Wind, Markets, and Capacity

1. EE 459/559Fall 2016Iowa State University Wind, Markets, and Capacity James D. McCalley London Professor of Power Systems Engineering

2. Outline ISOs Basics of electricity markets Wind and markets Dispatchable intermittent resources (DIR) Capacity 2

3. Western Energy Imbalance Market as of 5/2016. What are ISOs/RTOs? • Regional system operator: monitors/controls grid in real-time • Regional market operator: monitors/controls electricity markets • Regional planner: coordinates 5 and 10 year planning efforts • They do not own any electric power equipment! • None of them existed before 1996! • California ISO (CAISO) • Mid-continent ISO (MISO) • Southwest Power Pool (SPP) • Electric Reliability Council of Texas (ERCOT) • New York ISO (NYISO) • ISO-New England (ISO-NE) • Pennsylvania-Jersey-Maryland (PJM) 3

4. Energy control centers 4

5. ECCs: EMS & SCADA Remote terminal unit Substation SCADA Master Station Communication link Energy control center with EMS EMS alarm display EMS 1-line diagram 5

6. ECCs: SCADA, Telemetry, EMS, RT, DA Markets EMS Day-ahead market Real-time market Automatic Generation Control (AGC) is a feedback control system that regulates the power output of electric generators to maintain a specified system frequency and/or scheduled interchange. Intra-day & day-ahead reliability unit commitment (RAC) 6

7. Summary of power balance control levels We are addressing inclusion of wind in real-time and day-ahead electricity markets

8. Basic market design used by all ISOs today. Schedules entire “next-day” 24hr period. Schedules interchange for entire “next-day” 24hr period, starting at current hour, optimizing one hour at a time (1 value per hr) Computes dispatch every 5 minutes. 8

9. Basics of electricity markets • Locational marginal prices (LMPs), $/MWhr, indicate the energy price at each bus. • Markets compute LMPs via an internet-based double auction that maximizes participant benefits. The LMPs are computed from SCED every hour in the DAM and every 5 minutes in the RTM. • The DAM and the RTM are 2 separate settlement processes. 9

10. Electricity “two settlement” markets Which gens get committed, at roughly what levels for next 24 hours, and settlement Internet system Energy & reserve offers from gens Day-Ahead Market (every day) Generates 100 mwhr; w/ DAM price at $50, gets paid $5000. Energy bids from loads Generation levels for next 5 minutes and settlement for deviations from day-ahead market Energy offers from gens Internet system Real-Time Market (every 5 minutes) Generates 101 mwhr; w/ RTM price at $95, gets paid $95. Total payment is $5095 (if RTM price used for all, I would get $9595!) Energy bids from loads What if RTM price is $5? Total payment is $5005, which is much better than $505 if RTM price is used for entire $101 mwhr. RTM prices may be very different from DAM prices due to unexpected real time events. So DAM decreases exposure of market participants to this RTM risk. 10

11. Internet-based two-sided auction markets Internet System B1 S1 B2 S2 B3 • Buyers submit bids to buy in terms of • Price ($/MWhr) • Quantity (MWhr) • Sellers submit offers to sell in terms of • Price ($/MWhr) • Quantity (MWhr) Price at which seller is willing to sell increases with amount (cost of producing 1 more energy unit increases as a gen is loaded higher) Price at which buyer is willing to buy decreases with amount (first unit is used to supply most critical needs and after those needs are satisfied, next units of energy are used to satisfy less critical needs) This table orders offers and bids for each agent. 11

12. Internet-based two-sided auction markets This table orders offers and bids for each agent (same as previous slide) This table orders offers and bids across all selling and buying agents, respectively. 12

13. Market clearing price L. Tesfatsion, “Auction Basics for Wholesale Power Markets: Objectives and Pricing Rules,” Proceedings of the 2009 IEEE Power and Energy Society General Meeting, July, 2009. Computed as the price where the supply schedule intersects the demand schedule. SUPPLY Price ($/MWhr) DEMAND Quantity (MWhr) 13

