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The Market Value of Demand Response

The Market Value of Demand Response. Aaron Breidenbaugh Demand Response Program Coordinator New York Independent System Operator Prepared for: PLMA Fall 2004 Conference September 30, 2004. NYISO’s Demand Response Programs. Reliability Programs Emergency Demand Response Program

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The Market Value of Demand Response

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  1. The Market Value of Demand Response Aaron Breidenbaugh Demand Response Program Coordinator New York Independent System Operator Prepared for: PLMA Fall 2004 Conference September 30, 2004

  2. NYISO’s Demand Response Programs • Reliability Programs • Emergency Demand Response Program • ICAP Special Case Resources Program • Economic Program • Day-Ahead Demand Response Program

  3. Emergency Demand Response Program (EDRP) • Emergency/Reliability Program • Response is Purely Voluntary • Minimum Resource Size: 100 kW, may aggregate within Zones • Activated in Response to Operating Reserve Deficiency • Payment Only for Actual Energy (kWh) Reduction Provided • Provider notified of activation 2 hours ahead, if possible • Paid the greater of real-time marginal price or $500/MWh & guaranteed 4 hour minimum • May set real-time market price at $500 • Available to interruptible load & emergency backup generation (including generation in excess of host load) • Activated after ICAP SCR resources if deemed necessary by Operators

  4. ICAP Special Case Resources (SCR) Program • Emergency/Reliability Program • Response is Mandatory • Minimum Resource Size: 100 kW, may aggregate within Zones • Activated in Response to Operating Reserve Deficiency • Payment for Capacity (kW) Commitment plus Payment for Actual Energy (kWh) Reduction Provided • Provider advised 21 hours ahead with 2 hour in-day notification during Operating Reserve deficiency • Paid for energy reduction: real-time market price or Strike Price (maximum $500/MWh), whichever is greater & guaranteed 4 hour minimum • May set real time market price under scarcity pricing rules • Available to interruptible load & emergency backup generation (including generation in excess of host load) • Activated prior to Emergency Demand Response resources

  5. Day-Ahead Demand Response Program (DADRP) • Economic Program • Response is Expected, Energy Not Reduced is Bought Back at Higher of Day-Ahead or Real-Time Price • Minimum Resource Size: 1 MW, may aggregate within Zones • Load bids interruption in Day-Ahead Market just like a generator - if chosen, can set marginal price. $75/MWh minimum bid. • Payment for Actual Energy (kWh) Reduction Provided • Parties submitting accepted bids get: • Notified by 11:00 a.m. of schedule for the next day (starting at midnight) • incentive credit (fixed load bid reduced by amount of curtailment provided) • Available to interruptible load only (generation excluded) • Activated prior to Emergency Demand Response resources • Mandatory Response – Penalties Assessed for Non-Compliance • penalized for buy-through at Day-Ahead or Real-Time marginal price, whichever is greater

  6. Experience with DR • Emergency Programs 2001-2003 • Activated ~22 hours each summer • ~700 MW load reduction provided • ~$3-$7 million in energy payments • Neither program activated in 2004 (so far) • Economic Programs • > 350 MW registered • < 30 MW bids accepted at any given time • ~5 MW of curtailment typical • $50/MWh bid floor price in effect, slated to increase to $75 November 1, 2004 (change is pending at FERC)

  7. Market Impacts of Reliability Programs(EDRP & SCR)

  8. Emergency Curtailment Valuation (1) • The standard practice • Establish a range of representative Value Of Lost Load (VOLL) values • rolling blackouts tend to temper costs of those effected • lower range of values ($1 – $2.5/kWh may be most reasonable) • Establish LOLP improvement associated with DR curtailments • Generally confined to short periods • Estimate load at risk • Usually relatively confined - 2-5% • Result Value = LOLP improvement * load at risk * VOLL

  9. Emergency Curtailment Valuation (2) • System rebuild situation Customer without power • VOLL reflects extension of an already long period without power at their premise, and at any local or convenient premise • Higher VOLL is moreappropriate ($3-5/kWh • For customers without power LOLP = 1 • Load at risk is their entire load • System rebuild situation Customer with power • An outage after restoration would be more costly than a typical rolling, short duration blackout • LOLP change might be greater than under typical curtailments due to lack of system stability • Load at risk may be localized, but higher than normal, and subject to a full curtailment

