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Building the Energy Markets of Tomorrow . . . Today

The Market Value of The Market Value of Demand ResponseDemand Response

Aaron BreidenbaughAaron BreidenbaughDemand Response Program CoordinatorDemand Response Program CoordinatorNew York Independent System OperatorNew York Independent System Operator

Prepared for:Prepared for:PLMA Fall 2004 ConferencePLMA Fall 2004 Conference

September 30, 2004September 30, 2004


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Reliability Programs Emergency Demand Response Program ICAP Special Case Resources Program

Economic Program Day-Ahead Demand Response Program

NYISO’s Demand Response ProgramsNYISO’s Demand Response Programs


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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

Emergency Demand Response Emergency Demand Response Program (EDRP)Program (EDRP)


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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

ICAP Special Case Resources (SCR) ICAP Special Case Resources (SCR) ProgramProgram


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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

Day-Ahead Demand Response Day-Ahead Demand Response Program (DADRP)Program (DADRP)


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Experience with DRExperience 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)


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Market Impacts of Market Impacts of Reliability ProgramsReliability Programs

(EDRP & SCR)(EDRP & SCR)


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• 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

Emergency Curtailment Valuation (1)Emergency Curtailment Valuation (1)


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• 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 more appropriate ($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



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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%



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Total August event curtailment payments = $7.5 Million

System State

Fully Recovered

Recovering

$1,000/MW

$11.5 Million

$13.6 Million

$2,500/MW

$28.7 Million

$34.1 Million

$5,000/MW

$57.4 Million

$68.1 Million

Outage Cost

• 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

Estimates of Reliability BenefitsEstimates of Reliability Benefits


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Market and Reliability BenefitsMarket and Reliability Benefits

• 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

2001

2002

2003

EDRP

ICAP

8,159

6,632

6,138

6,576

13.0

0.5

NA

NA

20.1

4.8

28.0

26.3

4.2

3.3

4.0

3.3

3.9

0.3

NA

NA

EDRP Curtailed

MWh

Collateral Savings

($M)

Reliability Benefits

($M)

Program Payments

($M)

Reduced Hedge Cost

($M)

4.8

1.5

7.0

11.0

Impact Ratio


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Value When Programs Not CalledValue 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…….


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What is ICAP ?What is ICAP ?New York’s method to insure that energy is

available today, tomorrow and in the future.

Who Buys Capacity?Who Buys Capacity? All Load Serving Entities (LSE’s) in NYCA Marketers/Traders (resellers) ICAP Suppliers with a capacity shortfall

Who Sells Capacity ?Who Sells Capacity ? Generators Special Case Resources Marketers/Traders ICAP Buyers with Excess Capacity


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How do they Sell It?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 AuctionMay purchase or sell for any month(s) remaining in the

Capability Period

Spot Market Auction (SMA)Auction is for the upcoming month onlySMA 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


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ICAP Demand CurveICAP 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


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$13.30

% of Require-

ment

$/kW/Mo

0% 100%(Reference Price)

$0.00

ReferencePrice

MaximumClearingPrice

118%

$10.86

112%

$5.93

2004 Summer Demand Curves

*all $/kW/Month values in terms

of UCAP

$13.30 $20.99NYC

$10.86 $18.28LI

$ 5.93 $11.20NYCA

$20.99

$18.28

$11.20

NYCLI

NYCA


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Value of Additional CapacityValue 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


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Value of Additional CapacityValue of Additional Capacity Rest of State Demand Curve means that:

100 MW of new supply = Price decrease of approximately $0.15/kW-mo

SCR Price Spot Price Spot Price Total Capacity Total $$ Total $$ Paid toSCR Sold Flexibility w/o SCR w/SCR in NYISO Markets w/o SCR w/SCR Savings SCRs

(MW) ($/MW) ($/MW-mo) ($/MW-mo) (MW) ($million) ($million) ($million) ($million)January 905 0.15 1886 1750 11,219 21.16 19.63 1.52 1.58February 907 0.15 1866 1730 11,017 20.56 19.06 1.50 1.57March 905 0.15 1136 1000 10,912 12.39 10.91 1.48 0.91April 889 0.15 933 800 11,796 11.01 9.44 1.57 0.71May 846 0.15 1437 1310 11,119 15.98 14.57 1.41 1.11June 877 0.15 1402 1270 10,813 15.15 13.73 1.42 1.11July 975 0.15 1186 1040 10,606 12.58 11.03 1.55 1.01August 980 0.15 1317 1170 11,031 14.53 12.91 1.62 1.15September 995 0.15 1219 1070 11,153 13.60 11.93 1.66 1.06

