Recent Development in Reliable Energy Market in the US and Singapore

Transcription

1 Recent Development in Reliable Energy Market in the US and Singapore th June 2008 Electrical Engineering and Maintenance Forum World Engineering Congress, Bangkok, Thailand Dr. Panida Jirutitijaroen Department of Electrical and Computer Engineering National University of Singapore

2 Outline Market Structure and Trading Mechanism Overview Pennsylvania-New Jerseys-Maryland (PJM) Singapore New Electric Market Market Challenges and Reliability Issues Recent Development in PJM Recent Development in Singapore

3 Market Structure and Trading Mechanism Overview Pennsylvania-New Jerseys-Maryland Market Singapore New Electric Market

4 Before and After Deregulation Integrated utilities Generation Transmission Distribution Congestion management Reliability Generations Supply electricity Independent System Operators Transmission Congestion management Reliability Retailer Distribute to end consumers

5 Energy Trading Mechanism Bilateral contract Direct contract between consumer and supplier, for example, industrial consumer, retailer. Auctions Day Ahead Market Real Time Market or Balancing market

6 Market Clearing Price Firm 1 Bid function Firm 2 Bid function $ MCP Horizontal Sum of Bid function from each firm Demand MW MW that Firm 1 will supply MW that Firm 2 will supply

7 Energy Market Market structure in terms of ownership Market design Market operation/rules Energy market Ancillary services market Congestion management

8 Pennsylvania-New Jerseys- Maryland (PJM) Energy Market

9 Market Formation in the US

10 Different Market Structure in the US

11 PJM Statistics Largest centrally dispatched Independent System Operator (ISO) in the US 144,644 MW peak load (summer 06). Service > 51 million people Cover 13 states and D.C.

12 Independent System Operator (ISO) Or, Regional Transmission Organization (RTO) Independent from all market participants Market Monitoring Congestion management Provide ancillary services Transmission Planning

13 PJM Management Structure

14 PJM Market Design Energy market Day ahead market Real time market Ancillary services Regulation and Synchronized Reserve Blackstart Service Reactive Supply and Voltage Control Scheduling, System Control and Dispatch PJM Tariff Resource Adequacy Policy Reliability Pricing Model!! New Development!!

15 Day Ahead Market Generation companies submit willingness-tosupply bid for each hour in the following day Market operator forecast next day demand Market clearing price for each hour in the following day for day

16 Real Time Market Manage transmission congestion Generation companies submit willingnessto-supply bid in each 5/10 min. Market operators intersect this with residual demand. Market clearing price for each time interval in real time.

17 Pricing Method Locational Marginal Pricing (LMP) concept Energy purchase and sales in market Transmission congestion costs Physical flow-based pricing, not contract path Economic dispatch with transmission constraints. Price vary by node

18 110 MW 66 MW Locational Marginal Pricing Dispatched at 600 MW Brighton 600 MW $10/MWh E A 240 MW Thermal Limit Constrained Case Dispatch Solution Ignoring Thermal Limit D Dispatched 90 MW 200 MW $30/MWh 300 MW Sundance LMPs Brighton 600 MW 600 MW $10/MWh $15 $10.44 E A MW Thermal Limit Constrained Case $30 D 124 MW 200 MW $30/MWh Sundance 300 MW Alta 110 MW $14/MWh Dispatched at 110 MW 300 MW 300 MW Park City 100 MW B C $15/MWh Dispatched Total Dispatched 100 MW MW Solitude 520 MW $30/MWh Alta 300 MW 300 MW 110 MW B C $14/MWh Park City $21.14 $ MW $15/MWh Marginal Generators 15 Solitude 520 MW $30/MWh System Energy Price Transmission Congestion Cost LMP = + + Cost of Marginal Losses ( 07) The price to serve the next incremental load with transmission constraints at least cost

19 System Energy Price Optimal dispatch ignore transmission constraints Same price for every node Market clearing price Both day-ahead and real time market Market buyer pays system energy price Market seller paid system energy price