  10. Emergency Curtailment Valuation (3) • System Rebuild State • In the case when the system was not entirely recovered, and unsaved load exceeds the DR curtailed • Change in LOLP = 1 • High (~4-5/kWh) VOLL applies • Load at risk = Amount of DR curtailments • Recovered System state • When the system had been fully re-energized, DR contribute to reestablishing and maintaining design reserve margin • Utilize the same methods that were employed in previous years • Change in LOLP < 1 but higher than “normal” • Lower ($1-2.5/kWh) VOLL applies • Load at Risk = ~2-5%

  11. $1,000/MW $2,500/MW $5,000/MW $11.5 Million $13.6 Million $28.7 Million $34.1 Million $57.4 Million $68.1 Million Estimates of Reliability Benefits Outage Cost Total August event curtailment payments = $7.5 Million System State Fully Recovered Recovering • Gross Benefits of August DR Curtailments • Fully Recovered value places a lower bound on the value of DR curtailments • Recovering places an upper bound on the that value • Benefits Net of Payments • Fully recovered and low VOLL yields B/C = 1.5 • Recovering and high VOLL yields B/C = 9.0

  12. Market and Reliability Benefits EDRP Curtailed MWh Reduced Hedge Cost ($M) Reliability Benefits ($M) Program Payments ($M) Impact Ratio Collateral Savings ($M) 2001 2002 2003 EDRP ICAP 8,159 6,632 6,138 6,576 13.0 0.5 NA NA 3.9 0.3 NA NA 20.1 4.8 28.0 26.3 4.2 3.3 4.0 3.3 4.8 1.5 7.0 11.0 • Prior to 2003, EDRP benefits did not distinguish between EDRP and ICAP/SCR program registration • EDRP participants received $500/MWH: ICAP/SCR participants received higher of their bid, or LBMP

  13. Value When Programs Not Called • EDRP • No payments unless activated so $0 paid out • Does Not mean value is zero • Insurance value regardless of whether program is called • NYISO is considering valuation approaches • SCR • Same is true from an energy standpoint • SCR resources paid for capacity whether called or not • Additional capacity in the market makes the market more competitive • Need to understand NYISO’s capacity markets…….

  14. What is ICAP ? • New York’s method to insure that energy is available today, tomorrow and in the future. Who Buys Capacity? • All Load Serving Entities (LSE’s) in NYCA • Marketers/Traders (resellers) • ICAP Suppliers with a capacity shortfall Who Sells Capacity ? • Generators • Special Case Resources • Marketers/Traders • ICAP Buyers with Excess Capacity

  15. How do they Sell It? • Bilaterally (No NYISO Involvement) • Three NYISO Auctions • Capability Period Auction (“Strip Auction”) • A six month price for an equal amount of monthly MWs • Monthly Auction • May purchase or sell for any month(s) remaining in the Capability Period • Spot Market Auction (SMA) • Auction is for the upcoming month only • SMA held to secure capacity for deficient LSEs (failure to procure) and Suppliers (inability to supply) • NYISO submits bids on behalf of all LSEs at a level determined by applicable ICAP Demand Curve

  16. ICAP Demand Curve • Demand Curve is defined by two points: • Reference Price: Set price point for 100% of requirement • Percentage of requirement for price to be $0.00 • NYCA Demand Curve: 112% • LI & NYC Locational Demand Curves: 118% • Max. Demand Curve Clearing Price set at one and one-half times the localized levelized embedded cost of a gas turbine (not a trivial task to determine) • Benefits • Increases system & resource reliability • Values additional capacity above NYCA & Locational Requirements • Reduces price volatility

  17. $20.99 $18.28 NYCA $ 5.93 $11.20 LI $10.86 $18.28 NYC $13.30 $20.99 $13.30 $11.20 $10.86 $5.93 2004 Summer Demand Curves LI NYC $/kW/Mo Maximum Clearing Price Reference Price NYCA *all $/kW/Month values in terms of UCAP % of Require-ment $0.00 112% 118% 0% 100% (Reference Price)

