The effect of variability mitigating market rules on the operation of wind farms

Transcription

1 The effect of variability mitigating market rules on the operation of wind farms Eric Hittinger, Rochester Institute of Technology Jay Whitacre, Carnegie Mellon University Jay Apt, Carnegie Mellon University The issue of wind variability Effects of several variability mitigating market rules Comparison of wind mitigating market rules 1

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3 Wind generation has traditionally received a free pass for its variability, but this is changing BPA (Pacific Northwest) has implemented a Wind Balancing Service and charges wind generation $1080/MW month EirGrid (Republic of Ireland) requires wind farms to provide a small amount of frequency regulation (both up and down) ERCOT (Texas) has a ramp rate limit for wind farms responding to a deployment order 3

4 Wind generation has traditionally received a free pass for its variability, but this is changing BPA (Pacific Northwest) has implemented a Wind Balancing Service and charges wind generation $1080/MW month EirGrid (Republic of Ireland) requires wind farms to provide a small amount of frequency regulation (both up and down) ERCOT (Texas) has a ramp rate limit for wind farms responding to a deployment order Two issues: No comparisons of the costs and benefits of different strategies No market based policies that might internalize variability costs 4

5 The hypothesis Wind generators may be the entity that can manage short term wind fluctuations at lowest cost. Implementing market based limitations on wind variability may result in efficient operational changes that reduce overall wind integration costs, and affect the placement of new wind farms. 5

6 Some conceptual motivation for this work: The field of electricity demand response The concept that the most efficient carbon reductions come from market based policies (rather than command and control ) 6

7 The project Examine the effect of different wind integration rules on the revenue to and 30 minute variability from wind farms in ERCOT. Inputs: Wind farm power for 16 wind farms in West Texas for (15 min increments) Spot market (BES) and Frequency Regulation (both up and down) prices for West Texas over the same period Hourly forecast data from AWS Truepower (6 hour ahead is used) 7

8 Six types of system wind policies are considered Base Case (no rules) Wind Integration Fee (per MWh) Wind Integration Tariff (per MW month) Limited up ramping of wind Limited up and down ramping of wind Wind required to meet forecast (within deadband) Wind is allowed to violate ramping/forecast constraints and pay a penalty based on current frequency regulation price 8

9 The responses from wind farms were limited to: Controlling output to maximize revenue Curtailment to produce a reserve Purchasing and using sodium sulfur batteries 9

10 The responses from wind farms were limited to: Controlling output to maximize revenue Curtailment to produce a reserve Purchasing and using sodium sulfur batteries The wind farm s goal is to maximize revenue at each time step: 10

11 In an area with negative electricity prices, economic curtailment results in increased revenue and variability for wind farms (relative to a must run strategy) 120 Potential Wind Output Output under economic curtailment BES prices Power (MW) BES price ($/MWh) Break even price for wind Time (min) 11

12 In areas with negative electricity prices, economic curtailment results in increased revenue and variability for wind farms 1 day 12 hour Must-run operation Economic curtailment hour MW / Hz 1 hour 30 min Frequency (Hz) 12

13 Wind Integration Tariff (per MW month) No effect on the operation of wind farms At a rate of $680/MW month (the 2008 BPA rate), wind farm revenue decreases 5.6% At a rate of $1090/MW month (the 2010 BPA rate), wind farm revenue decreases 9% 13

14 Wind Integration Fee (per MWh) 14

15 Ramping Limitations Wind is permitted to over ramp but must pay a penalty. This penalty is based on the current Frequency Regulation clearing price. 15

16 A loose up ramp rate limit along with a higher penalty can reduce 30 min variability at little cost to wind farms 16

17 The results are similar for a case where up and down ramping are limited 17

18 Forecast Matching Wind is required to meet forecast within a stated deadband or pay a penalty. Penalties are based on current Frequency Regulation prices. 18

19 Wind can be encouraged to adhere to forecast by applying a low penalty to deviations along with a tight deadband 19

20 Market based rules (particularly ramp rate limits) are an effective way to reduce short term variability with little effect on wind farm profit 20

21 But most of the losses are due to penalty payments, which could be redistributed to wind farms 21

22 Conclusions Relatively small penalties can motivate a significant response from wind farms Market based variability mitigation policies can reduce short term variability at lower cost to wind farms than command and control strategies Market based strategies will also shift the economics of wind development, improving the relative financial attractiveness of sites with less variability (or better adherence to forecast). 22

23 Support for this research has been provided by the EPA STAR Fellowship, the Gordon Moore Foundation, the National Energy Technology Laboratory of the Department of Energy, and the Electric Power Research Institute under grants to the Carnegie Mellon Electricity Industry Center (CEIC). Questions! 23

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25 West Texas market clearing price does show light clustering around wind s marginal cost 0 West Texas BES Price ($/MWh) Production Tax Credit Production Tax Credit plus Texas REC price Time (days) 25

26 West Texas Market Example Regulation Down Regulation Up Balancing Energy Service (BES) Price ($ / MW - hour) Time (Days) 26

