Future Market Implementation

Transcription

1 SPP.org 1

2 Future Market Implementation Requirements - way forward MWG June 29 th, 2009 SPP.org

3 WebEx Instructions Please submit questions to host. If it is a long question you can type a summary until we are available to discuss We will break throughout the presentation for additional questions and discussion on the phone SPP.org 3

4 Target Audience Pi Primary audience is the MWG members that will be making design decision Secondary audience is Participant and Staff education about Future Markets SPP.org 4

5 Requirements Gathering Process Staff MWG Legend Togethe r Review MISO BPMs Pull Topics Research NY, NE and PJM Info Discussion Decision Sessions Points Session Decisions Draft Decision Matrix Review Decision Matrix Draft Protocols Review Protocols - provide updates to Staff SPP.org 5

6 Topic Schedule Feb 2 nd Market Structure Product to be Offered Resources March 30 th Canceled due to CHTF April 6 th Modeling Pseudo ties and JOU Virtuals Demand Response June 1 st June 8 th Reserve Sharing Credit July 13 th Feb 9 th June 22 nd Registration Market to Market Resource Qualification April 13 th June 29 th Market Timeline BA Functions Losses Demand Curves Feb 23 rd April 27 th Scarcity Pricing Resource Adequacy Opportunity costs Market Functions I May 4 th July 6 th March 2 nd Emergency Condition Technical Market Functions II Load Forecast Business Continuity Other March 9 th May 11 th Energy Transactions Settlements I Congestion Hedging March 23 rd May 26 th Make Whole Payment Settlements II Market Mitigation SPP.org 6

7 Topic Schedule Feb 2 nd Market Structure Product to be Offered Resources March 30 th Canceled due to CHTF April 6 th Modeling Pseudo ties and JOU Virtuals Demand Response June 1 st June 8 th Reserve Sharing Credit July 13 th Feb 9 th June 22 nd Registration Market to Market Resource Qualification April 13 th June 29 th Market Timeline BA Functions Losses Demand Curves Feb 23 rd April 27 th Scarcity Pricing Resource Adequacy Opportunity costs Market Functions I May 4 th July 6 th March 2 nd Emergency Condition Technical Market Functions II Load Forecast Business Continuity Other March 9 th May 11 th Energy Transactions Settlements I Congestion Hedging March 23 rd May 26 th Make Whole Payment Settlements II Market Mitigation SPP.org 7

8 June 29 th Losses Average or marginal losses for new market Scarcity Pricing Demand Curves Calculation of opportunity costs SPP.org 8

9 June 29 th Losses Average or marginal losses for new market Scarcity Pricing Demand Curves Opportunity costs SPP.org 9

10 Losses Average Losses Losses are calculated in an offline process and not used in the SCED calculation Marginal Losses Losses are calculated by the SCED engine Gives local resources a lower total cost (LMP) with respect to a load than a unit farther away (all other prices held constant) Over collects revenue that must then have to redistributed It is staffs understanding that the MWG has previously decided that marginal losses are undesirable in the market footprint. The next section was put together for information only SPP.org 10

11 PJM - Marginal Losses Implementation Training PJM switched to Marginal Losses in SPP.org 11

12 PJM - Marginal Losses Implementation Training SPP.org 12

13 PJM - Marginal Losses Implementation Training SPP.org 13

14 PJM - Marginal Losses Implementation Training SPP.org 14

15 PJM - Marginal Losses Implementation Training SPP.org 15

16 PJM - Marginal Losses Implementation Training SPP.org 16

17 PJM - Marginal Losses Implementation Training SPP.org 17

18 PJM - Marginal Losses Implementation Training SPP.org 18

19 PJM - Marginal Losses Implementation Training Before Marginal Losses SPP.org 19

20 PJM - Marginal Losses Implementation Training Before Marginal Losses SPP.org 20

21 PJM - Marginal Losses Implementation Training Before Marginal Losses SPP.org 21

22 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 22

23 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 23

24 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 24

25 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 25

26 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 26

27 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 27

28 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 28

29 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 29

30 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 30

31 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 31

32 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 32

33 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 33

34 PJM - Marginal Losses Implementation Training Marginal Losses Calculation SPP.org 34

35 Other RTO s MISO, PJM, NY, NE are marginal losses ERCOT is average losses PJM in 2007 switched from Average to Marginal Losses PJM is working on developing a loss hedging mechanism SPP.org 35

36 June 29 th Losses Average or marginal losses for new market Scarcity Pricing Demand Curves Opportunity costs SPP.org 36

