Robert J. King GoodCompany Associates January 30, 2007 Exploring Aggregated Demand Response Solutions In ERCOT Markets

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)


• 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)


• Energy + ICAP (if qualified)

• Pays LMP >$75/MWh

Demand Response is used as an important tool of most ISOs

15


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


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



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)



Co

sts

and

Val

ue

of

DR

($ /

kW/y

ear)

TYPE ASocial

Benefits

TYPE BInternal

TDUBenefits



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


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)


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)



Co

sts

and

Val

ue

of

DR

($ /

kW/y

ear)

TYPE ASocial

Benefits

TYPE BInternal

TDUBenefits



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)



Co

sts

and

Val

ue

of

DR

($ /

kW/y

ear)

TYPE ASocial

Benefits

TYPE BInternal

TDUBenefits



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


(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)


Co

ntra

ctua

l P

aym

en

t

Pe

rform

an

ce

Gu

ara

nte

e

EE Program ($)

ERCOT

Supply Bids

Dispatch Order

Documents

Robert J. King GoodCompany Associates January 30, 2007 Exploring Aggregated Demand Response Solutions In ERCOT Markets