatory, independent system operator and investor-owned
utility applications. This tool was used to simulate the HECO production for 2007 as part of the
baseline model validation process. Later, the model was used to forecast the Oahu power system
for the year 2014. Ultimately, the production cost model provides the unit-by-unit production
output (MW) on an hourly basis for an entire year of production (GWh of electricity production
by each unit). The results also provide information about the variable cost of electricity
production, emissions, fuel consumption, etc.
The overall simulation algorithm is based on standard least marginal cost operating practice.
That is, generating units that can supply power at lower marginal cost of production are
committed and dispatched before units with higher marginal cost of generation. Commitment
and dispatch are constrained by physical limitations of the system, such as transmission thermal
limits, minimum spinning reserve, stability limits, as well as the physical limitations and
characteristics of the power plants. Significant input was received from HECO and multiple
model refinement iterations were performed in order to capture the nuances of the HECO
system.
The price that HECO pays to an independent power producer (IPP) for energy is not, in general,
equal to the cost of production for the individual unit, nor are they equal to the systemic marginal
cost of production. Rather, they are governed by power purchase agreements (PPAs). The price
that HECO pays to IPPs for energy purchase was reflected in the simulation results insofar as the
conditions of the PPAs can be reproduced. This was done in conjunction with the HECO team
by modeling the AES and Kalaeloa units based on heat rate curves that reflect the cost of their
production. The costs of purchasing power from HPower (today and in the future), Honua
(future), and OTEC (future) were not captured in the model.
The primary source of model uncertainty and error for production cost simulations, based on the
model, consist of:
o Minimum spinning reserve rules are included. Losses are considered in prioritizing
dispatch. Each of these types of constraints in the model may be somewhat simpler than
the precise situation dependent rules used by HECO.
o Marginal production-cost models consider heat rate and a variable O&M cost. However,
the models do not include an explicit heat-rate penalty or an O&M penalty for increased
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