14. Market clearing price L. Tesfatsion, “Auction Basics for Wholesale Power Markets: Objectives and Pricing Rules,” Proceedings of the 2009 IEEE Power and Energy Society General Meeting, July, 2009. Computed as the price where the supply schedule intersects the demand schedule. SUPPLY Price ($/MWhr) DEMAND Quantity (MWhr) 14

15. Additional resources • What we have just seen is a conceptual description of the clearing mechanism for a real-time market (RTM). • We will also show in the next few slides simplified optimization problem statements that underlie the RTM and the day-ahead market (DAM). • The websites of each ISO/RTO provide detailed documentation on these markets and all other activities in which ISOs/RTOs engage. For example, MISO has 29 “Business Practice Manuals” (BPMs), as shown on the next slide.

16. Additional resources www.misoenergy.org/Library/BusinessPracticesManuals/Pages/BusinessPracticesManuals.aspx BPM 002 covers the Energy Market rules, design and operational elements of both MISO’s Day-Ahead Energy and Operating Reserve Market and Real-Time Markets.  This BPM also explains how the MISO Market complies with our Tariff, Reliability, NERC and ERO standards. This BPM benefits readers who want answers to the following questions: • What are the basic concepts of MISO’s Energy and Operating Reserve Markets? • What are the roles of MISO and the Market Participants in the Energy and Operating Reserve’s Market? • Where does a Market Participant go to find out Market Rules, Hours of Operation and guidelines related to the Market Tariff? • What are the Energy and Operating Reserve Market Products?

17. Additional resources …

18. Subject to 1. SCED obj fnct also includes regulation term, separating reg-up from reg-down. Security-constrained economic dispatch (SCED) 2. “Value” terms in obj fnct are set by stepped curves established by ISO. Max demand Σ di+wi<DMAXi for all i (9) • We allow offers and bids to be made on energy and reserves. • This problem is solved for a single operating condition. • We will assume the operating condition is representative for • a certain time period (either 1 hour or 5 minutes). The above is a simplified version. The MISO Business Practice Manual BPM-002-r11, Chapter 6, provides a detailed description of the SCED. See https://www.midwestiso.org/Library/BusinessPracticesManuals/Pages/BusinessPracticesManuals.aspx.

19. Locational marginal prices: three components LMP= Generation Marginal Cost Cost of marginal losses Transmission congestion cost + + • Units are $/MWhr • One for each bus in the network. • If the network is lossless & transmission capacity is infinite, then all buses have the same LMP, λ. In this case, λ is the increase in system cost if total load increases by 1 unit (corresponds to simple market we will see). • With a lossy and congested network, LMPk is the increase in cost of bus k MW load increases by 1 unit. 19

20. , We will do three examples. Case 1: All transmission has infinite capacity. Case 2a: All transmission has infinite capacity except one line which is constrained to 0.3 pu. Case 2b: Same as case 2a except we add 1 MW load to bus 3. Example Objective function: s1=13.07 $/MWhr s2=12.11 $/MWhr s4=12.54 $/MWhr s1=1307 $/puMWhr s2=1211 $/puMWhr s4=1254 $/puMWhr

