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ISO New England . Carol Chessmore Feiran Huang University of Texas at Arlington EE 5379: Fundamentals of Power and Energy Trading Dr. Ricson Chai Fall 2008. Introduction. Market Description Service Area Statistics and History Market Type LMP, FTRs, and ARRs Pricing Seams

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Iso new england l.jpg

ISO New England

Carol Chessmore

Feiran Huang

University of Texas at Arlington

EE 5379: Fundamentals of Power and Energy Trading

Dr. Ricson Chai

Fall 2008

Introduction l.jpg


  • Market Description

    • Service Area

    • Statistics and History

    • Market Type

    • LMP, FTRs, and ARRs

    • Pricing

    • Seams

  • Operations

    • Operations Structure

    • Action During Capacity Deficiency

    • Transmission Outage Plans

    • Emergency Plan

    • Regulatory Agencies

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Service Area

  • 300 market participants

  • 8 pricing zones and a hub

  • Summer peaking system

    • Typical Peak Summer Demand: 19,000 MW to 24,000 MW

    • Typical Peak Winter Demand: 18,000 MW to 20,000 MW

    • Typical Fall and Spring Demand: 15,000 MW to 18,000 MW

    • Record Demand: 28,130 MW

  • 13 interconnections to New York and Canada

  • Part of the Eastern Interconnection

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Generation Types in New England ISO

2007 Generation in the ISO-NE2007 Generation in ERCOT

Source: ISO-NE Source: ERCOT

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Generation by State

Source: ISO-NE

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Size Comparison of ERCOT and ISO-NE

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Brief History of New England Market

  • 1999 - Single energy clearing price market

  • March 2000 - Congestion Management (CMS) and Multi-Settlement Systems (MSS) added

    • CMS: Locational prices of electricity

    • MSS: Day Ahead and Real Time markets

  • March 2001 - Began use of Standard Market Design (SMD)

    • Used a PJM model

    • Worked with New York to standardize rules

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Comparison of Original System with SMD

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Available Trading Markets

  • Bilateral Transactions

    • Between wholesale buyers and sellers

    • Long term contract for set time frame

    • Set prices

    • 75% of transactions

  • Day Ahead Market (DAM)

    • Short term forward market

    • Used to manage risk of increases in real time prices

  • Real Time Market (RTM)

    • Spot market

    • Used for transactions not covered by bilateral transactions or DAM

    • Most risk since prices can change rapidly

  • Forward Capacity Market

    • Started in February 2008

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Forward Capacity Market

  • Economic incentive for investment in new and existing capacity resources

    • Demand Resources

    • Generation Resources

  • Auction

    • Forecasted requirements for 3 years in advance

    • Qualification process to prove they have their proposed capacity

  • Pay-for-Performance

    • Reduces payments to units not available during high demand

  • Peak Energy Rent

    • Reduces capacity costs for everyone when they reach a certain peak level

    • Theory: capacity market compensates for fixed costs while energy market compensates for variable costs

    • Prevents over-collection between the energy market and the capacity market during high demand

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Locational Marginal Price

  • LMP is “cost of congestion”

    • Value of locating new generation

    • Value of upgrading transmission

    • Value of reducing consumption

  • 3 costs

    • Energy (from least expensive unit)

    • Congestion (from more expensive unit)

    • Loss

  • Price calculated at 3 locations

    • Node (900 nodes)

    • Zone (8 zones)

    • Hub (1 hub)

  • Node

    • Not all Physical nodes have Pricing Nodes

    • Some Pricing Nodes are public and some are private

  • Zones

    • Load weighted average of the nodes in the zone

    • Zone LMP is public

  • Hub

    • Located in an area with low congestion

    • Price is average of the zone prices

    • Provides a stable reflection of the overall price

  • Eventually transition to full nodal market

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Uses of LMPs

  • LMPs used to calculate Charges or Credits for market services

    • Energy Market Energy

      • Energy Component

    • Transmission

      • Congestion Component

    • Transmission Losses

      • Loss Component

    • Net Commitment Period Compensation (NCPC)

