The nuances of hedging electric portfolio risks

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  • 1. The Nuances of Hedging Electric Portfolio RisksEric MeerdinkDirector, Structuring and AnalyticsElectric OperationsJuly 13, 2011

2. Demand and Supply Characteristics2 3. Demand for ElectricityDemand for electricity is seasonalWeatherAppliance/equipment usageLightingDemand for electricity is stochasticWeather is stochasticDemand for electricity varies throughout the dayAppliance usageLightingDemand varies by customer typeResidentialCommercialIndustrial3 4. Average Daily THI in Newark, NJSeasonal, Stochastic and Mean Reverting100 90 80THI (Temp-Humidity Index) 70 60 50 40 30 20 1001 26 51 76 101 126 151 176 201226 251 276 301 326 351Day of the Year4 5. Demand is a Function of WeatherAverage Daily Demand in PSE&G vs. THI Strong causal relationship between weather and load10,000 9,000 8,000 7,000 6,000 MW 5,000 4,000 3,000 2,000 1,0000 0102030405060 70 80 90 100 THI (Temp-Humidity Index)5 6. Intra-Day SeasonalityTypical Hourly Demand in PSE&G10,000 9,000 8,000 7,000 6,000 MW 5,000 4,000Winter 3,000SpringSummer 2,000Fall 1,0000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour6 7. Intra-Day SeasonalityBy Customer Type in PSE&GAverage Customer on 7-15-101.61.4 Ratio of Hourly Load to Average Load1.2 10.80.6ResidentialCommercial0.4 Industrial0.2 01 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24Hour 7 8. SeasonalityAverage Daily Demand in PSE&G8,000 June 2005 to December 2010Hot7,000Summer Summer CoolSummer6,000 Winter5,000 MW4,000Recession3,0002,0001,000 012/1/0512/1/076/1/059/1/06 12/1/066/1/073/1/089/1/08 12/1/08 6/1/09 12/1/09 3/1/109/1/10 12/1/10 9/1/053/1/06 6/1/06 3/1/07 9/1/07 6/1/08 3/1/099/1/09 6/1/10Date 8 9. Supply: Converting Fuel to ElectricityFUEL ELECTRICIT YMMBTU MWH MWHMMBTU = MWHMMBTU MMBTU = Heat Rate or EfficiencyMWH$MMBTU $ = MWHMWHMMBTU 9 10. Typical Generator Cost $ $= HR + Variable O & M + Emissions + Start CostsMWHMMBTUCombined Cycle ExamplePrice of natural gas = $6.00/mmbtuHeat rate = 8.0 mmbtu/mwhVOM = $2.00/MWHEmissions = $1.50/MWHStart cost = $1.50/MWHVariable Cost to Generate = 8.0 x $6.00 + $2 + $1.5 + $1.5= $52.75/MWHAlways produce as long as you can cover your variable costs and makea contribution to fixed costs. 10 11. Generation Bid StackSupply CurveHeavy OilRepresents the variable cost to produce electricityLight Oil $/MWH Simple Cycle Nat GasCombinedCycle Nuclear/Wind/ Coal HydroMW 11 12. Empirical Generation Bid StackJuly 15, 2010$160.00$140.00$120.00$100.00$/MWH $80.00 $60.00 $40.00 $20.00$0.000 2,000 4,0006,000 8,000 10,000MW12 13. Price Determination $/MWHSupply Curve Price CurveHour MW Load curve Hour13 14. Intra-Day Price Shape $160.0010,0009,000 $140.00 MW8,000 $120.007,000 $100.006,000 $/MWH MW$80.005,0004,000$60.00 $/MWH3,000$40.002,000$20.001,000 $0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour14 15. Hourly Energy Prices in PSE&G July 1, 2005 to December 31, 2010 $450.00 $400.00Hourly Volatility = 1,2875 $350.00Daily Volatility = 234% $300.00 $250.00 $/MWH $200.00 $150.00 $100.00$50.00 $0.00 15 16. What are the Characteristics of Electricity Prices?Electricity cannot be stored (economically)Supply must equal demand instantaneouslyDemand is seasonal and stochastic (weather)Generation cost is a function of stochastic fuel pricesGeneration is subject to random outagesWhat does this imply about electricity pricesStochasticMean reverting, because load and weather are mean revertingAsymmetric price jumps, positive jumps > negative jumpsSeasonality, price returns have a seasonal patternExtremely volatile 16 17. $/MWHAu $10.00 $20.00$30.00$40.00 $50.00$60.00$70.00$80.00$0.00 gSe - 11 p-O 11ctNo -11 vDe -11 c-Forward CurveJa 11 n-Fe 12 b-M 12ar -Ap 1 2rM - 12ay -Ju 12 n- 1 Ju 2l-1Au 2 gSe - 12 p-O 12ctNo -12 v DateDe -12 c-Ja 12 n-Fe 13 b-M 13ar -Ap 1 3rM - 13ay -Ju 13 n- 1 Ju 3l-1Au 3 gSe - 13 p-O 13ctNo -13 vDe -13 c- 13 PJM West Hub Forward Curve and Monthly Option Volatilities0.0%5.0%10.0%15.0%20.0% 25.0%30.0%35.0%40.0%45.0% Volatility %17 18. Nodal Prices Prices in the markets Hess serves (New England, NY and Mid-Atlantic) are locational or nodal. Each node or pricing point has can have a different price. So for example in the Mid-Atlantic region (PJM) there are 8,000+ nodes. The reason for the differences in prices between nodes is the presence of congestion on the transmission lines. If there were no congestion then each node would have the same price, and that price would be the cost to supply the last megawatt of electricity (marginal generator). Congestion is caused by thermal limits on the transmission lines. To alleviate this problem the power pool reduces generation supplying load on that line and turns on a more expensive generator to serve that load and that will not cause congestion on that line. When this happens prices split in the system causing some locations to be more expensive than other locations. 