21. minimize 1307 pg1 + 1211 pg2 + 1254 pg4 subject to theta1=0 -pb1 + 10 theta1 - 10 theta4 = 0 -pb2 + 10 theta1 - 10 theta2 = 0 -pb3 + 10 theta2 - 10 theta3 = 0 -pb4 - 10 theta3 + 10 theta4 = 0 -pb5 + 10 theta1 - 10 theta3 = 0 pg1 - 30 theta1 + 10 theta2 + 10 theta3 + 10 theta4 = 0 pg2 + 10 theta1 - 20 theta2 + 10 theta3 = 1 10 theta1 + 10 theta2 - 30 theta3 + 10 theta4 = 1.1787 pg4 + 10 theta1 + 10 theta3 - 20 theta4 = 0 -pg1 <= -0.5 pg1 <= 2 -pg2 <= -0.375 pg2 <= 1.5 -pg4<= -0.45 pg4 <= 1.8 -pb1 <= 500 pb1 <= 500 -pb2 <= 500 pb2 <= 500 -pb3 <= 500 pb3 <= 500 -pb4 <= 500 pb4 <= 500 -pb5 <= 500 pb5 <= 500 Bounds -500 <= pb1 <= 500 -500 <= pb2 <= 500 -500 <= pb3 <= 500 -500 <= pb4 <= 500 -500 <= pb5 <= 500 -3.14159 <= theta1 <= 3.14159 -3.14159 <= theta2 <= 3.14159 -3.14159 <= theta3 <= 3.14159 -3.14159 <= theta4 <= 3.14159 end Objective I arbitrarily set one angle to whatever I like (within bounds), since it is the angle differences that are important. Line flows DC power flow equations (constraints c7-c10) Case 1 CPLEX Code CPLEX only provides dual variables for equalities and inequalities that appear in the constraint list, i.e., it does not provide dual variables for inequalities in the “bounds” list. If the exact same constraints are imposed both places, CPLEX will not provide a dual variable. Generation offer constraints (constraints c11-c16) Line flow constraints (note infinite capacity of 500 pu). (constraints c11-c20) If you do not explicitly define a bound on a variable, then CPLEX applies bounds of 0 to ∞, and so if you want negativity for a variable, you must explicitly state that here.

22. Z*=$2705.7557 display solution variables – Variable Name Solution Value pg1 0.500000 pg2 1.228700 pg4 0.450000 pb1 -0.015163 theta4 0.001516 pb2 0.095487 theta2 -0.009549 pb3 0.324188 theta3 -0.041968 pb4 0.434838 pb5 0.419675 All other variables in the range 1-12 are 0. Solution to Case 1 – Decision Variables There are 11 variables listed as non-0. So which variable is 0? Why?

23. Units are $/per unit-hr. Solution to Case1 – Dual Variables • The dual variables tell us how much the objective changes when the right-hand-side of the corresponding constraint increases by a unit (subject to qualifications on next slide). Since we are in “per unit”, and a “per-unit” is 100 MW, dividing the dual variables by 100 gives the corresponding $/MWhr change in the objective function. So dual variables for • c7-c10 are$12.11/MWhr Increasing load by 1 MW at either of buses 1,2,3, or 4 increases objective by $12.11. This is set by the bus 2 generator, as it will respond to any load change. • c11 is -$0.96/MWhrThis constraint is –pg1<=-0.5. Increasing RHS from -0.5 to 0.49, equivalent to decreasing lower bound on pg1 from 50 to 49 MW, reduces objective by $0.96. • c15 is -$0.43/MWhr This constraint is –pg4 <= -0.45. Increasing RHS from -0.45 to -0.44, equivalent to decreasing lower bound on pg4 from 45 to 44 MW, reduces objective by $0.43.