    • Emergency Energy

    • Forward Reserves

    • Data Reconciliation

    • Inadvertent Energy Accounting

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Pricing using LMP

  • Calculated hourly for the Day Ahead Market

  • Calculated every 5 minutes for the Real Time Market

  • Real-Time Market

    • Participants with Generators are paid with Generator Node LMP

    • Participants with Asset Related Demands are charged based on the Load Node LMP

    • Participants with load other than Asset Related Demands are charged based on Zonal LMP

  • Day Ahead Market

    • Generators paid with Generator Node LMP

    • Participants with Increment Offers are paid with LMP at which the location cleared

    • Participants with Decrement Offers or Demand Bids are paid with LMP at which the location cleared

  • Rule of Thumb

    • If you are being paid, then use Node LMP

    • If you are being charged, then use Zonal LMP

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  • “Congestion Revenue”

    • Zonal LMP (loads charged) > Nodal LMP (generators paid)

    • Congestion revenue = Zonal LMP – Nodal LMP

  • Financial Transmission Rights (FTR)

    • Sold at auction to participants

    • Gives owner the right to receive part of congestion revenue

    • Helps market participants manage their congestion risks

  • Obtained in 3 ways

    • Auction

    • Secondary market

    • Unregistered trades

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  • Auction Revenue Rights (ARR)

    • NE ISO collects revenues from auction of FTRs

  • How are ARRs used?

    • Given out as Qualified Upgrade Awards (QUA) to pay for transmission upgrades that increase transfer capacity

    • Given to entities that pay congestion costs

      • Four stage process

      • Based on load served in the area

      • Allows them to recoup some of the congestion costs and some of the costs from acquiring FTRs

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Demand Response

  • General Features

    • Internet Based Communication System (IBCS)

    • Pre-planned actions to reduce load

    • Pre-determined rate paid per kWh

    • Monthly Capacity Payment based on ICAP or Market Price

  • Real-Time Demand Response Program

    • During emergency

    • 2 categories

      • Within 30 min

      • Within 2 hours

  • Real-Time Profiled Response

    • Without interval metering, but with directly controllable loads

    • Reduce load within 30 minutes

  • Real-Time Price Response Program

    • Reduce load when wholesale price forecast exceeds 10 ¢/kWh

  • Day-Ahead Program

    • Started in 2005

    • Supplement to the Real-Time Program

    • Participants in either Real-Time Program

    • Offer electricity reduction bids based on day-ahead wholesale energy market

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  • Operations Reserve

    • Can recover from the loss of 2 biggest sources with no interruption

    • Reserve margin of about 1,800 MW

    • Reserve Adequacy Analysis

    • Locational Forward Reserve Market

      • Twice a year auction for reserves

      • Online unused capacity or offline fast start generators

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Pricing for Reserves

  • Day Ahead Market

    • Operating reserves charges proportionate to DAM load obligations

  • Real Time Market

    • Charges are levied upon participants whose real time load deviates from the day ahead schedule

    • Charges for those whose generators deviate from day ahead schedules and who do not follow real time dispatch instructions

  • Forward Reserve Clearing Prices

  • Real Time Reserve Clearing Price

    • Set to zero unless need to redispatch

    • If need to redispatch, then equal to RCPF

  • Real Time Reserve Penalty Constraints

    • If reserve cannot be met

      • Local TMOR RCPF = $50/MWh

      • System TMOR RCPF = $100/MWh

      • System TMNSR RCPF = $850/MWh

      • System TMSR RCPF = $50/MWh

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  • Seams - Barriers that inhibit the economic trade of capacity and energy between neighboring wholesale electricity markets

    • ISO New England

    • New York ISO

    • PJM

    • Ontario

    • Hydro-Quebec

    • New Brunswick Power

  • Result of differences in

    • Market rules

    • Operating and scheduling protocols

  • In July 2002, FERC issued a Notice of Proposed Rulemaking for Standardized Market Design

