robert j. king goodcompany associates january 30, 2007 exploring aggregated demand response...
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Robert J. King
GoodCompany Associates
January 30, 2007
Exploring Aggregated
Demand Response Solutions
In ERCOT Markets
2
ERCOT AUGUST 17 PEAK DAYOPERATIONS DATA
57,376 MW
63,259 MW
64,731 MW
3
ERCOT AUGUST 17 PEAK DAYOperations and Planning Analysis
From Ken Donoho, 9/17/06
Operations
EMS Data
Load EMS Peak Value 63,259
Dispatchable Generation 57,376 593 MW Forced Out
Private Network Value 6,397
Wind Value 342
DC Tie Capability 855
Reserve Capacity 1,711 2.7 % of Load
LAAR 1,150
Total Reserve 2,8614.5% of Load,
Minimum 2,300 MW
4
Clarifying Definitions
Ele
ctric
Lo
ad
(kW
)E
lect
ric L
oa
d (
kW)
Time of Day0h 8h 16h 24h
Ele
ctric
Lo
ad
(kW
)1. ENERGY EFFICIENCY– Reduce total kWh of loadshape with
permanent efficient technologies.
– E.g.: CFLs, PE Motors, T8’s, etc..
2. DEMAND RESPONSE– Temporary reduction of peak energy
usage for a defined duration.
– Curtailment “events” triggered by either reliability or high prices.
– E.g.: Load-control switch, Thermostats
3. LOAD SHIFTING– “Flattening” the loadshape by using off-
peak power in place of on-peak power.
– Often permanent shift driven by combining appropriate technology and rates (TOU).
– E.g: Thermal Energy Storage
5
Actual Residential Test
Average Daily Load Profiles for all Homes in Program (July – September)
Ele
ctr
ic L
oa
d p
er
Ho
me
(k
Wh
/hr)
0.0
1.0
2.0
3.0
0:00 4:00 8:00 12:00 16:00 20:00 23:59Time of Day
Super Peak
Baseline
Group A Homes
Group B Homes
6
Commercial Example
0
10
20
30
40
50
60
12:00 PM 1:00 PM 2:00 PM 3:00 PM 4:00 PM 5:00 PM 6:00 PM 7:00 PM 8:00 PM
kW
2-Oct-03 25-Sep-03 26-Sep-03 29-Sep-03 30-Sep-03 1-Oct-03
Managing Retail HVAC/Lighting Loads
7
Hydro
Gas
Coal
OilEn
viro
nmen
tal I
mp
act
+
-
Capacity Resource – “Environmental Stack”
Geo-thermal
DemandResponse
Wind
Demand Response is the only capacity resource with a
positive environmental impact and yet “looks like” a gas peaking plant to a utility.
Clean Energy
Sector Bio-mass
Nuclear
Negative
Positive
Solar FuelCells
8
Characteristics Of Demand Response
Load Granularity: Large industrial loads may only be available in MW chunks while small loads can be aggregated and finely tuned.
Response Time: The time between sending the signal and actually curtailing the load can vary from sub-seconds to day-ahead.
Control Symmetry: The ability to control loads both "up" and "down". Some industrial loads can be shed in a few minutes, but take hours to return to the grid. Other DR technologies can respond in seconds.
Monitoring: Load changes must be measured and verified, and feedback may be required for the load provider to ensure performance. Settlements can be based on measured or stipulated performance.
Duration and Frequency: How often can the load be curtailed? For how long? How much warning is required?