24. minimize 1307 pg1 + 1211 pg2 + 1254 pg4 subject to theta1=0 -pb1 + 10 theta1 - 10 theta4 = 0 -pb2 + 10 theta1 - 10 theta2 = 0 -pb3 + 10 theta2 - 10 theta3 = 0 -pb4 - 10 theta3 + 10 theta4 = 0 -pb5 + 10 theta1 - 10 theta3 = 0 pg1 - 30 theta1 + 10 theta2 + 10 theta3 + 10 theta4 = 0 pg2 + 10 theta1 - 20 theta2 + 10 theta3 = 1 10 theta1 + 10 theta2 - 30 theta3 + 10 theta4 = 1.1787 pg4 + 10 theta1 + 10 theta3 - 20 theta4 = 0 -pg1 <= -0.5 pg1 <= 2 -pg2 <= -0.375 pg2 <= 1.5 -pg4<= -0.45 pg4 <= 1.8 -pb1 <= 500 pb1 <= 500 -pb2 <= 500 pb2 <= 500 -pb3 <= 0.3 pb3 <= 0.3 -pb4 <= 500 pb4 <= 500 -pb5 <= 500 pb5 <= 500 Bounds -500 <= pb1 <= 500 -500 <= pb2 <= 500 -500 <= pb3 <= 500 -500 <= pb4 <= 500 -500 <= pb5 <= 500 -3.14159 <= theta1 <= 3.14159 -3.14159 <= theta2 <= 3.14159 -3.14159 <= theta3 <= 3.14159 -3.14159 <= theta4 <= 3.14159 end Objective I arbitrarily set one angle to whatever I like (within bounds), since it is the angle differences that are important. Line flows DC power flow equations Case 2a CPLEX Code CPLEX only provides dual variables for equalities and inequalities that appear in the constraint list, i.e., it does not provide dual variables for inequalities in the “bounds” list. If the exact same constraints are imposed both places, CPLEX will not provide a dual variable. Generation offer constraints Line flow constraints (note the infinite capacity of 500 pu, except for line pb3). If you do not explicitly define a bound on a variable, then CPLEX applies bounds of 0 to ∞, and so if you want negativity for a variable, you must explicitly state that here.

25. Case 1 (without pb3 tightly constrained) Cases 1 and 2a Objective: Z*=$2705.7557 • In comparing the two solutions, we observe • flow on branch 3 is constrained to 0.3 • flows all over the network have changed. • gen levels at buses 2 and 4 have changed. • Activation of a transmission constraint has changed the dispatch. This will affect • energy prices (LMPs) • Objective function value Case 2a: (with pb3 tightly constrained) Objective: Z*=$2707.8358

26. This shows dual variables - the Lagrange multipliers on the equations corresponding to the indicated parameter (units are $ per 100MWhrs). These tell us how much the objective changes when the RHS of the constraint increase by a unit. Case 1 (without pb3 tightly constrained) . Case 2a(with pb3 tightly constrained). LMPs

27. Let’s increase the load at the highest price bus, bus #3, from 1.1787 to 1.1887 per unit, an increase of 1 MW. Resulting dispatch/flows are below, together with the Case 2a dispatch/flows. Case 2b flows/dispatch (PB3 constrained, Pd2=1.1887) Case 2a flows/dispatch (PB3 constrained, Pd2=1.1787) Case 2b To supply an additional MW at bus 3, the generation levels of 2 different units had to be modified. Specifically, Pg2 was decreased from 1.1803 to 1.1778, a decrease of 0.0025 pu (0.25 MW). Pg4 was increased from 0.4984 pu to 0.5109 pu, an increase of 0.0125 pu (1.25 MW). Thus, Pg4 was increased enough to supply the increased load at bus 3 and the decreased gen at bus 2. Question: Why did we not just increase Unit 2 or increase Unit 4 by 1 MW?

28. Case 2b flows/dispatch (PB3 constrained, Pd2=1.1887) Case 2a flows/dispatch (PB3 constrained, Pd2=1.1787) Case 2b Answer: Because the resulting flow on branch 3 would exceed its capacity!!! In fact, it is not possible to supply additional load at bus 3 with only a single unit increase. We will always have to compensate for the load AND redispatch to compensate for the additional flow on the branch 3. As a result, the nodal price at bus 3 is a function of the generation costs at those buses that are used in the particular redispatch that achieves the minimum cost.

29. www.misoenergy.org/LMPContourMap/MISO_All.html $33.30 $24.06 $38.99 $114.82 $36.08 $40.21 4:30pmCT, Monday Nov 28, 2016 29

30. www.misoenergy.org/LMPContourMap/MISO_All.html $31.75 $23.04 $37.10 $101.39 $33.48 $36.96 4:35pmCT, Monday Nov 28, 2016 30

31. Subject to 1. SCUC obj fnct also includes regulation term, separating reg-up from reg-down. Security-constrained unit commitment (SCUC) 2. “Value” terms in obj fnct are set by stepped curves established by ISO. Max demand Σ di+wi<DMAXi for all I,t (13) • We allow offers and bids to be made on energy & reserves. This problem is solved across multiple time periods, usually 24 hrs (1 hr at a time) but sometimes fewer (e.g, 4 or 6) and sometimes more. The above is a simplified version. The MISO Business Practice Manual BPM-002-r11, Chapter 4, provides a detailed description of the SCUC. See https://www.midwestiso.org/Library/BusinessPracticesManuals/Pages/BusinessPracticesManuals.aspx.