  • In 2002, Northeastern Independent Market Operators Coordinating Committee was formed

    • Coordination of market design and system planning protocols

    • Sharing of regulation services

    • Sharing of reserves during short-term interruptions

    • Ensure that energy exporting procedures are similar so that trading across borders is easier

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Operations Structure

  • Departments

    • System Operations

    • Market Operations

    • System Planning

  • Committees

    • Participants Committee & Working Groups

    • Markets Committee & Working Groups

    • Reliability Committee & Working Groups

    • Transmission Committee & Working Groups

    • Other Committees

    • Inactive Committees

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Procedures and Manual

  • Operating Procedures (OP)

    • The procedures inform generators of operating and reliability requirements.

    • Total 21 OP

  • Summary of the Procedures and Manuals

    • Transmission

      • OP2, 6, 7, 11, 12, 13, 16, 17, 19

    • Market

      • OP3, 4, 5, 8, 9, 14, 18, 21, M-06,-11,-35,-36

    • Installed Capacity

      • M-20

    • Accounting and Billing

      • M-27, -28, -29

    • ISO Administrative

      • OP1, 10

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Action During a Capacity Deficiency

  • Operating Procedure 4

  • 16 point plan

    • Action 1: Power caution

    • Action 2: All contracted 5MW generators come online

    • Action 3-5: Interrupt Real Time Demand with 2 hour or less notification

    • Action 6: Allow depletion of 30 minute reserve

    • Action 7-8: Continue to interrupt Real Time Demand

    • Action 9: Power Watch

    • Action 10: Request all generation contractually available

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Action During a Capacity Deficiency

  • Action11: Purchase energy from neighboring markets

  • Action 12:

    • Allow 5% less of normal operating voltage

    • Interrupt demand with 30 minutes or less

    • Inform NY ISO that sharing may be necessary

  • Action 13: Voltage reduction of 5% in 10 minutes

  • Action 14: Request all generation not contractually secured

  • Action 15:

    • Radio and Television Address for voluntary load curtailment

    • Power Warning

  • Action 16: New England State Governors to reinforce appeals for voluntary load curtailment

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Power Capacity Information

  • Normal

  • Power Caution

    • Issued to market participants

    • Prepare to implement OP 4

    • No need for public action

  • Power Watch

    • Public action: Reduce AC, shutting off lights, and doing laundry at night instead of peak hours

  • Power Warning

    • Public action: Shut off unnecessary lights, equipment, and appliances

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Transmission Outages

  • Operating Procedure 3

  • Outages:

    • Scheduled Outages

    • Long-Term Planned Transmission Outages

    • Short-Term Transmission Outages

    • Unplanned Outage

      • Emergency Outage

      • Forced Outage

      • Overrun Outage

      • Opportunity Outage

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Transmission Outages

  • Operating Procedure 3

  • Categories of Transmission Facilities

    • Category “A”– Highest voltages >= 115kV except 115kV radial circuits and most critical facilities

    • Category “B”– All 115kV radial circuits and all 69kV circuit

    • Local Area – Below 69kV

      NOTE: Lists of Category A and B facilities are posted for the public

      The outage treatment will be different from category to category

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Operating Reserve

  • Operating Procedure 8

    • An additional resource to meet the actual New England control area load

  • Control Area (CA)

    • An electrical power system to which a common Automatic Generation Control (AGC) is applied in order to

    • Match generation and load

    • Maintain interchange with other CA

    • Maintain frequency

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Operating Reserve

  • Ten-Minute Reserve

    • Ten-Minute Non-Spinning Reserve (TMNSR)

    • Ten-Minute Spinning Reserve (TMSR)

  • Thirty-Minute Operating Reserve (TMOR)

