1. Generation: Control & Economic Dispatch 2016 System Operator Seminar

2. Slide 2 What is Covered Automatic Generation Control Basics ACE Equation Unit Control Via AGC Control Performance Standards Economic Dispatch Basic Theory Control Economic Dispatch Study Economic Dispatch (using Economy A) Introduction

3. Automatic Generation Control Basics

4. Slide 4 Energy Balance Generation Demand Power Generated Imports Exports LoadsLosses AGC Basics Source:

5. Slide 5 Imbalance Conditions Over-generation Total Generation > Total Load Frequency > 60 Hz Generators momentarily speed up Under-generation Total Generation < Total Load Frequency < 60 Hz Generators momentarily slow down AGC Basics

6. Slide 6 Control Response Time Hierarchy Electromagnetic Stage………………………. < ⅓ sec System Inertia............................................... ⅓ -5 sec Frequency Bias Characteristic...................... < 20 sec (Governor & Load Response) Regulation (AGC).............................................> 30 sec Economic Re-Dispatch................................... > 5 min AGC Basics

7. Slide 7 Inertial Response Inertia - resistance to change in rotational speed When generators fail to meet load During load increases, generator starts to slow down During load decreases, generator starts to speed up Generators can’t instantly stop or they will fly apart Forces are present that oppose the change created by the change in load AGC Basics

8. Slide 8 Governor Response AGC Basics

9. House curves 9 60 300 MW Unit 100 MW Unit 200 MW load 57 3002001000 200300 5% Droop

10. House curves 10 61.5 200 MW Load60 300 MW Unit 100 MW Unit 57 3002001000 200300 5% Droop

11. House curve with Interconnection 11 61.5 200 MW Load60 Eastern Interconnection 300 MW Unit 57 3002001000 200300 5% Droop

12. Slide 12 Load Response to Frequency Portion of system load that increases or decreases when frequency increases or decreases Measured in MW/0.1 Hz Approximately 1 - 2 % load change for a 1% change in frequency System Load = 22,000 MW Example: Frequency Change = +/- 0.03 Hz What is the change in system load? 22000 X (1 % MW/0.1Hz) X.03Hz = 66 MW 22000 X (2 % MW/0.1Hz) X.03Hz = 132 MW AGC Basics

13. Slide 13 Frequency Bias AGC Basics Governor Response Characteristics Load Response Characteristics Frequency Bias

14. 2015 Frequency Bias values 14 Estimated Peak demand(MW) Average Frequency Bias (MW/.1Hz) Bias/Demand (%) Bias/Total Bias (%) L10 (MW) Eastern Interconnection 621,697‐6,303.011.01100.00 FRCC 50,282‐503.651.007.99 City of HomesteadHST97‐1.001.030.027.47 City of TallahasseeTAL543‐5.431.000.0917.40 Duke Energy of FloridaFPC12,163‐121.601.001.9382.34 Florida Municipal Power PoolFMPP3,245‐32.451.000.5142.53 Florida Power & LightFPL23,314‐233.141.003.70114.01 Gainesville Regional UtilitiesGVL424‐4.241.000.0715.38 JEA 2,726‐28.001.030.4439.51 Seminole Electric CooperativeSEC3,457‐34.571.000.5543.90 Tampa Electric CompanyTEC4,222‐42.221.000.6748.52 Utilities Commission, City of New Smyrna BeachNSB91‐1.001.100.027.47

15. Slide 15 Regulation Control “Regulating units” are generating units that provide fine tuning which is necessary for effective system control Governors respond to minute-to-minute changes in load “Regulating units” correct for small load changes that cause the power system to operate above and below 60 Hz for sustained period of time AGC Basics

16. Slide 16 Area Control Error (ACE) The instantaneous difference between a Balancing Authority’s net actual and scheduled interchange, taking into account the effects of Frequency Bias and correction for meter error. (Automatic Time Error Correction is only in WECC) ACE = (NI A − NI S ) − 10B (F A − F S ) − I ME Area Control Error

17. Interchange Component of ACE 17 ANI SNI (Schedules) Reserves Inadvertent payback Jointly owned units* Dynamic Schedules Miscellaneous (operator entered) * Ensure both parties agree where it goes in ACE!

18. AGC Operating Modes 18 There are three typical operating modes for AGC, namely: 1.Constant Frequency Control (Flat Frequency Control) Different from Isochronous governor control! 2. Constant Net Interchange Control (Flat Tie-Line Control) When would you use this? 3. Tie-Line Bias Control NERC Operating Standards specify that all Balancing Authorities shall use tie-line bias control unless they have an operational reason not to.

19. Slide 19 AGC Major Functions Load Frequency Control: AGC matches power generation with system load while maintaining the desired frequency Economic Dispatch: AGC calculates the economic base points for the units. Reserve Monitoring: AGC takes into account the required reserve that is necessary to provide a measure of electrical security in the network based on MW reserves that are available. Performance Monitoring: AGC provides measurements of its performance based on NERC operating standards. AGC Basics

20. Control Modes in AGC 20 Off Standby Manual Fixed External Ramp Econ Auto Test Schedule Market Regulation OFF REG Assist REG/Assist Emergency

21. Control Performance Standards

22. Slide 22 A statistical measure of ACE variability and its relationship to frequency error Intended to provide a frequency sensitive evaluation of how well demand requirements are met Calculated over a rolling 12-month period How well you control in the short term (helping or hurting frequency) NOTE: ACE reported to NERC for CPS1 should not include inadvertent. Control Performance Standards CPS1 Review

23. Slide 23 12-Month Compliance Factor Control Performance Standards InterconnectionEpsilon 1Epsilon 10 Eastern18.05.7 Hydro Quebec21.024.9 Western22.87.3 ERCOT30.013.15