20 Transmission Congestion Cost Consider transmission constraints Sensitivity factor for the next incremental load at least cost Price vary by node Both day-ahead and real time market Load pays congestion price Generator paid congestion price Revenue credited to Financial Transmission Right (FTR) holders

21 Congestion Hedging Financial Transmission Right (FTR) Point to point (single or aggregated, hubs or zones) MW unit, financial title, not physical right Obtained from auction, bilateral contract Protect customer from increased cost due to transmission congestion

22 Cost of Marginal Losses Cost for system losses, real MW power loss Loss penalty factor (PF) 1 Penalty Factor at node i Δ System Power Loss 1 Δ Input Power at node i Without loss, all units has the same incremental cost. With loss, use penalty factor to modify the incremental cost. This will impact LMP. Cost of Marginal 1 Loss Generation Marginal Cost 1 PF

23 Energy Price (LMP) in Day-Ahead and Real-Time Market (Avg. in 2006)

24 Virtual Bidding Different price between two energy markets Potential profit from energy transaction Bid as virtual supply or virtual demand Financial transaction, not physical consumption Allow non-energy institution such as financial institution to involve in the market Reduce price difference in both day ahead and real time market

25 Ancillary Services Regulation Synchronized Reserve Blackstart Service Reactive Supply and Voltage Control Scheduling, System Control and Dispatch PJM Tariff

26 Regulation Market Fine-tuning generation to correct small load change Maintain system frequency Real time actual assignment Response to demand within 5 min Fulfilled by Self-scheduling Bilateral contract Spot purchase Regulation Market Clearing Price (RMCP) each hour of next day at 10 PM.

27 Synchronized Reserve Market Bring system back in balance after loss of Gen Obligation calculated based on load ratio share Fulfilled by Self-scheduling Bilateral trading Purchase from spinning market Synchronized Reserve Market Clearing Price (SRMCP) cleared hourly during operating day

28 Spinning Reserve Requirement Determine in MW each hour of the operating day 10-minute synchronized of 75% of largest contingency provided that 25% of the remaining is available on 10-minute non-synchronized reserve. Normally, equal to MW output of the largest unit online

29 Blackstart Service Restore power in blackout event Provide incentives to critical units PJM identify critical units Cost-based service calculated by PJM Credit to critical generators Transmission customers bear the cost

30 Reactive Supply & Voltage Control Maintain voltages in the limit Reactive Power service Revenue requirement approved by FERC (Federal of Energy Regulatory Commission) Zonal pricing by PJM charges transmission customers

31 Singapore New Electric Market (NEM)

32 Market Structure Wholesale Market Real Time Market Procurement Market Retail Market Options for end-consumes to choose the suppliers (currently 10 MWh or above) Regulator Energy Market Authority (EMA) responsible for market rules.

33 Transmission System Single owner, Singapore Power PowerAssets. Maintain transmission network both high voltage (transmission) and low voltage (distribution). Direct by PSO.

34 NEM Market Structure since 2001

35 NEM Parties Energy Market Company (EMC) Operate and administer wholesale markets Power System Operator (PSO) (a division of EMA) Ensure reliable and secure market operation Control dispatch of facilities in wholesale market Direct transmission network operation Market Support Services Licensees (MSSLs) Meter reading/ data management Supply electricity to small consumers (10MWh or below, around 1 million consumers)

36 NEM Financial Flow Chart

37 Wholesale Market Spot Market for energy, reserve and regulation. Auction-based, every half an hour Interruptible load can be assigned as a resource facility for reserve and regulation. Contract-based procurement market for ancillary services.

38 Market Clearing Engine (MCE) Computer model for least-cost dispatch Nodal price model Include system constraint Demand forecasted by PSO Generation bid offer and forecasted demand prepared by EMC Buyers pay Uniform Singapore Energy Price (USEP) which is weighted-average of nodal prices.

