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WECC Introduction to SPP EIS Market June 26, 2008.

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Presentation on theme: "WECC Introduction to SPP EIS Market June 26, 2008."— Presentation transcript:


2 WECC Introduction to SPP EIS Market June 26, 2008

3 3 SPP at a Glance

4 4 The SPP Difference Relationship Based Member Driven Independence Through Diversity Evolutionary vs. Revolutionary Reliability and Economics Inseparable

5 5 SPP Milestones 1941: Formed to serve defense needs 1968: NERC Regional Council 1980: Telecommunications network 1991: Operating reserve sharing 1994: Incorporated as non-profit 1997: Reliability Coordination 1998: Tariff Administration 2001: Regional Scheduling 2004: FERC Approved RTO 2006: Contract Services 2007: Launched EIS Market, NERC Regional Entity

6 6 SPP at a Glance Little Rock based 300+ employees $101M operating, $24M capital (2008) 24 x 7 operation Full redundancy and backup site

7 7 SPP at a Glance 255,000 square miles of service territory $4.6 billion in transmission gross investment 52,301 total miles of transmission lines 4.5 million customers served 42.4 GWs of peak demand 55 GWs of generation capacity

8 8 SPP Members 12Investor-Owned Utilities 11Cooperatives 8Municipals 2State Agencies 2 Independent Transmission Companies 4Independent Power Producers/Wholesale Generation 1Contract Participant 11Marketers 51

9 9 SPP Transmission Map

10 10 Markets 101 EI Market Overview

11 11 What is a Market? General Concept An interaction between buyers and sellers RTO Facilitated Market Spot energy market required by FERC Allows participants to offer resources into the market Designed to promote use of least cost generation for Imbalance SPP Market SPP facilitates the marketplace, overseeing the activities of the market, insuring reliability, and forecasting supply requirements and providing Market Monitoring oversight.

12 12 Benefits of the SPP EIS Market Asset owners benefit from pooling their resources and gaining access to lower, more transparent pricing. GenCos benefit by having the option of reducing their generation and buying lower cost energy from the SPP market to serve their load, and by offering their generation into the marketplace for exposure to an increased customer base. GenCos are also able to more closely operate to their economical efficiency point. LSEs benefit from more efficient competition among suppliers (generators) which should lower spot energy prices.

13 13 Spot Balancing energy market Locational Imbalance Pricing (nodal) Voluntary Offers on Resources Charges on Imbalance Energy Uninstructed Deviation Charge Hourly Settlement Weekly Invoicing Physical Transmission Rights Self-commitment of Resources by Owners SPP EIS Market Highlights

14 14 All Load and resources within SPP tariff footprint are subject to financial settlement of Imbalance Energy. The EIS market is not, by its nature, thick or thin. The participation by resources in selling energy into the market and setting price is based upon each participant's evaluation of the benefits of selling energy to the market, and submitting offers accordingly. The financial impact on both resources and load is within the control of the participants through the use of energy schedules. Participants with both load and resources have the hourly imbalance settlement for both load and resources netted prior to invoicing. SPP EIS Market Highlights

15 15 SPP EIS Market Highlights Resources may either be: Sellers into the market (Available status) or; Self-dispatched to serve scheduled transactions and/or native load. Dispatch is regional and calculated using a security constrained economic dispatch (SCED) every 5 minutes. If a resource is Self-dispatched, it is still subject to imbalance settlement if actual output does not match scheduled output. Any resource that is offered for SPP dispatch has the entire asset subject to dispatch (within the "Dispatchable Range"). SPP EIS market does not supersede any MPs obligations to any other capacity or ancillary service obligations. Control Areas (CA) and asset owners will continue to use the same procedures used today to manage capacity adequacy, reserves, and other reliability-based concerns.

16 16 Market Comparison Real-time Energy Market Locational Pricing Day-Ahead Energy Market - Financial Transmission Rights Security Constrained Unit Commitment Mandatory Offers Energy Schedules without reservations (FinSched/eSched) Real-time Energy Market Locational Pricing No Day-Ahead Market -- Bilateral Markets Used Physical Transmission Rights Unit Commitment by Owner Voluntary Offers Energy Schedules using reservations MISOPJM SPP

17 17 What is Imbalance Energy? Imbalance energy (or Energy Imbalance) is the difference between what actually happens for each generator and load location, and what they prearranged through schedules. Energy Imbalance = Actual Production/Usage – Scheduled Production/Usage SPP instructs asset owners to move their generation output based on offer curves while maintaining reliability and balance (matching generation to load). The amount of increase or decrease in generation is paid for by the asset owner needing the energy.