24. Slide 24 CPS1 Calculation Good scores range from 100% to 200% 100% to 200% Control Performance Standards

25. Slide 25 CPS1 Review Control areas are not penalized when ACE benefits system frequency Negative ACE means you are under-generating: If frequency is high (greater than 60 Hz.), it is OK to have a small negative ACE because you are helping out the interconnection. Positive ACE means you are over-generating: If frequency is low (less than 60 Hz.), it is OK to have a small positive ACE because you are helping out the interconnection. Control Performance Standards

26. Slide 26 CPS1 Charts Control Performance Standards

27. Slide 27 CPS1 Review (This view is for BAL-001-2, effective 7/1/16) Control Performance Standards Region of above 60 Hz and negative ACE Region of below 60 Hz and positive ACE

28. So What Can We Do? 28 CPS1 is a short term (average 1-minute measure) Concern was that if CPS1 was the only regulating standard, Control Areas would: Grossly over or under generate (as long as it was opposite frequency) Get very good CPS1 scores Impact neighbors with excessive flows We need something longer term! What about CPS 2?

29. Slide 29 CPS2 CPS2 is a “safety valve” standard that was put in place when CPS was developed. Each BA shall operate such that its average ACE for at least 90% of clock- ten-minute periods (6 non-overlapping periods per hour) during a calendar month is within a specific limit, referred to as L10. Under CPS2, ACE is limited to a “regulating road” The width of the “regulating road” proportional to the Control Area’s size L10 is the term used to describe the width of the “regulating road” Control Performance Standards

30. Slide 30 L10 Formula Control Performance Standards

31. 2015 Frequency Bias values 31 Estimated Peak demand(MW) Average Frequency Bias (MW/.1Hz) Bias/Demand (%) Bias/Total Bias (%) L10 (MW) Eastern Interconnection 621,697‐6,303.011.01100.00 FRCC 50,282‐503.651.007.99 City of HomesteadHST97‐1.001.030.027.47 City of TallahasseeTAL543‐5.431.000.0917.40 Duke Energy of FloridaFPC12,163‐121.601.001.9382.34 Florida Municipal Power PoolFMPP3,245‐32.451.000.5142.53 Florida Power & LightFPL23,314‐233.141.003.70114.01 Gainesville Regional UtilitiesGVL424‐4.241.000.0715.38 JEA 2,726‐28.001.030.4439.51 Seminole Electric CooperativeSEC3,457‐34.571.000.5543.90 Tampa Electric CompanyTEC4,222‐42.221.000.6748.52 Utilities Commission, City of New Smyrna BeachNSB91‐1.001.100.027.47

32. Slide 32 CPS2 Calculation Good scores range from 90% to 100% Control Performance Standards

33. Slide 33 CPS2 Review CPS2 states that for each 10-minute period, the average ACE for a Control Area must be less than the L 10 of that Control Area Any clock 10-minute period greater that L 10 (whether it’s 1 MW more or 100 MW more) is a violation The minimum acceptable CPS2 is 90% This means that on average, a Control Are may have roughly one violation every other hour and still pass CPS2 Control Performance Standards

34. Economic Dispatch Basics

35. Slide 35 Economic Dispatch The distribution of total generation requirements among alternative sources for optimum system economy with due consideration of both incremental generating costs and incremental transmission losses. Basically, the objective of Economic Dispatch is to operate the power system at minimum $/HR cost at all time  Save money for customers, make money for shareholders

36. Factors for consideration 36 Heat Rate Fuel cost Transmission losses NOx (ammonia costs) SO 2 costs CO 2 costs Reserves Contingency (DCS) Regulation (CPS) Frequency Maintenance cost (O&M) Unit limits

37. Slide 37 Projected Natural Gas Prices Economic Dispatch

38. Slide 38 Generator Costs There are many fixed and variable costs associated with power system operation. Generation is major variable cost. For some types of units (such as hydro and nuclear) it is difficult to quantify. For thermal units it is much easier. There are four major curves, each expressing a quantity as a function of the MW output of the unit. Economic Dispatch

39. Slide 39 Generator Costs Input-Output (IO) Curve Shows relationship between MW output and energy input in Mbtu/hr. Production Cost Curve Input-output curve scaled by a fuel cost expressed in $/Mbtu which results in production cost in $/hr. Heat-Rate Curve Shows relationship between MW output and energy input (Mbtu/MWhr) Incremental (Marginal) Cost Curve Shows the cost to produce the next MWhr Economic Dispatch

40. Slide 40 Economic Dispatch P MIN P MAX Output (MW) $/MWHR If we multiply the fuel cost and the IHR Curve, we will have the Incremental Cost Curve. This is the curve we use for Economic Dispatch! Incremental Cost Curve

41. Slide 41 Economic Dispatch Since FPL’s load center is located in South Florida, units in the north have a higher penalty factors compared to units in the south. Penalty Factor

42. Slide 42 Economic Dispatch Penalty Factors Units nearer to the load center:Units farther from the load center: Penalty Factors are calculated by the Network Applications

43. Slide 43 Economic Dispatch Solving the Economic Dispatch Problem The Incremental Cost Curve is used to determine the optimal (most economical) dispatch for Generators 1, 2, and 3. In theory, to obtain the optimal dispatch, each unit should be operated so that they have the same incremental cost. Economic Dispatch uses an iterative solution technique that includes finding the value of Incremental Cost, Lambda (λ) that results in all units on dispatch operating at the same Incremental Cost.

44. Slide 44 Economic Dispatch n The purpose of Economic Dispatch is to minimize the production cost of on-line generation. For example, if we need to serve 300 MW... Do we know what we are doing?

45. Questions? 45