  18. Value of Additional Capacity • ICAP prices in NYC and Long Island are set by price caps on divested generating units. Markets nearly always clear at cap values. • NYCA (a.k.a. “Rest of State”) markets are competitive and liquid • More supply -> lower market clearing prices • Spot market prices are effectively determined by demand curve, which in turn reflect amount of supply • Economists say “Monthly and strip prices should converge with spot market prices” • ergo; All NYISO markets are influenced by SMA Prices

  19. Value of Additional Capacity • Rest of State Demand Curve means that: • 100 MW of new supply = Price decrease of approximately $0.15/kW-mo

  20. Market Impacts of Economic Program(DADRP)

  21. D F E F B A C G G H H I I J J K DADRP Analysis Pricing Zones Hudson-Capital West Long Island NYC

  22. 2001 2002 2003 9.4 5.1 / 11.8 9.4 5.1 4.2 3.9 / 5.0 3.6 6.5 1.4 1.9 3.5 1.2 West Hudson/Capital New York City Long Island Comparison of DAM Price Flexibilities • Price flexibility = % change in price due to a 1% change in the load served • Low flexibilities in 2003, 2004 due to lack of price volatility and no extreme price spikes • No “hockey-stick” shaped supply curve observed in 2003, 2004 2004 1.8 1.6 0.7 0.6 (preliminary)

  23. Collateral Savings Scheduled DADRP Reduction in Hedge Cost Program Payments $892,140 $236,745 $45,773 $4,245 $682,358 $202,349 $161,558 $28,577 $217,487 $110,216 $121,144 $27,357 2,694 MWh 1,468 MWh 1,752 MWh 439 MWh DADRP Market Price Impacts 2001-2003 2001 2002 2003 2004 (Preliminary) • Benefits clearly depend upon size of price responsiveness and scheduled curtailments

  24. DADRP Welfare Effects of DADRP (1) For load above LD supply price above value to customer  DWL: a + b Payment: b + c  NSW: a – c = DWL – Payment = (a+b) – (b+c) Positive  NSW when a>c Price S D Est. LBMP a LBMP b Strike Price c LD L Load

  25. DADRP Welfare Effects of DADRP (2) Price As supply curve becomes flatter, e.g. smaller flexibility, areaacan be smaller than areac, and as a result total welfare (a–c) is decreased S D Est. LBMP a LBMP and strike price c Load LD L

  26. Est. Welfare Effects of DADRP 2001 - 2004 • Net Welfare increase in 2001 largely due to bids being scheduled during hours with higher price flexibilities in both regions • Negative NSW change due to large number of bids scheduled in low-priced hours • Smaller negative NSW change in 2004 due to very small number of bids scheduled 2003  NSW 2001  NSW 2002  NSW 2004  NSW West Hudson-Capital -$752 $43,489 -$3,287 -$20,632 -$8,628 -$63,643 -$4,519 -$12,083 (preliminary)

  27. NYISO Response to NSW Results • Increase Bid Floor from $50/MWh to $75/MWh • Try to Make DADRP look more like emergency programs • Explore implementation of “standing bids” • Explore automated notification system when bids accepted • Increased floor should mitigate most NSW losses while other changes help retain bids and response during relatively rare high priced hours

  28. Questions? Aaron Breidenbaugh abreidenbaugh@nyiso.com 518-356-6023 www.nyiso.com

  29. Demand Response Statistics/Info

  30. Historic EDRP/SCR Participation

  31. DR Participation by Provider Type EDRP/SCR Breakdown Effective September 15, 2004 RIP/CSP/DRP Type DADRP MW EDRP/SCR MW 0.0 MW 13 Aggregators 412.7 MW 9 LSEs 321.5 MW 46.5 MW 3 Direct Customers 140.9 MW 8.0 MW 8 Transmission Owners 698.1 MW 334.4 MW

  32. DR Participation by Zone Breakdown Effective September 15, 2004

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