DR “types” can vary according to many factors, technology, monitoring method, end-use customers, costs and benefits. The key differences
include the following operational qualities:
9
CPP
Conceptual Map of DR Types
Basic Components Grid Components (Meters, RTUs, SCADA, LCD, Xfrms, etc…)
Advanced Components
Bas
ic N
etw
ork
Adv
ance
d N
etw
ork
Co
mm
un
icat
ion
Net
wo
rk
• Near-real-time• 2-way data• Detailed Control
DR Infrastructure can overlap with AMI Infrastructure
LaaRs
Tiered Frequency Response
Direct Cut-off DR
Intelligent DR
Load Co-op
TOULoad
ControlRelays
ThermostatSetback
w/ metering
ThermostatSetback
10
In Home Display ($180 plus $100 installation) Basic Load Control Switch, Single Load ($75 + $100 for installation)
– 1 way communication with no verification– Can control various loads (pool pumps, water heater, A/C, etc…)
Enhanced Load Control Switch ($250 plus $100 installation)– 2 way communication, allows verification– Load shed determined by historical use– Allows emergency low frequency event participation
Remote Controlled Thermostat ($200 plus $100 installation)– 1 way communication, no verification– Web/internet programmable, variable load shed– Controlled equipment: A/C
Home Automation/Energy Management System (>$2500)– 2 way communication available, allows verification– Variable load shed– Controlled equipment: A/C, pool pumps, water heater, appliances, lights
Sample DR Technologies (Residential)
11
Sample DR Technologies (C&I)
Basic Load Control Switch, Single Load ($75 + $100 install) Remote Controlled Thermostat ($200 plus $100 installation) Energy Management System Interface ($100 + $100-500 install)
– 1 way communication with no verification
– Must enable a pre-programmed demand response mode
Dimmable Lighting Ballasts ($15-$40/ballast)– Lights can dim 40% over 15 minutes without complaints
– Addressable by circuit or ballast
– Great application for combining EE and DR
Energy Management Systems ($500-$20,000 + >$1000 install)– 2 way communication with verification
– EMS must be able programmed to operate in “load shed” mode
Specialty Control Device Products (costs vary)– Industrial Gas OEM’s can fill tanks on flexible notice
– Various products for remote dispatch of DG assets
12
13
Providers of DR TechnologiesThese firms offer a wide range of DR technology & services
o Ice Energyo Infotilityo Invensyso Johnson Controlso muNet.com o PowerGrid Communicationso Powerweb Technologieso RETXo Siemens Building Technologieso Silver Spring Networkso Site-Controlso SmartSynch o TAC/Tour Andover Controlso Trilliant Networks
o Automated Energy, Inc.o Automated Power Exchangeo Cannon Technologieso Comverge Technologieso Connected Energy Corp.o ConsumerPower Lineo Corporate Systemso Current Technologieso Energy Controls & Conceptso EnerNOCo Enerwiseo Engage Networks, Inc.o GoodCents Sollutionso Honeywell Utility Services o Hunt Power/Apogee Interactive
Note: We have had discussions with the 22 firms in bold and meetings with the 6 firms followed by (*).
14
Who’s Doing DR Today? (1 of 3)
ISO Program Incentives
ISO-NE
(~1.5 GW)
• Reliability program called by ISO (250 MW)
• Demand bidding program managed by IOUS (1,230 MW)
• $350-$500/MWh (or LMP) + ICAP $44/kW + $2,800 per facility
•Greater of $100/MWh or LMP
NYISO
(~2.0 GW)
• Emergency Demand Response Program (587 MW)
• Installed Capacity-Special Case Resources (1,083 MW)
• Day-Ahead DR Program allows load to bid like generation resource (386 MW)
•Greater of $500/MWh or LMP
• ICAP market + up to $500/MWh (if dispatched by ISO to curtail)
• $75/MW bid floor
PJM
(~3.8 GW)
• Voluntary Emergency Program (1,619 MW)
• Emergency Capacity & Energy Program
• Economic Load Response Program allows loads to bid into Real-Time and Day-Ahead markets (2,210 MW)
•Greater of $500/MWh or LMP
• Energy + ICAP (if qualified)
• Pays LMP >$75/MWh
Demand Response is used as an important tool of most ISOs
15
Who’s Doing DR Today? (2 of 3)
ISO/ Utility
Program Incentives
MISO • Demand Response Resource Offers allows loads to bid into Day-Ahead schedule.
