Trading Arrangements in Power Pools Model Structure & Data

07/08/2003 1

Trading Arrangements Trading Arrangements in Power Poolsin Power Pools

Model Structure & DataModel Structure & Data

Brian H. BowenF.T. Sparrow

Geoff GranumPower Pool Development Group

Purdue University, U.S.A

South Asia Regional Initiative in Energy Training ProgramJuly 19-23, 2003, Dhaka Bangladesh

Purdue University07/08/2003 2

Electricity Trade ModelingElectricity Trade Modeling

Long TermModel

Inputs Outputs

Capital CostsFuel CostsHeat RatesLine Losses

Generation Capacities

Cost SavingsOptimal ExpansionsTrade TariffsWheeling EffectsReserve Margin Planning


ShortShort--Term and LongTerm and Long--Term Term ModelingModeling

Short-term (ST) modeling (fixed generation capacity) can be for almost any length of time less than 12 months. It can be a period of hours, days, weeks, or months. Long-term (LT) modeling (capacity expansions) is normally referring to several years. LT models are typically anywhere between 5 years and 20 years.


Electricity Forecasting PolicyElectricity Forecasting Policy

Across the United States and in the industrialized nationals generally a growth rate of about 2% is typical. In the developing economies the growth rates are often quoted as being double or triple this 2% growth rate and even more. Enormous planning differences occur over a 20 year planning horizon with different rates of 4%, 8%, and 12% are used: 1.0220 = 1.48, 1.0420 = 2.19, 1.0820 = 4.66, 1.1220 = 9.64


Electricity Trading CommoditiesElectricity Trading Commodities

The Purdue long-term electricity trade model (PLTETM) trades in two commodities:

a.) Megawatt reserve power (MW)b.) Megawatt hour energy (MWh)


Supply, Demand and Shipment Supply, Demand and Shipment (Existing and Proposed)(Existing and Proposed)

The Purdue electricity and gas trade models optimize the minimum cost to meet the demands for electricity and natural gas within one region over a long-term horizon (e.g., 20 years). The region consists of several or more countries (indexed as z or zp). Normally each country is modeled as one node. Free trade is permitted to take place between all of the countries in the specified region.

Figure 4.1 Training Model with Peak Demand (D) & Existing Generation (PG, CC, H) for Each Country

Boundary of regionfor power pool

Country 1D = 3000PG(1A) = 1200PG(1B) = 1600-2500(NH(1C) = 300-900NH(1D) = 600GT(1E) = 800)

Country 2D = 500PG(2A) = 550Country 3

D = 300PG(3A) = 260(GT(3B) = 600)

Country 4D = 1000PG(4A) = 500PG(4B) = 1200-2600(CC(4C) = 300-2100GT(4D) = 300)

Country7D = 400H(7A) = 450(NH(7B) = 200-600)

Country 6D = 300H(6A) = 600(NH(6B) = 150-900)

Country 5D = 2000PG(5A) = 2400(CC(5B) = 350-2800)

Key (all values in MW):D = Electricity DemandPG = Old thermal/oil generationCC= Old Combined Cycle generationH = Old hydropower generation

All electricity annual demand growth rates are set at 4% for each country

(Italicized values are proposed capacity expansions

Proposed new gas turbine station capable of expansion up to 600MW with a variable cost of $0.3m/MW. Fuel $6/106Btu

GT(1E)

Proposed new hydro station of 600MW with a fixed cost of $850m

NH(1D)

Proposed new hydro station of 900MW with fixed cost $600m for the first 300MW and then a variable cost of $0.9m/MW

NH(1C)

Existing thermal station, 1600MW (expansion is possible up to 2500MW, costing $0.5m/MW). Fuel $44/MWh

PG(1B)

Existing thermal station, 1200MW. Fuel $68?MWh

PG(1A)Country1

Details of StationStation Name

Country

Proposed new gas turbine stations capable of expansion up to 600MW with a variable cost of $0.31m/MW. Fuel $7/106Btu

GT(3B)

Existing thermal station, 260MW. Fuel $25/MWh

PG(3A)Country3

Existing thermal station, 550MW. Fuel $80/MWh

PG(2A)Country2


CountryContinued…

Proposed new gas turbine station, 300MW, with a variable cost of $0.325m/MW. Fuel $5.5/106Btu

GT(4D)

Proposed new combined cycle station, 300MW, with fixed cost of $175m and then the option of expansion up to 2100MW with a variable cost of $0.55m/MW. Fuel $3.8/106Btu

CC(4C)