32. They are both tools to solve optimization problems. But different optimization problems. Here are some observations. SCUC Objective SCED Objective Simplified versions of SCED and SCUC • Decision variables are gi, di, ri, wi • Objective & constraints are linear • Decision variables continuous valued • It is a linear program (LP). • It is a convex programming problem. • It is solved by simplex, very efficient. • For a single time period (5 min). • It provides LMPs. • Decision variables are zit, git, yit, xit • Objective & constraints are linear • zit, yit, xit are discrete, git is continuous • It is a mixed integer linear program (MIP). • It is a non-convex programming problem. • It is solved by branch and bound. • For multiple time periods (24 hrs) • It does not provide LMPs on its own (+SCED)

33. The next slide is divided into three columns, one each for • Day-ahead market, • Reliability assessment commitment process, and • Real-time market • For each column, there are two main sections. • The upper section, in dark blue, yellow, and green, say what its name is (dark blue), what kind of market it is (yellow), and what it does (green). • The lower section, in light blue and pink, identifies the software applications used within the function, either SCUC (light blue) or SCED (pink). Two markets and a process

34. DAY-AHEAD MARKET (DAM) (Intraday) Reliability Assessment Commitment Process (RAC) REAL-TIME MARKET (RTM) The Day-Ahead Energy and Operating Reserve Market is a financially binding market that clears energy, reg reserve, spin reserve & supp reserve hourly. The Reliability Assessment Commitment (RAC) process is a process to commit resources, schedule regulating reserve on committed resources and/or release emergency operating ranges on resources when appropriate, hourly for use in the Real-Time Energy and Operating Reserve Market. The RAC process can be executed on a multi-day, day-ahead and/or intra-day basis. The Real-Time Energy and Operating Reserve Market is a financially and physically binding market that clears energy, reg reserve, spin reserve and supp reserve every 5 minutes. Two markets and a process SC-SCUC commits resources, schedules regulating reserves on committed resources and/or releases emergency operating ranges on resources. SC-SCED is used in Real-Time Energy/Operating Reserve Market to dispatch & price energy, regulating reserve, spinning reserve and supplemental reserve on a 5-minute basis. SC-SCUC is used in the RAC process to commit resources, schedule regulating reserves on committed resources and/or release emergency operating ranges on resources for the Real-Time Energy and Operating Reserve Market. SC-SCED is used to clear/price energy, regulating reserve, spinning reserve and supplemental reserve on hourly basis. Ref: M. Tackett, Experience with Implementing Simultaneous Co-optimization In The Midwest ISO Energy & Operating Reserve Markets, IEEE PES General Meeting, 2009.

35. Two markets: “Energy & operating reserve” are 2 different markets, 1 for buying/selling energy, 1 for buying/selling operating reserve. • Co-optimization: The first “SC” in SC-SCED/SC-SCUC stands for “simultaneous co-optimized” referring to the fact that both energy & operating reserve markets are cleared within 1 optimization formulation. • Reserves: Regulation reserve supplies minute-by-minute variation in net-demand via AGC. Spinning/supplemental reserve provide backup for contingencies (gen loss). Spinning is inter-connected, supplemental need not be; both must be available within 10 mins of a request. • Financially-binding: a settlement will occur; buyers will pay and sellers will be paid according to the market outcome. • Physically-binding: solution will be imposed on the system. • Use of SC-SCED: In DAM, SC-SCUC solves once per hour and then for that hour, SC-SCED is also solved. RTM uses the RT commitment as input to SC-SCED in computing RT dispatch every 5 minutes. • LMPs: SC-SCUC gives hourly commitment and dispatch, but w/ limited network modeling, therefore no nodal prices (LMPs). SC-SCED, given a commitment and full network modeling, gives dispatch & nodal prices. • Contingencies: Transmission security constraints for SC-SCUC are enforced via a predefined constraint list for the SCUC and a simultaneous feasibility testing (SFT) function iterating with SCED. Two markets - comments