37 June 29 th Losses Average or marginal losses for new market Scarcity Pricing Demand Curves Opportunity costs SPP.org 37

38 Scarcity Pricing Based on the idea that t under scarcity conditions generating units will receive higher compensation. This additional revenue stream helps to incentivize investment in new generation and promotes overall system reliability. When supply conditions are tight and drop below a pre- determined d threshold h level, l the price for additional MW significantly ifi rises. May be due to capacity, ramp or stranded MWs due to constraints SPP.org 38

39 SCARCITY PRICING: MORE ON LOCATIONAL OPERATING RESERVE DEMAND CURVES William W. Hogan Mossavar-Rahmani Center for Business and Government John F. Kennedy School of Government Harvard Harvard Electricity Policy Group March 13, 2009 (Revised March 23, 2009) SPP.org 39

40 Electricity Markets Scarcity Pricing Scarcity pricing presents one of the important challenges for Regional Transmission Organizations (RTOs) and electricity market design. Simple in principle, but more complicated in practice, inadequate scarcity pricing is implicated in several problems associated with electricity markets. Investment Incentives Inadequate scarcity pricing contributes to the missing money needed to support new generation investment. The policy response has been to create capacity markets. Better scarcity pricing would reduce the challenges of operating good capacity markets. Demand Response Higher prices during critical periods would facilitate demand response and distributed generation when it is most needed. The practice of socializing payments for capacity investments compromises the incentives for demand response and distributed generation. Renewable Energy Intermittent energy sources such as solar and wind present complications in providing a level playing field in pricing. Better scarcity pricing would reduce the size and importance of capacity payments and improve incentives for renewable energy. Transmission Pricing Scarcity pricing interacts with transmission congestion. Better scarcity pricing would provide better signals for transmission i investment. t Improved scarcity pricing i would mitigate t or substantially remove the problems in all these areas. While long-recognized, only recently has there been renewed interest in developing a better theory and practice of scarcity pricing 1. 1 FERC, Order 719, October 17, SPP.org 40

41 Pricing and Demand Response Early market designs presumed a significant demand response. Absent this demand participation most markets implemented inadequate pricing rules equating prices to marginal costs even when capacity is constrained. This produces a missing money problem. SPP.org 41

42 Electricity Markets Scarcity Pricing The theory and practice of scarcity pricing intersect important elements of electricity systems and economic dispatch. Reliability. By definition, scarcity conditions arise when the system is constrained and dispatch is modified to respect reliability constraints. Dispatch. Simultaneous optimization of energy and reserves means that scarcity in either effects prices for both. Resource Adequacy. The standards for resource adequacy and operating security are not fully integrated or compatible. A critical connection is the treatment of operating reserves and construction of operating reserve demand curves. The basic idea of applying operating reserve demand curves is well tested and found in operation in important RTOs. NYISO. See NYISO Ancillary Service Manual, Volume 3.11, Draft, April 14, 2008, pp, ISONE. FERC Electric Tariff No. 3, Market Rule I, Section III.2.7, February 6, MISO. FERC Electric Tariff, Volume No. 1, Schedule 28, January 22, SPP.org 42

43 Electricity Markets Operating Reserves The underlying models of operating reserve demand d curves differ across RTOs. One need is for a framework that develops operating reserve demand curves from first principles to provide a benchmark for the comparison of different implementations. Operating Reserve Demand Curve Components. The inputs to the operating reserve demand curve construction can differ and a more general model would help specify the result. Locational Differences and Interactions. The design of locational operating reserve demand curves presents added complications in accounting for transmission constraints. Economic Dispatch. The derivation of the locational operating demand curves has implications for the integration with economic dispatch models for simultaneous optimization of energy and reserves. SPP.org 43

44 June 29 th Losses Average or marginal losses for new market Scarcity Pricing Demand Curves Opportunity costs SPP.org 44

45 June 29 th Losses Average or marginal losses for new market Scarcity Pricing Demand Curves Opportunity costs SPP.org 45

46 June 29 th Losses Average or marginal losses for new market Scarcity Pricing Demand Curves Opportunity costs SPP.org 46

47 Demand Curves Used in conjunction with the simultaneously l co-optimized i energy and reserve markets to properly and transparently price energy and reserves during scarcity conditions in capacity One of four approved approaches identified by FERC in Order No. 719 to address pricing during scarcity conditions and further promote entrance and responsiveness by demand response resources in the RTO Markets. Basic premise is to establish a price-based demand curve with increments to gradually increase the price for reserves during times of shortage. Through co-optimization, these higher prices are also reflected in the energy prices in order to maintain product priority and not incent participants to try and supply one product over another. SPP.org 47