Existing combined cycle station, 1200MW, with option of expansion up to 2600MW, with a variable cost of $0.6m/MW. Fuel $30/MWh

PG(4B)

Existing thermal station , 500MW. Fuel $59/MWhPG(4A)Country4


CountryContinued…

Continued…

Proposed new hydropower station, 200MW, with fixed cost of $270m, with the option of expansion up to 600MW at a variable cost of $1.3m/MW

NH(7B)Existing hydropower station, 450MWH(7A)Country7

Proposed new hydropower station, 150MW, with fixed cost of $220m and then the option of expansion up to 900MW with a variable cost of $1.1/MW

NH(6B)Existing hydropower station, 600MWH(6A)Country6

Proposed new combined cycle station, 350MW, with fixed cost $ 405m and then the option of expansion up to 2800MW with a variable cost of $0.63m/MW. Fuel $3.2/106Btu

CC(5B)

Existing combined cycle plant, 2400MW. Fuel $65/MWh

PG(5A)Country5


Country


Power Trading Power Trading –– ShortShort--TermTerm

The Purdue models can be used as a short-term model by limiting the length of the planning horizon. Typically it is used as a 10 year model (5 time periods with each period being 2 years long or 10 periods with each period being 1 year long). The amount of trading taking place (using a cost minimization objective) will be subject to a demand constraint:

Generation + Imports + Distributed Generation = Demand – Exports

Total cost = Operational Costs (Fuel & maintenance)+ Penalty Costs of unmet demand/power


Tariff SettingTariff Setting

The present default arrangement with the Purdue model is such that a trade tariff of 6 cents/kWh will take place when the marginal cost of the exporting country is 2 cents/kWh and the marginal cost of the importing country is 10 cents/kWh.

Trade Tariff = Marginal cost*{(Exporter cost + Importer cost)/2}

The importing country makes a cost saving and the exporting country earns a revenue.


Electricity Exporters & Importers Electricity Exporters & Importers

Based on the cost minimization the model indicates which countries are net exporters and which are net importers. In the generic model it can be seen from the user-friendly Windowstm interface that the net importing countries would be countries 1, 2 & 3, and the net exporting countries are 4, 5, 6 & 7.

Following are the examples:

Country 1 – Net Importer



Country 4 – Net Exporter





Capacity Expansion PlanningCapacity Expansion Planning

The model strategically expands generation and transmission capacities for a cost minimization objective.

In the generic 7-node model, with free trade, a cost saving of 24% is made over the scenario where there is no trade.

The trading in MW reserves provides increased reliability and significantly decreased costs.


Capacity Expansion PlanningCapacity Expansion Planning

01,994New Transmission MW)01,617Old Transmission (MW)

4270New Gas Turbines (MW)1,9902,317New Hydropower (MW)3,1104,185New Combined Cycle (MW)900973Old Thermal (MW)2.860.63Unmet Reserve Margin, MW ($bn)2.201.23Unserved Energy, MWh ($bn)2.713.42Capacity capital costs ($bn)11.189.17Operational Costs ($bn)19.0314.52Total regional cost ($bn)

No Trade10 years

4% growth

Free Trade10 years

4% growth

Note that total costs do not include revenues or cost savings from trade.


Objective Function Objective Function –– ShortShort--TermTerm

t i z

min c(i,z)PG(i,z, t) DGcostDG(z, t) UMcostUM(z)+ +∑∑∑

c(i, z) = Fuel Cost/MW at i in z ($)

PG(i,z,t) = Power Generation at i in z during t (MW)

DGcost = Cost/MW of distributed generation demand ($)

DG(z,t) = Distributed Generation in z during t (MW)

UMcost = Cost/MW of unmet reserves ($)

UM(z) = Unmet reserve requirement in z (MW)


Objective Function Objective Function –– LongLong--TermTerm

( ) ( ) ( ) ( )

( )( ) ( )

( )

Yi z t

yy=1

Y Y

y 1 y

c i,z PG i,z,t,y UEcost UE z,t,y UMcost UM z,ymin

1+disc

crf expcost i,z PGexp i,z,y

1+discτ

τ= =

+ ++

∑∑∑∑

∑∑

Costs of capital is now incorporated into the structure of the model, crf represents the capital recovery factor.


Regional Integration Regional Integration -- TransmissionTransmission

Country A Country B

Energy TradeMWh

Reserve TradeMW

Each country/node has existing thermal and high power generation. In the LT model generation capacity expansion takes place. Transmission (existing and proposed) connects A to B, and expansions on the lines also take place. The need for trading requires extra load carrying capability.