18 18 What is the Energy Imbalance Service? EIS is the dollar amount associated with the imbalance energy. EIS is calculated by taking the amount of Energy Imbalance and multiplying by the price at a specific point on the energy grid. Energy Imbalance Service = Imbalance Energy x Locational Imbalance Price (LIP)

19 19 Lets say that Generator A is scheduled to provide Load B 100 MWh of energy. But at the end of the hour, the energy output of Generator A was only 90 MWh, and the energy consumption of Load B was also only 90 MWh. Has an imbalance occurred in this situation? Gen A 100 MWh Gen A 90 MWh Load B 100 MWh Load B 90 MWh Scheduled Actual Note: Generation Injections are (-) and Load Withdrawals are (+) as viewed from an SPP settlement reference frame for EIS. Imbalance Energy Example

20 20 Imbalance Energy Example Imbalance (Gen A) = (-90 MWh Actual) – (-100 MWh Scheduled) Imbalance (Gen A) = 10 MWh Imbalance (Load B) = (90 MWh Actual) – (100 MWh Scheduled) Imbalance (Load B) = -10MWh Notice that even though the system was in balance (generation matched load), by definition there was an imbalance at each location. Actual and Scheduled were not equal. Actual minus Scheduled

21 21 Pricing Imbalance Energy in an Unconstrained & Constrained System Imbalance energy is priced depending on which resources are deployed to meet the load requirements. This is known as Locational Imbalance Pricing or LIP. An unconstrained system will have a single system wide price, or a System Marginal Price. LIP recognizes that cost may vary at different times and locations based on real-time system conditions. Constraints on the system can cause price divergence among the various nodes due to the out-of-order dispatch needed to prevent operating limit violations. With LIP, asset owners know the price per MWh of electricity at various intersections on the system (nodes).

22 22 Heres an example… Generator A offers 10 MW@ $15/MWh Generator B offers 10 MW@ $30/MWh Generator C offers 10 MW@ $20/MWh To supply 15 MWh of energy to a load in an unconstrained system, the market selects the most economical generation within current reliability standards. In this case, Generators A and C. Generator A10 MW@ $15/MWh Generator C5 MW@ $20/MWh (sets price as providing the next increment of energy) In this case, Generators A and C would both get paid $20/MWh to serve 15 MWh of load Locational Imbalance Price (Unconstrained)

23 23 But what if it is impossible to deliver power economically within current reliability standards? Binding constraints (preventing a limit violation) usually result in: Generation being dispatched out of economic order Different prices for energy at different points in the system (or price divergence) When there are constraint violations, action must be taken to maintain reliability standards. Post-Market Energy Imbalance Process

24 24 Pricing Imbalance Energy Knowing that constraints can cause different load points in the system to have different prices, lets revisit a previous example: Imbalance (Gen A) = (-90 MWh Actual) – (-100 MWh Scheduled) Imbalance (Gen A) = 10 MWh Imbalance (Load B) = (90 MWh Actual) – (100 MWh Scheduled) Imbalance (Load B) = -10MWh This nets to zero, but a system constraint could cause the LIP at Gen A to be different than the LIP at Load B. A System Marginal Price would net to zero dollars between these two nodes For settlement purposes, an energy injection is a negative value

25 25 Settling an Imbalance Financially Suppose the following: LIP @ (Gen A) = $30/MWh LIP @ (Load B) = $40/MWh The resulting charges would be: EIS (Gen A) = $30/MWh x 10 MWh = $300 (MP pays SPP) EIS (Load B) = $40/MWh x -10 MWh = -$400 (SPP pays MP) The net imbalance is zero (generation equaled load), but there is a net payment of $100 ($300+(-$400)) to Load B because of different prices at different points in the system. NOTE: A (+) EIS indicates that SPP will receive payment from the Participant (a charge) A (-) EIS indicates that SPP will pay out to the Participant (a credit)

26 26 Example 1: No Market Participation GenA has a bilateral contract with Load A and schedules 200 MWh at $40/MWh to Load A. It costs GenA $30/MWh to produce the energy. Generator A has a profit of: ($40/MWh - $30/MWh) x 200 MWh = $2,000 Gen A 200 MWh $30/MW Load A 200 MWh Scheduled Bi-Lateral Contract $40/Mw

27 27 Example 2: Market Participation GenA and Load A have a bilateral schedule for 200 MWh. GenA also decides to offer its generation into the SPP market @ $40/MWh. The SPP Market can provide energy @ $25/MWh from other resources. Therefore, SPP instructs GenA to go to Min MW (10 MW) because its price is higher than the LIP. Gen B MWh $25/MW Gen A 200 MWh $40/MW Load A 200 MWh Scheduled = 200 MW @ $40/MW Actual = 10 MW @ 40/MW Bi-Lateral Contract $40/Mw Scheduled = 0 MW Actual = 190 MW @ $25/MW Market Dispatch $25/Mw