•MISO will dispatch based on DR bid stack ($1,000 MWh cap is waived)
CALISO •Over 40 different DR programs offered by State, ISO, Municipalities, and IOUs
• In process of moving all customers >200kW (30% load) to CPP rates
• CPUC goal of meeting 5% of peak demand with price-based DR.
• Various
Demand Response is used as an important tool of most ISOs
16
Who’s Doing DR Today? (3 of 3)
ISO/ Utility
Program Incentives
Austin Energy
•Over 30,000 programmable, DR thermostats dispatched by utility
• Free installed thermostat
Florida Power and Light
• 728,000 participate in the company’s load control program, 1,000 MW in normal operation, 2,000 MW in an emergency
Incentive Payments per Year
– AC Cycle: $42 old / $21 new
– Strip Heat Cycle: $10
– Strip Heat Extended: $20
– Water Heat: $42 old / $18 new
– Pool Pump: $36
– Total per customer:
Typical - $80 old / $45 new
Georgia Power
• outside direct control unit (DCU) to cycle AC 32,500, 45-50 MW load reduction
• $20 incentive, $2 per activation
Demand Response is also used as an important tool by many IOUs
17
FERC Demand Response SurveyData from comprehensive report released to Congress in August 2006
Customers Enrolled in Direct Load Control (DLC) Programs
Number of Entities Offering Capacity, Demand Bidding, and Emergency Programs
Although the Technology exists, ERCOT exhibits limited participation in DR programs compared with other NARC Regions……
18
Conclusions from Existing Research
Studies find substantial system value for Demand Response.
Benefits are difficult to capture, quantify, and monetize.
Lack of standard definitions of benefits and “DR Types”.
Large uncertainties in quantifying benefits.
– Reliability is complex to model, VOLL, option value, risk and efficient frontier analysis
– Arbitrage value exists at low-frequency extremes (e.g. most expensive 20-200 hours, which vary by year)
– Many non-quantifiable benefits (e.g. operational flexibility, customer choice, anti-collusion, etc…)
“Value” depends on perspective and most analysis looks at “system benefits” or net social benefits.
19
ERCOT: Identifying / Quantifying Value
Regulatory and Social Benefits
Increased Reliability
Enhanced Customer Choices
More Efficient Use of Resources
Developing Demand Response Capacity in Texas delivers value to different parties. Benefits fall into one of three categories.
Benefits Realized Internally by TDUs
Benefits Realized by Other Market
Participants
Operational Efficiencies
Deferred Capital Costs of T&D
Regulatory Goodwill
REPs –Commodity value, lower LMPs, facilitates expanded service and rate offerings.
QSE – reduction of imbalance events
ERCOT – additional sources of reserves and ancillary services
Customers – premium services
20
$19.63$27.48
$43.18
$78.50
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
Load Management C&I Res HTR
"Av
oid
ed
Co
sts
" R
ec
ov
era
ble
by
Se
gm
en
t ($
/kW
/ye
ar)
• EE Program incentives today only monetized value for this category.
• Allowable payment per kW increases (from left to right on chart) but costs per controllable kW increase as well.
• Important to consider the potential benefits of Energy Efficiency to provide congestion relief.
• Benefit today:RANGE: $19.63 - $78.50 $/kW/yr
Residential $40Load Mgmt.