Figure 4.2 Training Model with Existing International Transmission Lines and Proposed New Lines

Boundary of regionfor power pool

Key (all line values in MW):

12

43

5 6 7

100 100 150

300150

300300

350

Existing LineProposed Line

Italicized values are proposed new line expansions (MW)All lines can expand up to 2000MW

Generic Model, Free Trade, Existing Transmission Expansions 2004-5

Generic Model, Free Trade, New Transmission Projects 2006-7

Generic Model, Free Trade, New Transmission Expansions 2006-7


International Electricity Trading PolicyInternational Electricity Trading Policy

With international electricity imports and exports between utilities, a decision must be taken at some stage regarding the level of dependency that there is to be on the amount of purchases that are to take place. Considerable attention will be given to this policy as it will affect the planning for new capacity and the type of trading contract that is agreed upon between the buyer and seller.


ContinuedContinued……

The Purdue model represents this important trade policy issue with two parameters that are called autonomy factors. There is an autonomy factor for trading reserves and another one for trading energy:

Reserves trading of MW, autonomy factor AF

Energy trading of MWh, autonomy factor ENAF


Continued….Continued….

The autonomy factors are implemented such that:

If an autonomy factor is set at 100% independence (AF=1.0) then this means a policy requirement exists such that the country, at all times, will meet all of its own electricity demand.

Generation Capacity > (Autonomy Factor AF * Peak Demand)

Generation Production > (Autonomy Factor ENAF * Hourly Demand)


Wheeling TariffsWheeling Tariffs

Country CMarginal cost:

$0.10/kWh

Where a third party country is involved for wheeling electricity from Country A to Country C then a wheeling policy will be needed.The present model demonstrates where this takes place, and currently allocates gains from trading.

Country BMarginal cost:

$0.06/kWh

Country AMarginal cost:

$.02 /kWh$.04/kWhTrade Tariff

$.08/kWhTrade Tariff


Wheeling Continued…Wheeling Continued…

The general rule is that gains from trade between two countries are shared on a 50-50 basis.Trade between A & B is $.04 per kWh, country A has revenue of $.02 and B saves $.02 per kWhTrade between B & C is $.08 per kWh, B has revenue of $.02 per kWh and C has cost saving of $.02 per kWh.Note that country B saves $.04 per kWh, but A and C only save $.02 per kWh.Beware how wheelers can control trade!Fair wheeling policy is a crucial issue in power pools


Generation Plans & Technology Generation Plans & Technology OptionsOptions

The economic benefits of various generation technologies are included in the Purdue LT Model.Depending upon the type of technology, the capital fixed costs, operational costs - including fuel costs - and heat-rate parameters and others, all vary. How do we choose the most suitable technology?

LeastLeast--CostCost Combined Cycle Capacity Combined Cycle Capacity Expansions, 2006Expansions, 2006--77

LeastLeast--Cost Hydropower Capacity Expansions, Cost Hydropower Capacity Expansions, 20062006--77


Model Data Collection & ManagementModel Data Collection & Management

The large electricity trade model requires extensive and accurate data collection. The methodology for the data collection requires collaborative and well coordinated trained personnel.

The reliability of the data collection will determine the reliability of the model output. The model is very sensitive to the data inputs; “Garbage in, garbage out”.

Examples follow of standardized data input sheets.

Data Input Selection

Electricity Demand Data Inputs


Country: ………………………………..A : Yearly DataA1: Annual Peak Demand (MW) A2: Annual Energy Use (GWh)Projected by year, 1998-2020 Projected by year, 1998-2020

20202020……

19981998

GWhMW

Electricity Load ForecastElectricity Load Forecast

Country annual demand growth rate for 2004:[(GWh in 2004 – GWh in 2003) / (GWh in 2003)] * 100%


Electricity Load ForecastElectricity Load Forecast

Electricity Load Forecast C Hourly Data (MW) for a Representative Week, in the most recent year