28 Example 2: Market Participation Gen A EIS = (Actual – Scheduled) x LIP Gen A EIS = [-10 MWh – (-200 MWh)] x $25/MWh Gen A EIS = 190 MWh x $25/MWh Gen A EIS = $4,750 (Paid to SPP) GenA pays SPP $4,750 SPP disperses this money to the generator(s) that provided the 190 MW of energy. Gen B MWh $25/MW Gen A 200 MWh $40/MW Load A 200 MWh Scheduled = 200 MW @ $40/MW Actual = 10 MW @ 40/MW Bi-Lateral Contract $40/Mw Scheduled = 0 MW Actual = 190 MW @ $25/MW Market Dispatch $25/Mw $4750 A positive value

29 29 Example 2: Market Participation Gen B EIS = (Actual – Scheduled) x LIP Gen B EIS = [-190 MWh – (0 MWh)] x $25/MWh Gen B EIS = -190 MWh x $25/MWh Gen B EIS = - $4,750 (paid to this resource) SPP pays Gen B $4,750 Gen B MWh $25/MW Gen A 200 MWh $40/MW Load A 200 MWh Scheduled = 200 MW @ $40/MW Actual = 10 MW @ 40/MW Bi-Lateral Contract $40/Mw Scheduled = 0 MW Actual = 190 MW @ $25/MW Market Dispatch $25/Mw $4750 A negative value

30 30 Example 2: Market Participation Load A EIS = (Actual – Scheduled) x LIP Load A EIS = (200 MWh – 200 MWh) x $25/MWh Load A EIS = 0 MWh x $25/MWh Load A EIS = $0 Load A pays no EIS Gen B MWh $25/MW Gen A 200 MWh $40/MW Load A 200 MWh Scheduled = 200 MW @ $40/MW Actual = 10 MW @ 40/MW Bi-Lateral Contract $40/Mw Scheduled = 0 MW Actual = 190 MW @ $25/MW Market Dispatch $25/Mw $4750 No change to scheduled withdrawal

31 31 Example 2: Market Participation GenA paid SPP $4,750 in lieu of spending $5,700 to generate the 190 MWh of energy itself. This saved GenA $950 by offering the resource to the Market GenA continues to receive compensation from load A under its bilateral agreement (200MWh x $40/MWh) of $8000. GenA profits increased from $2000, to $2950 Gen B MWh $25/MW Gen A 200 MWh $40/MW Load A 200 MWh Scheduled = 200 MW @ $40/MW Actual = 10 MW @ 40/MW Bi-Lateral Contract $40/Mw Scheduled = 0 MW Actual = 190 MW @ $25/MW Market Dispatch $25/Mw $4750

32 32 Only schedules with a source and sink associated with registered settlement locations will be used in market settlement. NERC registry entries in the tag must be mapped to valid settlement locations. Schedules can be Tags (Point to Point) or Native Load Schedules (NLS) Scheduling reduces the imbalance charges as a result of actual meter values not matching schedule values. Market participants typically NLS schedule from their generators to their loads to avoid price exposure. Market Participants need to schedule their native load at a settlement location level. Introduction to Interchange Scheduling

33 33 Physical and Market Schedules Energy Schedules are classified depending on the Resource Status submitted in the Resource Plan. If Self-Dispatched Resource, the schedule will be a Physical Schedule. If the Resource is offered into the Market (Available) or the source is a Settlement Location for Load, the schedule will be considered a Market Schedule. If the MP submits both a schedule and an offer, the dispatch system will ignore the scheduled output for each Resource and calculate a Dispatch Instruction for the Resource based on the Offer Price and the information in the Resource Plan.

34 34 Satisfying Energy Requirements Example: A Market Participant has an obligation of 500 MW at a Settlement Location(s) in a particular hour and two Resources, each having a minimum operating limit of 60 MW and a maximum operating limit of 300 MW. Gen 1 Max 300 MW Min 60 MW Gen 2 Max 300 MW Min 60 MW 500 MW Obligation BA Load

35 35 Satisfying Energy Requirements The MP could: Self Dispatch both of its Resources Indicate it intends to operate its Resources (on its Resource Plan) at an aggregate 500 MW Generate in real time 500 MW, consistent with the sum of its schedules The MP must also schedule an aggregate of 500 MW from its Resource Settlement Locations to meet its Load obligations

36 36 Dispatch value will be the sum of schedules includes all tagged (energy and dynamic) schedules, NLS schedules and Reserve Sharing Schedules that are contained in RTO_SS. These resources may only be dispatched outside of the sum of the schedules in a system emergency (a manual out of merit energy or OOME dispatch instruction sent by the Market Operator). Self-Dispatched Resources Introduction