General(25% AC)
Load Mgmt. (C&I)
(35% AC)
Load Mgmt. (Residential)
(55% AC)
Load Mgmt. (HTR)
(100% AC)
“Avoided Cost” defined as $78.50/kW/year
Regulatory and Social Benefits
Regulatory and Social Benefits
In Congested Areas
Quantifying Value in ERCOT
EE Program Incentives
21
$19.63$27.48
$43.18
$78.50
$-
$20
$40
$60
$80
$100
$120
Load Management C&I Res HTR Technology Costs
"Av
oid
ed
Co
sts
" R
ec
ov
era
ble
by
Se
gm
en
t ($
/kW
/ye
ar)
EE Benefits Alone do not Cover Costs
Load Mgmt. General
(25% AC)
Load Mgmt. (C&I)
(35% AC)
Load Mgmt. (Residential)
(55% AC)
Load Mgmt. (HTR)
(100% AC)
“Avoided Cost” (AC) defined as $78.50/kW/year
In Congested Areas
Tech
nolo
gy C
osts
R
an
ge
$6
0-$
11
0
/kW
/year
Technology Costs
Technologies are mature and proven.
Costs vary widely and are very site-specific.
EE Budget (§25.181) will cover full DR costs in only a few rare situations.
Must identify additional sources of value to fill this gap…
22
TDU Benefits
Operational Efficiencies
– Reduction in local outages
– Increased operational flexibility
– More options in system planning
Deferred Capital Costs of T&D
– Transmission capital deferral limited to TDU share of postage stamp rates
– Distribution capital cost deferral value accrues to TDU directly
– Realizing this value depends on rate structure, regulatory lag
– Potential revenue loss from reducing peak demand by large customers on rates that have large demand component
Regulatory Goodwill
23
Quantifying Values: Previous Studies
Pacific Northwest National Lab (June 2006)
GridWise demonstration combining DR and DG
System Benefit Analysis of capital deferral
– Gen: $15 – 36
– LMP: $10 – 15
– Dist: $13 – 90
– Trans: $8 – 40
TOTAL:
$46 – 181 /kW/yr
MADRI States DR Benefits (November 2005)
System wide study for state PUCs for incenting distributed resources
System Benefit Analysis of capital deferral
– Capacity benefit:$40
– LMP:$34
– Dist:$35
– Other (Emis, Reliabil.):$100
TOTAL $209 /kW/yr
DRR Valuation and Market Analysis, IEA (2006).
Monte Carlo Simulations of Strategist asset-based system model
Defined 3 “types” of demand response:
– Interruptible
– CPP
– Callable w/ RTP
Total System Cost Savings from each type was $48, $574, $1,984 million (20-year NPV)
24
Quantifying Benefits to T&D Utilitites
Transmission and Distribution benefits vary widely over a TDU’s territory (we calculate $490/KW NPV from CNP Rate Case)
Marginal Costs are much higher than average costs, so higher in utilities with growth
Additional Studies by CEC and EPRI regarding energy storage attempt to quantify avoided T&D Costs for demand reduction
Range for costs avoided ranges from $35/kW to over $1900
Distribution upgrades suggest an internal value for capital deferrals. Other studies found 10% of the substation upgrade capital to be >$1000/kW.
RANGE: $35 - $1900 $/kW/yrConservative Value: $40 $/kW/yr
Benefits Realized Internally by TDUBenefits Realized Internally by TDU
25
Benefits realized by others
REPS, DR Aggregator - Ancillary Services Revenues
– Must meet conditions for eligibility for each market.
– Currently, DR only receives revenue as LaaRs.
– QSE would have to bid DR. REPs – Arbitrage Value
– REPs have little interest in DR for arbitrage under current market.
– Difficult for DR to qualify and sell into the Balancing Energy Market.
– AMI, change in settlement from profile could make DR a valuable option.
– Will DR receive LMP? REPs – lower LMPs
– Requires large amounts of DR to lower market price, socialized benefit.
– DR can reduce local congestion, but REPs will be charged zonal price. QSE – could benefit from reduction of imbalance events. ERCOT –source of reserves and ancillary services; avoids ICAP costs.