39 Retail Market Market Participant Retailers (MPRs) and contestable consumer purchase energy from wholesale market Non-Market Participant Retailers (NMPRs) purchase energy from MSSL Non-contestable consumers purchase energy only from MSSL.

40 Market Challenges and Reliability Issues

41 Electric Market Challenges Inelastic demand Consumer can not response to price change in time Market power* Withholding generations to increase market clearing price Excuses of maintenance, units down, *Market power = Firm reduces output or raise their bid prices in order to change the market prices.

42 Example of Market Rules Price cap Generations couldn t bid more than a certain price (usually $1000/MWh in US) Constrained bid function Generations could not bid X% above its history record, etc.

43 Electric Reliability Issues Capacity adequacy Reliability requirement/measurement Reliability cost Tools and operators failure Lack of adequate tools to visualize system conditions Lack of long distance communication tools to detect and identify system failure in short time

44 Capacity Adequacy Capacity addition does not match demand growth Poor market design No incentive to invest on generation No requirement on system installed generation No single entity responsible for this obligation Less capacity in the system means that generation can exhibit market power

45 Reliability Measures Both short term and long term Standard measurement for vertically integrated market, still use in deregulated market Energy not supplied Standard reserve margin System loss of load probability These standards consider system as a whole not an individual node/area. May not suitable for deregulated market

46 Reliability Cost Need index to access reliability cost How much? Who pays? Should unit s performance be considered? Higher credit for reliable unit? (Hirst and Kirby 1999)

47 Tools and Operators Failure Northeast blackout in 2003 results from lack of coordination between control areas Communication tools, system protection tools not function optimally Personal, operators not well trained Lack of adequate tools to visualize system conditions

48 Recent Development in PJM

49 PJM Challenge and Remedy Challenge Market power Inelastic demand Price insensitive demand Resource adequacy No incentive to invest on generation No guidelines Remedy Price cap Demand response program Resource adequacy policy Reliability Pricing Model!! New Development!!

50 Demand Response Program Reduce costs and maintain reliability during peak period and when resource may be scarce Energy market Synchronized reserve market Regulation market Capacity market: Load management in Reliability Pricing Model Demand Resource (DR) Interruptible Load for Reliability (ILR)

51 Program Objectives Emergency purpose Ensure system stability and reliability during emergency period Economic purpose Provide incentive to end-users to reduce consumption at high LMP Reduce electricity price

52 Resource Adequacy Policy Ensure PJM reliability for future years with sufficient resources. Regional Transmission Operator (RTO) determines the amount of resources (region s unforced capacity obligation UCAP) required to serve the forecasted load with reliability criterion (LOLE < 1 day in 10 years).

53 Reliability Pricing Model Motivation Ensure long term capacity adequacy Promote long term price signal for capacity resources that is consistent with the PJM Transmission Expansion Planning process Introduce demand responsive program Demand Resources* (DR) in RPM auction Interruptible Load for Reliability (ILR) Demand resources = Load response resources or load that can be interrupted

54 Reliability Pricing Model New resource adequacy model, effective June 1 st, 2007 Activities performed in advance of delivery year Transition period: 2007/ Obligation to procure unforced capacity determined by ISO Credit the capacity resources Cost allocated to LSEs through the Locational Reliability Charge

55 RPM Participation Mandatory for all Load Serving Entities (LSE) Each LSE pays Locational Reliability Charge Alternative option for LSE is to elect Fixed Resource Requirement (FRR) Mandatory for all resource providers with available unforced capacity within PJM market Voluntary for resource providers with external/planned generation

56 RPM Locational Reliability Charge LRC = Unforced Capacity Obligation X Zonal Capacity Price UCAP obligation calculated from RTO requirement and forecasted peak load. Zonal Capacity price from auction result

57 RPM Implementation Bilateral Market Series of Auction Base Residual Auction 1 st incremental auction 2 nd incremental auction 3 rd incremental auction Interruptible Load for Reliability (ILR) A portion of Unforced Capacity requirement reserved to be fulfilled by ILR

58 RPM Bilateral Market LSEs self-supply capacity obligation Hedge against Locational Reliability Charge from Base Residual and 2 nd incremental auction Capacity providers can cover shortages due to delays, decrease in demand resources, resource cancellation.

