Glossary
A
A time-weighted average across the scenario timeframe. It is calculated by summing the price for every interval and dividing it by the total number of intervals.
The price at a particular interval multiplied by the generation or the load (demand) at that interval for a specific object. These values are summed and then divided by the total volume across the entire scenario timeframe.
The proportion of time a plant is available to operate during a scenario timeframe. It is calculated by dividing the capacity available over a period by the total potential capacity. For example, a plant on maintenance for 2 days out of 10 would have 80% availability. A plant is considered available if it has a bid and is not on outage.
A polynomial curve representing the cost to generate energy at different capacity levels. In the database, this corresponds to SRMC0 (100%), SRMC1 (80%), SRMC2 (60%), and SRMC3 (40%) capacity values. Values are interpolated for intermediate capacity levels.
B
A model run that uses historical data to test how well a forecasting method would have predicted past outcomes.
C
A measure of actual energy generated compared to the potential maximum energy that could have been produced if the plant ran at full capacity for the entire period. It is calculated as total energy generated divided by (Installed Capacity x Total Time Period). Always calculated across the whole scenario time period.
The annual money paid to a bank to pay off debt for the installation of a power station. In reports, this annual figure is prorated based on the number of days in the simulation scenario. Stored in the database as Philippine Pesos per kilowatt per year.
The cost of CO2 emissions calculated by multiplying the CO2 emission intensity factor by the energy generated and then by the carbon price (tax) defined in the scenario parameters. Typically around $25 per ton depending on carbon trading.
A database field representing the carbon emission intensity factor for a site. This value is multiplied by the energy generated and the carbon price to calculate carbon costs.
D
The total load or demand for a region or specific load object (like pumped storage) for the duration of the scenario timeframe.
F
An estimate of future electricity price, demand or generation based on historical data, trends, and predictive models.
Annual costs for maintaining the plant that do not change based on energy production. Like capital charges, these are prorated for the scenario period. This is a site-level cost.
Calculated by multiplying the amount of energy produced by the coal consumption rate (tons per MW). The coal consumption is a function of the megawatt output.
G
The calculated price at the generator site. It is derived by taking the regional price and multiplying it by the Marginal Loss Factor (MLF) of that particular site.
The total energy produced by a unit or site during the scenario timeframe.
H
The actual electricity market data in the past, used as a baseline for analysis and comparison with forecasts.
I
The sum of the maximum capacity ratings (MW Max) for all units or stations operating in a given year. This information is pulled from the system database.
L
The Real-Time Dispatch (RTD) price used in historical datasets. In the LESA system, it is called LMP; in AMO, it is referred to as the Regional Reference Price (RRP).
A measure of the 'flatness' or 'peakiness' of the generation or demand profile. It is the area under the actual generation curve (numerator) divided by a square area based on the maximum recorded generation point (denominator). A value of 100% means the profile is perfectly flat. A low load factor indicates a peaky plant; a high load factor indicates flat generation.
M
The rating of the actual generating machine. This is the capacity at the terminal of the generating set before internal loads are subtracted. The effective sent out capacity is typically lower (e.g., a 350 MW unit may have 321 MW sent out).
A factor used to adjust regional prices to site-specific prices. When calculating the Generator Weighted Average Price (GWAP), the regional price is multiplied by the MLF of that particular site.
N
The difference between generation and demand. A positive value indicates the region is exporting energy, while a negative value indicates it is importing. Displayed as generation minus demand.
A count of every instance a unit goes on an outage and then returns to service. Each time it goes offline and comes back online counts as one start.
O
Revenue streams that are not part of the energy market, such as contract-based revenues.
P
The earnings a station receives from the energy market pool based on its generation. It is calculated by multiplying the volume-weighted price by the actual energy generated.
The financial summary calculated by adding up all costs (capital charge, fixed O&M, variable O&M, supply costs, carbon costs, startup costs) and comparing them to pool revenue. Some costs are site-level while others are unit-level.
R
The term used in AMO (Australian Market Operator) for the Locational Marginal Price. This is the RTD price for a region.
S
A price metric that differs slightly from the LMP. While LMP represents the price for a whole region, the System Marginal Price (SMP) is specific to a particular node.
The energy that actually exits the power station gate and enters the transmission line. In plants like coal stations, a portion of the generated energy (roughly 7%) is used internally to power auxiliary equipment like pumps and fans; 'Sent Out' is the net energy after these internal loads are subtracted.
The cost to generate energy at different capacity levels, calculated using an average cost curve. In the database, this is represented by polynomial values (SRMC0, SRMC1, SRMC2, SRMC3) corresponding to costs at 100%, 80%, 60%, and 40% capacity respectively. This is a unit-level cost.
The cost incurred to bring a unit back online after an outage. This cost is dependent on how many hours the unit was offline; iPool tracks offline hours and applies different costs (SEC5, SEC20, SEC50) for different durations. Primarily relevant for coal and CCGT plants due to expensive boiler heating.
Costs that are only applicable at the site level, not at individual units. These include Capital Charge, Fixed O&M, and Transmission Network Service Charge. When summed, these contribute to the total site cost.
T
An annual fee paid for the use of the transmission network. This is a site-level fixed cost that is prorated based on the scenario duration.
U
Costs calculated at the individual unit level, such as Supply Cost (SRMC). These are aggregated to the site level by summing all unit costs.
V
Maintenance costs that are proportionate to the amount of energy produced (Pesos per MWh sent out). This covers consumables used for maintaining the plant, such as cleaning or replacing parts like ball bearings.
W
Hypothetical cases used to explore the impact of different assumptions or conditions on demand, generation, or system performance.