26
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
$550
$600
$650
$700
$750
0 50 100 150 200 250 300 350 400 450 500 550 600 650 700
Curtailable Hours/Year
ER
CO
T M
arke
t P
rice
($/
MW
h)
$0
$10,000
$20,000
$30,000
$40,000
$50,000
$60,000
$70,000
$80,000
$90,000
$100,000
$110,000
$120,000
$130,000
$140,000
$150,000
To
tal
Val
ue
of
1 M
W o
f D
R
Gross Value of DR in ERCOT To REP and/or CustomerERCOT (7/1/05 – 6/30/06) MCPE + RPRS
Curtailing 1 MW during the 50 highest-priced hours would save ~$20,000
27
Benefits Realized by Other Market Participants
Benefits Realized by Other Market ParticipantsBased on ERCOT’s BES market, a
REP could save ~$20,000 by curtailing 1,000 kW during the highest-priced 50 hours.
The gross value could range from $4-20k for 10-50 hours. Value could be higher as some technology could access more than 50 hours.
LaaRs Program $40-$69 payments
Both REP and customer would likely require an incentive.
RANGE: $4 - $69 $/kW/yrLIKELY VALUE: $10.00 $/kW/yr $0
$50
$100$150
$200
$250
$300
$350$400
$450
$500
$550
$600$650
$700
$750
0 50 100 150 200 250 300 350 400
Curtailable Hours/Year
ER
CO
T M
arke
t P
rice
($/
MW
h)
$0
$10,000
$20,000
$30,000
$40,000
$50,000
$60,000
$70,000
$80,000
$90,000
$100,000
To
tal
Val
ue
of
1 M
W o
f D
R
REPs
ERCOT Market Price (07/05 – 06/06)
Commodity Value in ERCOT
28
Quantifying Value
($19-$78)
($20 - $120)
($4 - $20)
($35-$185)
Value Stack for Demand Response
NOTE: This does not include costs for marketing or profit sharing among parties.
Co
sts
and
Val
ue
of
DR
($ /
kW/y
ear)
TYPE ASocial
Benefits
TYPE BInternal
TDUBenefits
TYPE CExternal Benefits
Total Gross Benefits
Current Technology
Costs
$40
($19-$78)
$40
($20 - $1900)
$10.00
$60.00
$90
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
$110
$120
EE ProgramIncentives
T&D Avoided
Cost
(BESMarket)
TOTALGROSS
BENEFITS
AverageTechnology
Costs
($4 - $20)
29
Quantifying Value
($19-$78)
($20 - $120)
($4 - $20)
($35-$185)
Value Stack for Demand Response
NOTE: This does not include costs for marketing or profit sharing among parties.
Co
sts
and
Val
ue
of
DR
($ /
kW/y
ear)
TYPE ASocial
Benefits
TYPE BInternal
TDUBenefits
TYPE CExternal Benefits
Total Gross Benefits
Current Technology
Costs
$40
($19-$78)
$40
($20 - $1900)
$10.00
$60.00
$90
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
$110
$120
EE ProgramIncentives
T&D Avoided
Cost
(BESMarket)
TOTALGROSS
BENEFITS
AverageTechnology
Costs
($4 - $20)
Total Avoided Generation
Cost
Additional T&D Avoided
Cost
Market Potential
(LaaRs=$40 to $69/kW)
30
Conceptual ERCOT Market Structure Texas Legislature
Texas PUC
Bid
Disp
atch
Rate
Total Payment(G, T, D, + A)
T&D
Prop
osal
s
Metering Services
Committed Load
Payment for Committed Load ($)
Load
For
ecas
t
Met
erin
g Se
rvice
s
Physical Delivery
Physical Delivery
ERCO
T Se
ttlem
ent (
RPRS
+BE
S)
GenCo(or Power Marketer)
REP
End-User
ERCOT
TDSP Payment
Metering Svcs
QSE QSET&D Co
ER
CO
T S
ett
lem
en
t (B
ES
)
31
ERCOT Regulatory Environment
Advanced Meter Rules are currently under consideration.
TDU cannot provide Competitive Services—can’t reach behind the meter.