59 RPM Auction Base Residual Auction Procurement for unforced capacity obligation for future delivery year Incremental Auctions Accommodate adjustments due to resource cancellations, delays, etc., increase obligation caused by increase in peak load forecast Cost allocated to LSEs through Locational Reliability Charge

60 Demand in RPM Auctions Base Residual Auction Variable Resource Requirement (VRR) curve Relate level of reserve to capacity price Recognize capacity above required reserve Incremental Auction Buy bids from participants in 1 st and 3 rd Buy bids from PJM in 2 nd

61 Supply in RPM Auctions Existing and planned capacity resources Existing and planned demand resources Qualifying transmission upgrades All resources are subject to PJM requirement

62 RPM Auction Process

63 Recent Development in Singapore NEM

64 NEM Challenge and Remedy Challenge Market power One Generation company, one power station Can not be physically divided into small companies Inelastic demand Retail contestability Remedy Vesting Contract Retail competitiveness for small consumers Electric Vending System!! New Development!!

65 Vesting Contract Financial contract proposed by EMA in 04 Long term capacity to account for at least 25% of system demand. X % of the market volume settled on fixed prices. Design to reduce market power by large market players and promote price stability.

66 Electric Vending System Motivation Lack of retail contestability Currently 11,000 contestable consumers (industrial and large consumers) MSSL distribute energy to the remaining 1.3 million uncontestable consumers (residential and small commercial consumers) under regulated tariff.

67 EVS Background No cost effective way for retail customers to choose energy supplier conveniently Labor-intensive and expensive billing system for 1.3 million retail customers Need for new meter technology to facilitate full retail competition and to improve billing system Integrate capability of the existing software, metering and communication system

68 EVS Concept Vending machine concept, pay electricity as you used Replace monopoly purchase infrastructure with a new competitive vending infrastructure Integrated real-time smart metering system Real-time electronic transaction for electricity Customers free to choose electricity plan from any retailers that suit their lifestyle Anytime, Anywhere, Any plan

69 Integration of Existing Technology Meter Data Management System software and Automatic Meter Reading Software to read and process data in real-time Advance electronic metering technology to allow energy usage and keep track of energy consumed in certain time period E-Payment for real-time transaction Wholesale electric market settlement information and tariff by PSO Wireless communication technology

70 Process Flow in EVS Electric Vending System Meter Data Management System e-payment System Retailer s System M M Automatic Meter Reading System Meter Concentrator Energy Market Company System Electricity Network Operator System Meter M

71 EVS Meter One time investment by the government Each has identification number or Meter Access Code Communication among meters and to control center to update usage data Screen display shows real-time electricity price, name of retailer, remaining value and tariff rate

72 EVS Bill Management Cost-effective solution Easy to track electricity used Integrated computer system with updated real time customer information Settle payment through electronic transaction Multiple payment channels with existing e-payment services

73 EVS Benefit to Customer Smart-meter system with real-time energy cost display Provide incentive to reduce consumption during peak period, potentially bring price down Easy to buy electricity via mobile phone, ATM, supermarkets, convenient stores, etc. Easy service activation Cheaper billing system

74 Reference Chi-Keung Woo, Debra Lloyd, and Asher Tishler, Electricity Market Reform Failures: UK, Norway, Alberta and California, Energy Policy, 2003 Kenneth Rose, 2003 Performance Review of Electric Power Markets, Review Conducted for the Virginia State Corporation Commission, August 2003 Sam Zhou et. al., Comparison of Market Designs, Market Oversight Division Report, Public Utility Commission of Texas, January 2003 Eric Hirst and Brendan Kirby, Technical and Market Issues for Operating Reserves, The Electricity Journal, 1999 Pennsylvania-New Jersey-Maryland Independent System Operator webpage Singapore Energy Market Authority webpage