    • The same as Ten-Minute Non-Spinning Reserve

    • In 30 minutes

  • Replacement Reserve

    • Reserve other than TMSR, TMNSR, or TMOR

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Operating Reserve

  • First Contingency Loss

    • The largest capacity outage (MW) that would result from the loss of a single element

  • Second Contingency Loss

    • The largest capacity outage (MW) that would result from a single element after allowing for the First Contingency Loss

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Operating Reserve

  • Procedure

    • Real time Operating Reserve Requirement

      • Ten-Minute Reserve >= require to replace the First Contingency Loss

      • Thirty Minute Operating Reserve >= 50% of the Second Contingency Loss

      • Any excess of Ten Minute Reserve can be counted as Thirty Minute Reserve

      • Operating Reserve shall be sustainable for at least one hour from the time of activation

      • The output of the largest generating unit cannot be considered as Operating Reserve

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Emergency Plan

  • Operating Procedure No 7

  • Procedure For Low Frequency Condition

    • If the cause is outside of New England CA

      • Increase the synchronized reserve, if needed

      • Make known to external area the available amount capacity

    • When the cause is due to a deficiency in NE CA

      • Request assistance from external area up to the emergency transfer limit of the interconnecting lines

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Emergency Plan

  • Procedure For Low Frequency Condition

    • When frequency reaches 59.90Hz

      • Disconnect any pumped storage resource operating in the pumping mode

      • Order fast-start non-synchronized resource into service

    • When frequency reaches 59.80 Hz

      • Automatic Generation Control will be tripped automatically

      • Direct all resources to maximum limits as maximum response rates, as appropriate

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Emergency Plan

  • When frequency reaches 59.30 Hz

    • Underfrequency relays will provide 10% load relief by the time the frequency reaches 59.00 Hz

  • When frequency reaches 58.80 Hz

    • Underfrequency relays will provide an additional 15% load relief by the time the frequency reaches 58.50 Hz

  • If it continues to decline below 58.50 Hz

    • Order manual load shedding (50% of the NE CA’s load can be shed manually)

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Regulation Market

  • FERC

    • Federal Guidelines

    • Prevents anti-competitive behavior

  • ISO New England's Market Monitoring and Mitigation Unit

    • Interacts with FERC's Office of Market Oversight and Investigation

    • Tries to suggest ways that SMD can be improved to prevent problems

  • Multiple PUCs: One PUC for each state

  • Multiple Energy Councils: One for each state

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Regulatory Agencies

  • New England Power Pool (NEPOOL)

    • Alliance of utility companies

    • Must have capacity

    • Looks at costs, benefits, and accountability

      • Dispatch: Meet demand with lowest fuel cost

      • Settlement: Accountability for dispatch

      • Forwards: Market to optimize generating resources by trading

  • Independent Market Monitoring

    • Evaluates SMD

    • Monitors markets for gaming

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  • Market Description

    • Standard Market Design

    • 8 zones and a hub

    • Locational Marginal Price (LMP)

    • Financial Transmission Rights (FTRs)

    • Auction Revenue Rights (ARRs)

    • 3 Markets

      • Real Time

      • Day Ahead

      • Forward Capacity

    • Pricing

    • Seams

  • Operations

    • Committees

    • Plan for Capacity Deficiency

    • Plan for Transmission Outages

    • Emergency Plan

    • Reserves

    • Regulation Market

    • Regulatory Agencies

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Thank you for your attention!

Any questions on


For more information on iso ne l.jpg

For More Information on ISO-NE

  • For more information on the ISO-NE, visit


      • News and Issues: Inside Grid & Markets Section

    • Market Operations Manual M-11 (Word doc) for discussion of uses of LMPs and pricing with LMPs

  • To see statistics about the ERCOT system, visit


      • About ERCOT: Media Kit: ERCOT Organization Backgrounder Section

      • ERCOT Quick Facts May 2008 (PDF document)

  • For more information on NEPOOL, visit


  • All pictures, ISO-NE statistics, and the ISO-NE logo were taken from the ISO-NE website

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