37 37 Satisfying Energy Requirements OR the MP could: Make both Resources available for SPP dispatch SPP can then calculate economic base points within the operating range of 60 MW to 300 MW on each unit While not explicitly required, the MP could also choose to schedule from its Resource Settlement Locations (and still allow the SPP MOS to dispatch unit)

38 38 Satisfying Energy Requirements OR the MP could: Make one of its Resources available for SPP dispatch. Self-Dispatch its other Resource by indicating on its Resource Plan that it intends to operate that Resource at 200 MW (and Scheduled as such) and generate in real time at the dispatched 200 MW value. Self-Dispatch of the second unit at 200 MW is required so that the remaining load requirements can be covered by the other Resource (made available) being dispatched by SPP MOS While not explicitly required, the MP could also choose to schedule from its offered Resource Settlement Location (300 MW).

39 39 Reserve Sharing Event Market Participants providing assistance for a reserve sharing event deploy specific Resources at their discretion to respond to the event. Schedules of energy deployment from the Reserve Sharing System (RSS) will ensure that Self-dispatched Resources are sent consistent instructions. Schedules allow the MOS to utilize the withheld capacity from Market Resources allocated as carrying Spinning and/or Supplemental Operating Reserves.

40 40 With the implementation of an energy market not all schedules/tags represent physical/actual flows. NERC has made modifications to the Interchange Distribution Calculator (IDC) to reflect MISO/PJM market design. SPP has complied with the same modifications made for MISO/PJM. Due to SPPs use of schedules as a physical transmission rights and the resulting difference from MISO implementation, SPP has developed the Curtailment Adjustment Tool (CAT) TLR used to relieve flowgate loading when flow levels approach the Security Operating Limit (SOL), or the Interconnect Reliability Operating Limit (IROL) of that flowgate. Uses both the NERC IDC and the SPP CAT tools in the schedule curtailment process Transmission Loading Relief (TLR)

41 41 TLR curtails two types of constraint flow: Tagged Schedules by the NERC IDC Market Flows using the SPP CAT Market flow is determined by the MFC (Market Flow Calculator) and sent to NERC IDC every 15 minutes Transmission Loading Relief (TLR)

42 42 SD = Self Dispatched MD = Market Dispatched Control Area Red = SPP Market Flow (CAT curtailed) CA SPP Green = NERC IDC Curtailment SPP Market Footprint SD MD SD MD SD MD NLS EIS TAGS EIS Market Flow vs. IDC Transactions TAGS

43 43 Five-Minute Deployment 0000 0005 0010 0015 0020 0025 Calculations Communications Ramp Deployment MW reached Calculations Communications Ramp Snapshot Calculations Communications Ramp Snapshot Note: for Manual status: Snapshot = Deployment Snapshot T T- 5 minutes T-10 minutes T-15 minutes T T- 5 minutes T-10 minutes Deployment MW reached Deployment MW reached Deployment MW sent Deployment MW sent Deployment MW sent

44 44 EIS Market Experience

45 EIS Market is a Marginal Market

46 But Robust, Capacity Available to the EIS Market 46 ** If Manual was included in the SPP-Wide Availability calculation, the average SPP-Wide Availability would be approximately 73%.

47 % Total Capacity Dispatchable

48 Electricity Sales in the EIS Market 48

49 Share of EIS Market Sales (Anonymously Ranked) 49

50 Graphically

51 Regional Monthly Average Prices

52 Electricity Prices Compared with Neighboring Regions 52 * The average prices shown here represent simple average prices.

53 Interval Prices Beyond Thresholds 53

54 Top 10 Congested Flowgates 54

55 Congestion Resolution

56 Transmission/Bi-Lateral Market Unaffected

57 EIS Market Benefits Analysis The SPP Board of Directors approved implementation of the EIS Market based largely upon the benefits to the region projected by the CRA cost/benefit study. Were they right? 57

58 EIS Market Benefits Analysis The SPP Board of Directors approved implementation of the EIS Market based largely upon the benefits to the region projected by the CRA cost/benefit study. Were they right? YES! 58

59 59 Incurred Avoided Trade Benefit $286 Million - $ 393 Million = $ 107 Million Adjustments - $ 4 Million _____ $ 103 Million A Simplified Regional Calculation 7,560 GWh @ $38 /MWh 7,560 GWh @ $52 /MWh

60 State of Market External Market Monitor Statements A.EIS Market is a success – do more markets B.Significant Transmission Investment – make more transparent C.Huge wind development – celebrate and manage D.Keep attracting new competition – lower price, more innovation E.Manage transmission congestion – a work of/in progress

61 Carl Monroe, EVP 501-614-3218

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