November 2001CHRISTENSEN ASSOCIATES

RTP as a Demand Response Program – How Much Load Response Can You Expect?

Peak Load Management AllianceFall Conference

November 2001Steven Braithwait

Christensen Associates

November 20012CHRISTENSEN ASSOCIATES

Christensen Associates

Economic and engineering consulting for energy industry

25 years of experience in designing and evaluating retail pricing strategies – – TOU (traditional and competitive)

– Real-time pricing (NiMo, Georgia Power, KCP&L)

– Market-based interruptible load programs

November 20013CHRISTENSEN ASSOCIATES

Sound Bites from Yesterday

“Square peg in round hole” Customers aren’t generators

Trends in DR programs?Look at competitive markets

“Dollars on the table”Focus on NEW $$$ from efficient pricing

“Keep it simple”Here are tomorrow’s prices, you decide…

November 20014CHRISTENSEN ASSOCIATES

Topics

Real-time pricing as a DR program

Capturing the benefits of DR and RTP

Evidence of RTP load response

Technology facilitates residential “RTP”

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What is Real-time Pricing (RTP)?

A market-based pricing strategy – Customers face hourly spot market prices– Advance notice – day-ahead; hour-ahead– Price protection through hedging/price caps– Works in regulated and competitive markets

A demand response program

– RTP customers provide load reductions at times of high wholesale prices

November 20016CHRISTENSEN ASSOCIATES

RTP at Georgia Power Company

1,700 C & I customers

5,000 MW (80% of C & I sales)

Day-ahead (75%) & hour-ahead (25%)

Load response: 500 – 1,000 MW (at prices of $500 – $2,000/MWh)

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Benefits of Demand Response

Connects wholesale and retail markets

Demand response at high prices can reduce wholesale price spikes

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Connected Markets: Demand Response Yields Lower Wholesale Prices

$/MWh

GWh

Qnormal

Retail Price

Pnormal

Qspike

Lnormal

Dnormal

E

Pspike

Lhot

WP

B

Qhot

PhotE´

Dhot

A

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Capturing the Benefits of DR

To capture benefits, the amount of demand response must be measured and anticipated (e.g., in unit dispatch and power purchases)

November 200110CHRISTENSEN ASSOCIATES

Measuring Non-RTP DR

DR programs pay for “performance”

However, cannot “measure” performance (i.e., load reductions) by metering

Load response (LR) must be estimated:

LR = Baseline load - Actual load

Problems in estimating CBL; $$ at risk

November 200111CHRISTENSEN ASSOCIATES

Measuring and Forecasting RTP Load Response

For billing: No “verification” problem – RTP customers pay for what they consume

For forecasting:

– Develop load response model based on analysis of historical experience

– Advantage of aggregating over customers

November 200112CHRISTENSEN ASSOCIATES

RTP Load Response Curve for Georgia Power (Load Response as a Percent of Total RTP Load)

0%

5%

10%

15%

20%

25%

30%

35%

$0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000

$/MWh

% L

oa

d R

ed

uc

tio

n

November 200113CHRISTENSEN ASSOCIATES

Evidence of RTP Load Response

Georgia Power Real-Time Pricing (RTP) – 1,700 large C & I customers; 5,000 MW of load

Duke Power Hourly Pricing – 100 large industrial customers; 1,000 MW

GPU Energy “Critical price” TOU– 1997 residential pilot program

November 200114CHRISTENSEN ASSOCIATES

Summary of RTP Price Responsiveness

Significant, consistent load response

Small to modest price elasticities

Wide range across customer types

Most price responsive customers:

– Electricity intensive (e.g., most intensive industrials; residential customers with most major appliances)

– Enabling technology (e.g., own generation; storable production process; automatic controls)

November 200115CHRISTENSEN ASSOCIATES

0.60

0.70

0.80

0.90

1.00

1.10

1.20

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hour

Nor

mal

ized

Loa

d

0

2

4

6

8

10

12

14

16

Lo

ga

rith

m o

f P

ric

e (

$/M

W)

Highest DA prices

Load onhighest-price day

GP RTP Load Response (DA): Very High-Price (Load response = 500 MW; 20% of reference load)

November 200116CHRISTENSEN ASSOCIATES

0.000

0.050

0.100

0.150

0.200

0.250

0.300

0.350

0.400

HA OSG - I Non-Int - I OSG - C Non-Int - C

Moderatelyhigh price

Veryhigh price

Diversity of Customer Price ResponsivenessPrice Elasticity by Customer Type and Price Level

November 200117CHRISTENSEN ASSOCIATES

Duke Power RTP Load Response (per Tom Taylor, Rates and Regulation)

100 industrial customers; 1,000 MW

Total load response when Price > $.25/kWh– 200 MW, or 20% of expected load

20 customers reduced load by > 5%

Significant price elasticities for 25% of customers

November 200118CHRISTENSEN ASSOCIATES

GPU “Critical-price” TOU RateEffect of Technology on Load Response

TOU rate, plus critical price ($.50/kWh)

Interactive communication system– customers pre-select thermostat settings and

circuit priority at different price triggers– utility can send critical price signal

Similar programs at AEP, Gulf Power

November 200119CHRISTENSEN ASSOCIATES

“Critical-price” TOU Rate Design

0

0.1

0.2

0.3

0.4

0.5

1 8 14 18 20 24

Critical price

Rate 6173

Rate 9122

Standard Rate

November 200120CHRISTENSEN ASSOCIATES

Residential TOU Load Response – Critical Price Day

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Ave

rage

Hou

rly

Usa

ge:

kW

h/h

r.

ControlTreatment

OPS

Peak

SOP

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Conclusions

RTP offers demand response in a natural retail market setting

Methods are available for anticipating RTP load response at different price levels

Evidence is available on amount of RTP load response to expect

November 200122CHRISTENSEN ASSOCIATES

For Additional Information:

Customer Response to Market Prices – How Much Can You Expect When You Need it Most?, Steven Braithwait and Michael O’Sheasy, EPRI Pricing Conference, July 2000.

Residential TOU Response in the Presence of Interactive Communication Equipment, Steven Braithwait, in Pricing in Competitive Electricity Markets, Ahmad Faruqui, Ed.

The Choice Not to Buy: Energy Savings and Policy Alternatives for Demand Response, Steven Braithwait and Ahmad Faruqui, in Public Utilities Fortnightly, March 15, 2001.

Contact:Steve Braithwait (sdbraithwait@lrca.com)Christensen Associates608-231-2266

November 200123CHRISTENSEN ASSOCIATES

Types of Demand Response Programs

Demand-side bidding – customers bid load reductions into the wholesale market

“Buy-back,” or pay-for-performance interruptible – Suppliers buy load reductions, relative to baseline, at

price tied to market price

Real-time (hourly) pricing– Full-time

– Part-time; whenever cost exceeds specified level

November 200124CHRISTENSEN ASSOCIATES

How to Estimate Reference Load?

Historical load on same day-type (e.g., summer Tuesday, with “hot” weather)

Rolling average of loads on “non-event” days (e.g., previous 10 weekdays)

Average load in previous hours (e.g., previous 3 hours)

Key objective – avoid “gaming” possibilities

November 200125CHRISTENSEN ASSOCIATES

“Disconnected” Electricity Markets: Fixed retail price no demand response

$/MWh

GWh

Retail Price

Pnormal

Qnormal

Lnormal

Pspike

Qspike

Lhot

WP