27 Equations 1 The goal is to maximize revenue at each time step: The penalty under a direct wind energy fee is: The penalty under a wind tariff (per MW month) is: The penalty under an up ramp limit is: 27

28 Equations 2 The penalty under an up and down ramp limit is: The penalty under the requirement that wind meets forecast (within a deadband) is: 28

29 Wind farms under long term contracts should be operated/curtailed in the same way (it is just a different entity that has the motivation to do so) West Texas BES price = $30/MWh West Texas BES price = $30/MWh Wind Farm Output = 20 MW Coal Plant Output = 100 MW Wind Farm Output = 0 MW Coal Plant Output = 120 MW Payment = $40/MWh Transmission (presumably maxed out) Payment = $65/MWh Transmission (presumably maxed out) San Antonio (load / wind contract holder) Power to San Antonio = 20 MW Payment to wind farm = $800 Revenue to wind = $1300 Net cost to San Antonio = $800 San Antonio (load / wind contract holder) Power to San Antonio = 20 MW Payment to wind farm = $1300 Revenue to wind = $1300 Net cost to San Antonio = $700 Payment = $30/MWh 29

30 A note on the partial derivates for upand down ramping results Doubling the penalty reduces 30 min fluctuations by ~10% Doubling the penalty causes wind farm revenue losses to increase by 1.8X No consistent relationship between ramp limit and resulting fluctuations (minimum around 5 10%) Making your ramp rate twice as tight (ramp limit * 0.5) causes revenue losses to increase by 1.5X 30

31 Under a strict ramp rate limit, wind farms curtail some very valuable energy 31

32 Up ramp limit example 7 6 Potential wind output Output under no ramp limitation Ramp limit=1%, Penalty = 5xRegDown Ramp limit= 20%, Penalty = 5xRegDown 5 Power (MW) Time (Minutes) 32

33 Alternate ramping rules example 6 5 Potential wind output Ramp based on previous time step Ramp based on last non-violation time step 4 Power (MW) Time (minutes) 33

34 Amount of underforecasting Average amount of underforecasting chosen by wind generators Penalty (percent of Frequency Regulation Price) 25% 50% 100% 200% 500% 5% deadband 45.9% 46.3% 46.7% 47.0% 47.6% 10% deadband 36.1% 36.5% 36.9% 37.2% 37.7% 20% deadband 22.6% 22.9% 23.1% 23.4% 23.7% 40% deadband 10.6% 10.6% 11.1% 11.1% 11.1% 60% deadband 6.6% 6.6% 6.6% 6.6% 6.6% 34

35 Differences in wind farms under upand down ramping limit of 20% 100% Wind farm revenue (relative to "no rule" scenario) 99.8% 99.6% 99.4% penalty = 0.25xFreqReg penalty = 0.5xFreqReg penalty = 1xFreqReg penalty = 2xFreqReg penalty = 5xFreqReg Average of 16 wind farms 40% 60% 80% 100% Power of fluctuations at 30-min period (relative to "no rule" scenario) 35

36 When wind farms are penalized for diverging from forecast, loose deadbands and high penalties are more efficient ways to improve adherence to forecast 36

37 Differences in wind farms under forecast matching 100% Wind farm revenue (relative to "no rule" scenario) 90% 80% penalty = 0.25xFreqReg penalty = 0.5xFreqReg penalty = 1xFreqReg penalty = 2xFreqReg penalty = 5xFreqReg average of 16 wind farms 5% 6% 7% 8% 9% RMSE (percent of actual nameplate capacity) 37

38 Using a fee bate system means that the most variable wind farms collect less revenue Wind farm revenue under a "feebate" system (relative to "no rule" scenario) 100% 99.8% 99.6% Normalized variability at 30-minute period (1 / Hz) 38

39 Using a fee bate system for forecast divergence means that the least predictable wind farms get less revenue Wind farm revenue under a "feebate" system (relative to "no rule" scenario) 102% 100% 98% 10% deadband, 5x FreqReg penalty, underforecasting allowed 60% deadband, 5x FreqReg penalty, no underforecasting 96% 7% 8% 9% Root-mean-square error (percent of nameplate capacity) 39

40 Example of battery operation Battery Power Output Electricity Price ($/MWh) % 0% "Sell above" price "Buy below" price Electricity price Battery operation (perfect information) Battery operation (simple model) -100% Time (Hours) 40

41 Summary Table Scenario Parameters Decrease in wind farm revenue Wind Integration Fee (per MWh) Wind Balancing Tariff (per MW month) Limited up ramping Limited up and down ramping Penalty for diverging from wind forecast Penalty for diverging from wind forecast (underforecasting permitted) Decrease in wind farm revenue under a "feebate" system $10/MWh fee 15% 0.2% 3% $680 / MWmonth tariff 20% ramp limit, 5xFreqReg penalty 20% ramp limit, 5xFreqReg penalty 60% deadband, 5xFreqReg penalty 1% deadband, 5xFreqReg penalty 5.5% 0% 0% 0.4% 0.1% 21% 0.5% 0.2% 45% Decrease in 30 minute variability 0.9% 0.1% 6% (0.1% improvement in RMSE) 14% 0.7% 23% (0.2% improvement in RMSE) 41