The Market Value of Demand Response

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
NYISOs 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 1100 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
• gt 350 MW registered
• lt 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 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

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 lt 1 but higher than normal
• Lower (1-2.5/kWh) VOLL applies
• Load at Risk 2-5

11
Estimates of Reliability Benefits
Outage Cost
System State
Fully Recovered Recovering

• Total August event curtailment payments 7.5
  Million

• 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
Reliability Benefits (M)
Program Payments (M)
Reduced Hedge Cost (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
20.1 4.8 28.0 26.3
4.2 3.3 4.0 3.3
3.9 0.3 NA NA
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 NYISOs capacity markets.

14
What is ICAP ?

• New Yorks method to insure that energy is
  available today, tomorrow and in the future.

Who Buys Capacity?

• All Load Serving Entities (LSEs) 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
2004 Summer Demand Curves
NYC
LI
/kW/Mo
Maximum Clearing Price
Reference Price
NYCA
all /kW/Month values in terms of UCAP
of Require-ment
0.00
118
112
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 -gt 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
DADRP Analysis Pricing Zones
Hudson-Capital
West
Long Island
NYC
22
Comparison of DAM Price Flexibilities
2004
1.8 1.6 0.7 0.6
(preliminary)

• 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

23
DADRP Market Price Impacts 2001-2003
2001 2002 2003 2004
(Preliminary)

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

24
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 (ab) (bc)
• Positive ? NSW when agtc

Price
S
D
Est. LBMP
a
LBMP
b
Strike Price
c
LD
L
Load
25
Welfare Effects of DADRP (2)
Price
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
S
D
Est. LBMP
a
LBMP and strike price
c
Load
LD
L
26
Est. Welfare Effects of DADRP 2001 - 2004
2003 ? NSW
2001 ? NSW
2002 ? NSW
2004 ? NSW
West Hudson-Capital
-752 43,489
-8,628 -63,643
-3,287 -20,632
-4,519 -12,083
(preliminary)

• 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

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

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Questions? Aaron Breidenbaugh abreidenbaugh_at_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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