Limits on energy-efficiency incentive payments (~$20-40/kW/year) established by rule.
Existing LaaRs Market limited to very large customers (2005: 1,803 MW eligible, $71.1M payments or $39.40/eligible kW/year).
REP/QSE only access point into ERCOT energy market settlement process.
Fixed settlement profiles are a barrier to realizing DR value to REP and Customer.
32
REP Interviews – Highlights
REPs today sell largely on cost (3).
REPs expect to sell more on service (8).
AMI more important influence than PTB.
REPs don’t understand the EE Programs (although affiliated C&I ESCOs do).
Reducing acquisition costs all important.
Selling equipment to customers complicates sales process.
Most potential value perceived in mass market.
Want to be “in the loop” for demand response.
33
Business Model 1
TDU REP
End-Users
Contractual Payment
Mar
ketin
g
Inst
alla
tion
EE Program ($)
Avoided T&D ($)
Dispatch
3rd Party
EE Program ($)
34
Business Model 2
TDU REP(multiple)
End-Users
Contractual Payment
Ma
rke
ting
Inst
alla
tion
EE Program ($)
(Avoided T&D ($))
3rd Party
Joint Marketing
Joint Dispatch(Z times per year)
Performance Guarantee
Commodity Value ($)
EE Program ($)
Joint Dispatch (Y times per year)
Performance Guarantee
35
Section 39.905 (a) (3) Goal for Energy Efficiency
Envisioned a larger role for REPs
– “each electric utility will provide, through market-based standard offer programs or limited, targeted, market-transformation programs, incentives sufficient for retail electric providers and competitive energy service providers to acquire additional cost-effective energy efficiency equivalent to at least 10 percent of the electric utility's annual growth in demand”
The PUCT has opened the Energy Efficiency Rule for reconsideration. Additional Funding is required if we are truly hoping to have the REPs participate, and take efficiency to a new level.
If the avoided cost calculation can be modified to include the real avoided cost of T&D in addition to Generation, even with the current caps (35% for C&I, 50% for Res, 100% for HTR), Demand Response will likely flourish in the ERCOT Market
36
Quantifying Value
($19-$78)
($20 - $120)
($4 - $20)
($35-$185)
Value Stack for Demand Response
NOTE: This does not include costs for marketing or profit sharing among parties.
Co
sts
and
Val
ue
of
DR
($ /
kW/y
ear)
TYPE ASocial
Benefits
TYPE BInternal
TDUBenefits
TYPE CExternal Benefits
Total Gross Benefits
Current Technology
Costs
$40
($19-$78)
$40
($20 - $1900)
$10.00
$60.00
$90
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
$110
$120
EE ProgramAvoided Gen. Cost
T&D Avoided
Cost
(BESMarket)
TOTALGROSS
BENEFITS
AverageTechnology
Costs
($4 - $20)
+
37
Quantifying Value
($19-$78)
($20 - $120)
($4 - $20)
($35-$185)
Value Stack for Demand Response
NOTE: This does not include costs for marketing or profit sharing among parties.
Co
sts
and
Val
ue
of
DR
($ /
kW/y
ear)
TYPE ASocial
Benefits
TYPE BInternal
TDUBenefits
TYPE CExternal Benefits
Total Gross Benefits
Current Technology
Costs
$40
($19-$78)
$40
($20 - $1900)
$10.00
$60.00
$90
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
$110
$120
EE ProgramIncentives
(BESMarket)
TOTALGROSS
BENEFITS
AverageTechnology
Costs
($4 - $20)
38
Business Model 3
TDU REP(multiple)
End-Users
Ma
rke
ting
Inst
alla
tion
EE Program ($)
3rd Party
Settlement Payment
Joint Dispatch (Z times per year)
Performance Guarantee
Co
ntra
ctua
l P
aym
en
t
Pe
rform
an
ce
Gu
ara
nte
e
EE Program ($)
ERCOT
Supply Bids
Dispatch Order