48 Demand Curves Use of Demand Curves can be integrated t with market-wide and zonal level requirements. Energy prices also remain locational which helps in the dispatch and control of localized constrained facilities as well as providing good pricing signals to participants to help alleviate the scarcity capacity conditions. Under abundant conditions, demand curve sets amount cleared and supply offers set price Under shortage conditions, demand curve sets price and supply offers set how much clears. MISO, NYISO, and ISO-NE already employ forms of demand curves and simultaneous co-optimization of energy and reserve products PJM and Cal-ISO have both identified their intentions to develop this mechanism within their respective markets as well. SPP.org 48

49 Demand Curves Demand curve showing three breakpoints and increases in scarcity price. At Requirement, price goes to $0 Additional Scarcity Breakpoints Requirement Sample Demand Curve SPP.org

50 MISO Demand Curves Region-wide id for all Operating Reserves combined Zonal for all Operating Reserves combined Region-wide for regulation product Zonal for regulation product SPP.org 50

51 MISO Demand Curves Region-wide id Operating Reserve Demand Curve Formula price determination based on probabilistic assessment of loss of load following any single generator loss Minimum Scarcity Price set to the energy offer cap plus the reserve product offer cap (i.e. $ $100 = $1,100) Maximum Scarcity Price set to the projected Value of Lost Load (VOLL): currently set at $3500 in MISO SP = Max(VOLL * Probability bilit of Load Loss, Minimum i Scarcity Price) when cleared operating reserves < required reserves Different formulas for 0 to 100 MW scarcity and then above 100 MW SPP.org 51

52 MISO Demand Curves Zonal Operating Reserve Demand Curve Two breakpoints Cleared reserves < 10% of requirement: Scarcity Price = VOLL Zonal Regulating Reserve Demand Curve Price If Requirement*10% <= Cleared reserves < Requirement: Scarcity Price = $1100 SPP.org 52

53 MISO Demand Curves Region-wide id Regulating Reserve Demand Curve Single Breakpoint at Regulating Reserve Requirement Set based on pre-determined Monthly Average Peaker Proxy Price. Currently this amount is $1000. SPP.org 53

54 MISO Demand Curves Zonal Regulating Reserve Demand Curve Single Breakpoint at Zonal Regulating Reserve Requirement Equal to the Region-wide Regulating Reserve Scarcity Price. SPP.org 54

55 MISO Demand Curve Impacts on MCP Each Reserve Product has a Marginal Clearing Price calculated Shadow prices of multiple constraints are accounted for in the determination of each product MCP. Separate MCP for Demand Response for Spin and Supp MCP REG = γor + γor (z) + γrs + γrs (z) + γrr + γrr (z) + γgor MCP SPING = γor + γor (z) + γrs + γrs (z) + γgor MCP SPIND = γor + γor (z) + γrs + γrs (z) MCP SUPPG = γor + γor (z) + γgor MCP SUPPD = γor + γor (z) SPP.org

56 MISO Demand Curve Impacts on MCP γor = Operating Reserve Balance Shadow Price. Under abundant conditions, this price represents the marginal cost of supplying Operating Reserves. Under shortage, this price represents the demand curve price for the cleared Region-wide Operating Reserve γrs = Regulation + Spin Requirement Shadow Price γrr = Regulation Reserve Requirement Shadow Price (z) represents the zonal constraints γgor = Shadow price for generation supply constraint. Applies to Generator MCPs due to a constraint that a certain % of reserves must be carried by generation resources. SPP.org

57 New England Demand Curves New England has a different structure t for their optimization i of Operating Reserves than MISO Simultaneous optimization of energy and reserves does not include regulation. Regulation determined through separate offers an hour ahead. Ex-post Opportunity costs applied to set final expost Marginal Clearing Price for Regulation ISO-NE does not have separate capacity bids for operating reserve products in Real-time. All products cleared using physical operating characteristics of resources and incremental offer curves SPP.org 57

58 New England Demand Curves MCP for Operating Reserve products under normal circumstances is equal to 0 If redispatch is required but sufficient capacity is available, the highest opportunity cost will set the MCP If scarcity conditions exist, the following Reserve Constraint Penalty Factors (Demand Curves) apply zonal 30 Min OR RCPF = $50/MWh system 30 Min OR RCPF = $100/MWh system 10 min Non-Spin Reserve RCPF = $850/MWh system 10 min Spin Reserve e RCPF = $50/MWh. SPP.org 58