18 19. Locational Marginal Price Locational Marginal Price (LMP) LMP = Marginal Energy + Marginal Congestion + Marginal Losses The marginal energy price is the same for all nodes and locations. The only difference is in marginal congestion and marginal losses. Each power pool has a hub from which basis to the various locations is quoted. The hubs are the most liquid locations in which to trade. Basis is the difference in price between the location and the hub. For example, the basis to PSE&G zone in PJM is the difference between the PSE&G LMP and the West Hub LMP. LMPs can be NEGATIVE.19 20. Zonal Price in New York ISODay-Ahead Zonal Prices on July 11, 2011$200.00$180.00 CapitalCentral$160.00 DunwoodGenesee$140.00Hudson ValleyLong Island$120.00Mohawk Valley$/MWH$100.00 MillwoodNYC $80.00 NorthWest $60.00 $40.00 $20.00$0.001 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24Hour 20 21. Day-Ahead vs. Real-Time There are two types of prices in the power pools. Day-Ahead and Real-time The power pools allow generators and load serving entities (LSEs) to bid their generation and load into the pool the day prior. The power pool schedules the load and generation looking for the least cost solution to meet demand. The power pools then produce a schedule for generators and LSEs that specifies the LMPs by hour and either the load they are buying or the generation they are supplying the next day. These costs and revenues are fixed. In the real time market weather, load and generation outages can be different than those forecasted the day prior. For this reason LSEs may need to purchase more energy or generators my need to generate more energy. The power pools calculate real-time prices for this imbalance energy 21 22. Day-Ahead vs. Real-Time LMPs in PSE&GJuly 15, 2010 $250.00 $200.00 DA_LMP RT_LMP $150.00 $/MWH $100.00$50.00 $0.00 1 35 7 9 11 13 15 17 19 21 23 Hour 22 23. Pricing and Hedging Retail Load ContractsVolumetric and Swing Risk23 24. What is a Full Requirements Load Following Contract? Full Requirements Load Following: A fixed price agreement to serve all the electricity load of a customer, and provide all products required to supply the electric load, for a pre-determined interval of time, without restrictions on volume. Typically served at a fixed rate per MWH. Also called Full Plant Requirements Contract. Typical key products to be supplied: Load Following Energy Capacity Transmission Ancillaries RECs24 25. Volumetric or Swing Risk Volumetric or swing risk is defined as a cash flow risk caused bydeviations in delivered volumes compared to expected volumes. Theprimary cause of these volumetric deviations is weather and economicconditions. Not enough that delivered volumes deviate from expected volumes. These deviations in delivered volumes must be positively correlated withmarket prices. The full requirements load following contract is delta hedged at someexpected volume. Under these conditions the resulting expected cash flow position isnegative and non-linear with respect to changes in market prices. Swing risk is similar to the gamma position of an option, as it is a secondorder price risk.25 26. Short-Run Correlation Between Price and LoadHourly Load and Price in PSE&G Zone 7/12/10 to 7/17/20$200.00 12,000$180.0010,000$160.00$140.008,000$120.00$/MWH MW$100.00 6,000 $80.004,000 $60.00 $40.002,000 $20.00$0.00 0 07/12/1007/13/10 07/14/10 07/15/10 07/16/10 07/17/1026 27. Long-Run Correlation Between Price and Load12-Month Rolling Average of Load and Price in PSE&G Zone 5,500 $90.00 $80.00 5,400 $70.00 5,300 $60.00 5,200 $50.00$/MWHMW $40.00 5,100MW $30.00$/MWH 5,000 $20.00 4,900 $10.00 4,800 $0.00 May-06 Sep-06 Jan-07 May-07 Sep-07 Jan-08 May-08 Sep-08 Jan-09 May-09 Sep-09 Jan-10 May-10 Sep-10Month/Yr27 28. Typical Short Sale and Long HedgeP&L Long Hedge+ Net$/MWH-Short Sale28 29. Sources of Swing Risk in Load Following DispatchEconomic Impact (A to B)CurvePower Price $/MWH Weather Principal source ofswing risk.General Economic Conditions ab Weather Impactbetween a and b.BADemand (MW)29 30. Retail Sale and Long Hedge$Long Hedge+$/MWHNet: Swing RiskGamma- Short Sale Short Retail Sale30 31. Change in Cash Flow when Power is Delta HedgedAB C Load greater Load less thanLoad equalsthan expected expected loadexpected loadload Price less than 1 expected price-0 + 2Price equals expected price00 03 Price greater than expectedprice +0 - Swing Risk- - - - - -LongHedgedShort PositionPosition31 32. Cash Flow @ Risk (CF@R) The positive covariance between prices and load gives the cash flow distribution a negative skew. CF@R is a probabilistic measure of the deviation between the expected cash flow and a loss that can occur with a certain probability. Cash flow is a good measure of risk since we have obligations through delivery. 0.04 Mean 0.03 Density 0.02 0.01% 0.00-60-50 -40 -30 -20 -100 10 2030Cash Flow (1 ) % CV@R = $5032 32 33. Short Gamma Hedge