13.75 10.223.53Net SCR "Benefit"


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Market Impacts of Market Impacts of Economic ProgramEconomic Program

(DADRP)(DADRP)


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J

F

I

GC

E

K

D

H

B

A

F

G

H

IJ

DADRP Analysis Pricing ZonesDADRP Analysis Pricing Zones

West

Hudson-Capital

NYC

Long Island


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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

West

Hudson/

Capital

New York City

Long Island

9.4

5.1 / 11.8

9.4

5.1

2001

4.2

3.9 / 5.0

3.6

6.5

2002

1.4

1.9

3.5

1.2

2003

Comparison of DAM Price FlexibilitiesComparison of DAM Price Flexibilities

2004

1.8

1.6

0.7

0.6

(preliminary)


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2001

2002

2003

2004

2,694

MWh

1,468

MWh

1,752

MWh

439 MWh

Scheduled

DADRP

$892,14

0

$236,74

5

$45,773

$4,245

Collater

al Savings

$682,358

$202,349

$161,558

$28,577

Reduction in

Hedge Cost

$217,487

$110,216

$121,144

$27,357

Program Payment

s

• Benefits clearly depend upon size of price responsiveness and scheduled curtailments

DADRP Market Price Impacts DADRP Market Price Impacts 2001-20032001-2003

(Preliminary

)


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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

Load DADRP

Strike

Price

LBMP

Est. LBM

P

SD

LD L

b

a

c

Welfare Effects of DADRP (1)Welfare Effects of DADRP (1)


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a

As supply curve becomes flatter, e.g. smaller flexibility, area a can be smaller than area c, and as a result total welfare (a – c) is decreased

Price

Load

DADRP

LBMP and

strike price

Est. LBM

P

SD

LD L

c

Welfare Effects of DADRP (2)Welfare Effects of DADRP (2)


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Est. Welfare Effects of DADRP 2001 - 2004Est. 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

West

Hudson-

Capital

-$752

$43,489

2001 NSW

-$8,628

-$63,643

2003 NSW

-$3,287

-$20,632

2002 NSW

-$4,519

-$12,083

2004 NSW

(preliminary)


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NYISO Response to NSW ResultsNYISO 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


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Questions?Questions?Aaron BreidenbaughAaron Breidenbaugh

[email protected]@nyiso.com

518-356-6023518-356-6023

www.nyiso.comwww.nyiso.com


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Demand Response Demand Response Statistics/InfoStatistics/Info


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EDRP & SCR Growth

0

200

400

600

800

1000

1200

1400

1600

1800

Date

MW

Re

gis

tere

d

0

500

1000

1500

2000

2500

# C

us

tom

ers

MW Registered # Customers # Customers (Disaggregated)

Historic EDRP/SCR ParticipationHistoric EDRP/SCR Participation


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RIP/CSP/DRP Type EDRP/SCR MW

13 Aggregators 412.7 MW

3 Direct Customers 140.9 MW

8 Transmission Owners 698.1 MW

EDRP/SCR Breakdown Effective September 15, 2004

9 LSEs 321.5 MW

DADRP MW

46.5 MW

8.0 MW

334.4 MW

0.0 MW

DR Participation by Provider TypeDR Participation by Provider Type


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Breakdown Effective September 15, 2004

Zone Count Load (MW) Gen (MW) Total MW Count Load (MW) Gen (MW) Total MW Count Load (MW) Gen (MW) Total MWA 43 25.6 14.3 39.9 56 357 0.5 357.5 4 138 0 138B 16 19.91 16.5 36.41 27 45.8 6.5 52.3C 102 15.38 16.9 32.28 44 100.2 3.4 103.6 2 37.4 0 37.4D 15 1.83 3.4 5.23 4 84.7 0 84.7 1 100 0 100E 52 24.8 27.5 52.3 22 30.8 0.8 31.6 1 10 0 10F 54 35.75 9.2 44.95 20 64 0 64 8 89 0 89G 35 23 24.3 47.3 1 1 0 1H 9 1.3079 5 6.3079 3 2.2 0 2.2I 30 7.381 4.86 12.241 6 10.9 0 10.9J 147 95.528 54.382 149.91 72 185.1 3.2 188.3 1 2.5 0 2.5K 608 81.166 69.99 151.156 13 21.3 77.9 99.2 1 12 0 12

1111 331.7 246.3 578.0 268 903.0 92.3 995.3 18 388.9 0.0 388.9Total Emergency 1573.3 Total Economic 388.9

ICAP/SCREDRP DADRP

DR Participation by ZoneDR Participation by Zone


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