59 New England Demand Curves Although h Demand Curve prices seem to indicate higher h priority to 10 minute non-spin over 10-minute spin, product substitution and priority rules govern that product marginal clearing prices reflect priority from 10-minute spinning reserve down to 30 minute operating reserve. Price impacts for capacity shortages to meet the lower priority products will be reflected in the MCP for higher priority products, similar to MISO. SPP.org 59

60 New York Demand Curves New York does have simultaneous co-optimization i of regulation, spinning, supplemental and 30-minute supplemental The regulation demand curve has two breakpoints. Cleared regulation < regulation requirement 25 MW: Scarcity Price = $300/MW Regulation requirement 25 MW <= Cleared regulation < Regulation requirement: Scarcity price = $250/MW SPP.org 60

61 New York Demand Curves In addition to the regulation demand d cure NYISO defines 9 additional operating reserve demand curves, including zonal. The following eight have single breakpoint curves Total Spinning Reserves: SCP = $500/MW Eastern or Long Island Spinning Reserves: SCP = $25/MW Long Island Spinning Reserves : SCP = $25/MW Total 10-Minute Non-Synchronized Reserves : SCP = $150/MW Eastern or Long Island 10-Minute Non-Synchronized Reserves : SCP = $500/MW Long Island 10-Minute Non-Synchronized Reserves : SCP = $25/MW Eastern or Long Island 30-Minute Reserves : SCP = $25/MW Long Island 30-Minute Reserves : SCP = $300/MW SPP.org 61

62 New York Demand Curves One of the additional demand d curves has multiple l break points defined. That is the Total 30 Minute Reserve Curve Cleared < Requirement 400 MW: SCP = $200/MW, Requirement 400 MW < Cleared < Requirement 200 MW: SCP = $100/MW Requirement 200 MW < Cleared < Requirement: SCP = $50/MW SPP.org 62

63 June 29 th Losses Average or marginal losses for new market Scarcity Pricing Demand Curves Opportunity costs SPP.org 63

64 Opportunity Cost Most markets compensate units for lost opportunity costs for providing one product over another Easiest example is if a unit is cleared to Regulate with planned low LMPs. Then in the operating hour LMPs are high, and the unit is asked to reg down. They would have made more energy if they had not been cleared for Regulation as the capacity clearing price (MCP) for regulation did not make up for the expensive energy they had to forgo to regulate down. Different opportunity costs if there is a 5 min co optimized solution vs. hour ahead regulation procurement SPP.org 64

65 Oportunity Cost SPP.org 65

66 Opportunity Cost The previous slide shows the lost opportunity cost in a 5 min cooptimized real time solution. There is an additional lost opportunity cost if you move the regulation to an hour ahead market. This is due to the need to estimate real time LMP in the Hour Ahead (HA) market. To the extent that the RTO estimates the RT LMP incorrectly in the HA market there could be additional lost costs These additional lost costs are because the units my no longer be in the money with where the HA regulation market has set them up. And giving RT knowledge you would have deployed regulation differently than you did in the HA market SPP.org 66

67 June 29 th Losses Average or marginal losses for new market Scarcity Pricing Demand Curves Opportunity costs SPP.org 67

68 Decision session talking points Marginal or Average Losses Use of scarcity pricing? Use of demand curve? Define constraints that will utilize demand curves Define Make whole payments for any lost opportunity costs SPP.org 68

69 July 6 th High Availability Infrastructure What are other RTO s doing What are uptime requirements What is the Cost / Benefit Information to provide on the portal Contour maps Daily reports Participant support (NOC) SPP.org 69

70 Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q Project Startup Requirements Def (Establish PMO, Communications Team, Project Risks, Funding) RFP / Contracts FERC / State t Filings Business Practices BA, Update Tariff, ASM, States Sys Requirements System Dev Environment Build Integration Test Operation Testing Code Stabilization Cutover / Launch SPP.org 70

71 One Year Detail Timeline Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Information Sessions Decision Sessions Requirement Doc 15,000 foot document Draft / Review Protocol Task Force Breakout Cost Allocation, Make Whole Pmt,. Document RFPs RFP / Contracts FERC / State Filing Drafting System Development Ace Diversity Implement Sept 1 st, 2009 CBA Phase I Req A High Availability Req A RFP for Phase I CBA system changes concurrent with SPP.org Market RFP 71

72 Questions Manager of Market Development SPP.org 72