(24 x 7 = 168 values)Year: ……………, Week Number: ………

DAY & MW load each hour

24…1

SatFriThursWedsTuesMonSunHour

B Weekly peak load (MW) for the most recent year Year: ……………

52…………

423121111

Existing Thermal Generation Data Input

Existing Thermal Generation Data Input

Fdecom14. Forced Decommissioning AT period tyPGmin13. Old thermal minimum usage in MWh per yeardecayPGO12. Decay rate of old thermo plants (fraction/year)

fpescO11. Escalation rate of fuel costs of old thermo plants (fraction/year)

fpO10. Fuel cost of Existing thermo plant ($/MWh)HRO9. Heat rate of old thermo plant set equal to oneVarOMoh8. Variable O&M for old thermal plants ($/MWh)crfi7. Capital recovery factor for existing thermals (fraction/year)UFORPGO6. Unforced outage rate for existing thermo plants (fraction)FORPGO5. Force outage rate for existing thermo units (fraction)PGOmax4. Max possible MW addition to existing thermo plants (MW)PGOexpstep3. Expansion step size for old thermo plants units (MW)Oexpcost2. Expansion costs dollar per MW of old plants ($/MW)PGOinit1. Current net effective (dependable) sent out capacity (MW)ParameterValueComment

Existing Hydropower Data Input

Existing Hydropower Data Input

FdecomH13. Forced decommissioning AT period tyMinH12. Old hydro minimum usage in MWh per yearReshyd11. Reserve margin for hydro plants (fraction)DecayHO10. Decay rate of old hydro plants (fraction/year)VarOMoh9. Variable O&M cost for old hydro ($/MWh)

Crfih8. Capital recovery factor for an existing hydro plant (fraction/year)

FORoh7. Forced outage rate for existing hydro plant (fraction/year)

HOLF5. Annual MWh allowed at an existing dam (normal conditions) (MWh/yr)

HOVmax4. Maximum MW expansion that can be added (MW)Hoexpstep3. Expansion step for existing hydro (MW)HOVcost2. Capital cost of additional capacity for existing hydro ($/MW)Hoinit1. Initial capacity of an existing hydro station (MW)ParameterValueComment

Proposed Combined Cycle Data Input

Proposed Combined Cycle Data Input

MinCC19. Combined cycle minimum usage in MWh per year

AftCC18. Combined cycle NOT built BEFORE or AT period ty

BefCC17. Combined cycle built BEFORE or AT period ty

AtCC16. Combined cycle built AT period ty

DecayNCC15. Decay rate of combined cycle plants (fraction/year)

FpescNCC14. Escalation rate of fuel cost of new combined cycle plants (fraction/year)

FpNCC13. Fuel costs of new combined cycle plants $/1000000 BTU’s

HRNCC12. Heat rate of new combined cycle plants 1000000 BTU’s/MWh

FixOMCC11. Fixed O&M cost for combined cycle plants ($/MW/year)

OMCC10. Variable O&M cost for combined cycle plants ($/MWh)

Crfni9. Capital recovery factor for new thermal (fraction/year)

UFORNCC8. Unforced outage rate for combined cycle plants (fraction)

FORNCC7. Forced outage rate for combined cycle plants (fraction)

PGNCCmax6. Maximum expansion for a combined cycle plant (MW)

PGNCCinit5. Initial capacity of new combined cycle plants (MW)

NCCexpstep4. Expansion step size for combined cycle plants (MW)

NCCexpcost2. Expansion costs of new combined cycle plants ($/MW)

FGCC1. Fixed costs, site purchase preparation & infrastructure ($)

ParameterValueComment

Proposed Transmission Line Data Input

Proposed Transmission Line Data Input

Beflines19. Line built BEFORE or AT period tyAftlines18. Line NOT built BEFORE or AT period tyAtlines17. Line built AT period tyMinPFN16. Minimum power flow on a new line (MW)DecayPFN15. Decay rate of new lines (fraction/year)FORICN12. Annual forced outage rate for new transmission line (%)PFNloss9. Transmission loss factor on new lines (%)

PFNVmax8. Maximum MW expansions that can be added to a new tie line (MW)

PFNVc7. Cost of additional capacity on new line (wire cost) (mill $/MW)

PFNFc6. New tie line fixed cost,Engineering, procurement & construction (mill US $)

Crf5. Capital recovery factor for transmission lines (fraction/year)PFNinit1. Initial tie lines capacity for new line (MW)ParameterValueComment

Regional DataRegional Data

Country DataCountry Data


Data Collection at NodesData Collection at Nodes

The shipping capacity (of electricity and natural gas) between any two nodes/countries has to be known. Data for the existing and potentially new supply points are all needed. The existing demand at each node and the forecast for electricity growth in demand is required. The fuel types to be supplied to each node, for electricity generation, is part of the data. More than one node for each country can be created if shown to be necessary.


In Summary:In Summary:

Power Pool models provide:Quantitative decision support toolsEstimates of gains from more flexible trading contractsSupport for coordinated planningDemonstration of the economies of scale

Documents

Trading Arrangements in Power Pools Model Structure & Data