36. Co-optimization, in the context of electricity markets, refers to the simultaneous clearing of two or more commodity markets within the same optimization problem. • Most ISOs clear 3 commodity markets within their co-optimization: • Energy • Regulating reserve • Contingency reserve Co-optimization (SC-SCUC) Operating reserve K. Wissman, “Competitive Electricity Markets and the Special Role of Ancillary Services, slides presented at the Licensing/ Competition and Tariff/Pricing Comm Meeting, Feb 4-5, 2008. Cooptimization optimizes two (or more) objectives which depend on different but related decisions: min f1(x)+f2(y) Optimize generation f1(x) and reserves f2(y) where x+y<=capacity (and therefore x and y are related!) Multiobjective optimization optimizes two (or more) objectives which depend on the same decisions: min f1(x)+f2(x) How to choose operating condition x to achieve good risk-cost f1-f2 trade-off?

37. MISO and PJM balancing areas 37

38. RT LMPs in the MISO and PJM balancing areas 7:20 am (CST) 9/8/2011 Source: MISO - PJM Interconnection Joint and Common Market Web site, previously at www.miso-pjm.com/ but not maintained. 38

39. RT LMPs in the MISO and PJM balancing areas 7:40 am (CST) 9/8/2011 Source: MISO - PJM Interconnection Joint and Common Market Web site, previously at www.miso-pjm.com/ but not maintained. 39

40. Average annual locational marginal prices 40

41. Locational marginal prices – effect of transmission. 41

42. RT LMPs in the MISO and PJM balancing areas - temporal variation for four different nodes 6:00 am-noon (CST) 8/28/2012 42

43. RT LMPs in the MISO balancing area March 4, 2013, 10:20 CST 43

44. Ancillary services in the MISO balancing area March 4, 2013, 10:20 CST 44

45. RT LMPs in the MISO balancing area April 21, 2014, 9:41 CST https://www.misoenergy.org/LMPContourMap/MISO_All.html 45

46. Ancillary services in the MISO balancing area https://www.misoenergy.org/MarketsOperations/RealTimeMarketData/Pages/AncillaryMarketMCP.aspx April 21, 2014, 9:44 CST 46

47. Day-ahead LMPs in ISO-NE balancing areas For hour ending 11:00 am (EST) 9/8/2011 New England ISO website, at http://www.iso-ne.com/portal/jsp/lmpmap/Index.jsp but no longer available. 47

48. RT LMPs in the ISO-NE balancing areas 10:25 am (EST) 9/8/2011 New England ISO website, at http://www.iso-ne.com/portal/jsp/lmpmap/Index.jsp but no longer available. 48

49. RTAncillary service prices in ISO-NE bal areas TMSR=10min spinning rsrv TMNSR=10min non-spinning rsrv TMOR=30min operating rsrv Regulation clearing price is $5.11/MW. Load Zones: Connecticut (CT), Southwest CT (SWCT), Northeast Massachusetts/Boston (NEMABSTN) 10:25 am (EST) 9/8/2011 New England ISO website, at http://www.iso-ne.com/portal/jsp/lmpmap/Index.jsp but no longer available. 49

50. Operating day commences. RAC process closes; new units notified. Market time line 2000 0000 Ref: A. Botterud, J. Wang, C. Monteiro, and V. Miranda “Wind Power Forecasting and Electricity Market Operations,” available at www.usaee.org/usaee2009/submissions/OnlineProceedings/Botterud_etal_paper.pdf