Does Real-time Pricing Deliver
Demand Response?
Charles Goldman
Lawrence Berkeley National Laboratory
[email protected]
New England Restructuring Roundtable
October 28, 2005
Policy Questions
• What evidence is there that RTP delivers
demand response (DR)?
• What factors determine how much DR you
get?
– Customer enrollment (amount of load exposed to
hourly varying prices)
– Price response of enrolled customers
– Relative roles of RTP and Emergency DR
programs
• How does default service RTP impact retail
market development?
Recent Projects Examining Large
Customer RTP Experience
• Optional RTP Tariffs: Utility Experience
– Summarized 43 RTP programs offered by vertically
integrated utilities in 2003
– Analyzed trends in program participation & participant price
response
• RTP as Default Service:
– Case studies of eight states where RTP is considered for
large C/I customers in context of competition for retail load
– Comparative analysis of market and regulatory context,
RTP tariff design, and customer choices and response
• Case Study of Niagara Mohawk RTP
– In-depth study of customer choices and response to dayahead hourly RTP tariff as default-service in a competitive
retail environment
– Interviewed and surveyed customers and estimated price
response
Optional RTP Tariffs: Overview
• RTP offered by:
– Most investor-owned
utilities (IOU) in Southeast
and TVA
– All IOU in Illinois and NY
(statutory/ regulatory
requirement)
– Many mid-west utilities
(First Energy, Cinergy,
Xcel, KCPL)
– All CA IOUs in 2003, but
two programs since
cancelled
• RTP not offered by many
utilities in:
– The West
– New England
Number of Utilities in Each State with
RTP as Optional Tariff (2003)
RTP as Default Service: Regulatory &
Market Context
Retail Customers with Choice
Policy Context
for RTP
Implementation
Primary
Objective
Experimental
Rate Design
Marginal-Cost
Based Pricing
Resource
Planning/
Adequacy
Demand
Response
Expiration of
Transitional
Utility Supply
Service
Support Market
Development
New Load
Non>900 kW
Residential
(one-time only)
All Customers
Georgia
(GPC)
New York
Oregon
(IOUs other than
NMPC, CHG&E)
(PGE)
Penn.
New Jersey
(Duquesne)
(all IOUs)
Ohio
Maryland
(CG&E)
(all IOUs)
Illinois
New York
(ComEd)
(NMPC, CHG&E)
Optional
RTP
Default
RTP
Recent
Established
Bilateral-Only
ISO Market
ISO Market
Market
Wholesale Market Structure/Status
•
•
Default RTP driven primarily by retail market restructuring goals – not DR
In New York, PSC first decided against and then recently in favor of
statewide default service RTP for large C&I
Case Study of Niagara Mohawk RTP:
Choices Available to SC-3A Customers
Electricity Supply
delivery service
Additional Products & Services
electric commodity
late 1998
1998-2003
2004...
SC-3A Option 1
(RTP)
SC-3A Tariff
(demand and
volumetric charges)
SC-3A Option 2
(fixed-price forward contract)
contract
signed
contract effective
NYISO
curtailment incent.
hedges
tech. incent./
assistance
2001...
EDRP
ICAP/SCR
financial
derivatives
DADRP
NYSERDA
programs
competitive
retailer
products
competitive supply contract
(fixed-price or indexed)
Service provider
Type of service
NMPC
default
competitive retailer
optional
NYSERDA
NMPC or curtailment service provider
RTP Enrollment: A Snapshot
5050 MW
5,000
4,900
Load (MW)
• Why the differences?
– Alternative, fixedprice utility supply
option (e.g.,
Duquesne)
– Tariff design: dayahead vs. after-thefact price notice
– Retail market
development?
• Enrollment in Optional
RTP:
– Anemic in all cases
except Ga. Power
– Offer inadequate
savings opportunities
or “too risky”
– Lack of aggressive
marketing by utility
5,100
500
440 MW
default-service RTP
enrollment
optional RTP
enrollment
400
300
213 MW
200
100
Percent of
applicable customer class
• Enrollment in Default
RTP:
– 3-15% in PJM states
– 25-34% in New York
192 MW
85 MW
35 MW
0
0 MW
50 MW
0 MW
83%
80%
60%
40%
34%
25%
20%
15%
8%
0%
NJ
MD
3%
0%
PA
NY
NY
NY
(Duqne.) (NMPC) (CHG&E) (other
IOUs)
0%
0%
IL
(ComEd)
OR
(PGE)
GA
(GPC)
148
Niagara Mohawk RTP:
Customer Migration
Patterns
ESCO only
(25 customers)
back and
forth
between
NMPC and
ESCOs
(27)
100
• “You can build it, but they may not
•
SC-3A Customer
switched
after 2000
and did not
return
(37)
switched
only in 2004
(18)
50
•
•
•
•
Electric commodity provider
NMPC
ESCO (competitive retailer)
N=148
1
2000
2001
2002
2003
Summer
2004
NMPC only
(41)
•
(or may) stick around”
17% of customers left NMPC for
ESCO and never returned
18% went back and forth
37% switched later to ESCO and
never returned
28% of customers stayed on NMPC
RTP
Load served by ESCO: 30% (2000)
increased to 63% by 2004
Surprise: Load facing hourly prices
(45-60% in 2004)
Niagara Mohawk RTP:
What Customers Told Us
Load Response Strategies
Percent of Survey Respondents
80
9%
60
7%
N=76
40
forego
Frequency
No barriers encountered
9
Organization/ Business Practices
Insufficient time to pay attention to prices
Institutional barriers
Inflexible labor schedule
Electricity is not a priority
Cost/inconvenience outweighs savings
20
0
17
17
Risk averse/ hedged
5%
Respond
39
23
16
Inadequate incentives
33%
17%
•
•
•
onsite
generation
Barriers to Price Response (N=76)
shift
28%
Don't respond
Management views price response as too
risky
10
Flat rate or time-of-use contract makes
responding unimportant
9
~30% of customers say they are unable to curtail load
~70% can either forego or shift load or utilize onsite generation
Most customers report multiple barriers to price response;~15% respond
without obstacles
Niagara Mohawk RTP:
What customers actually did?
non-responsive (< 0.05)
N
Average
Elasticity
Government/Education
34
0.10
Public Works
17
0.02
Commercial/Retail
16
0.06
Healthcare
8
0.04
Manufacturing
44
0.16
moderately responsive (0.05 - 0.10)
100%
highly responsive (> 0.10)
Percent of Customers
Business Category
80%
60%
40%
20%
0%
Commercial/
Retail (N=16)
Gov't/
Education
(N=34)
Healthcare
(N=8)
Manufacturing Public Works
(N=44)
(N=17)
• Relative price responsiveness varies substantially across and within
business sectors
• Key Findings:
– 18% of customers account for 75-80% of aggregate DR
– 119 customers reduced their peak demand (500 MW) by ~10%
(50 MW)
Optional RTP Tariffs: Maximum Load Reductions
Public Service of
Oklahoma
• Aggregate load
reductions are
modest for nearly
all RTP programs
(<1% of utility
peak)
40 MW
Duke Power
200 MW
Com Ed (Rate RHEP)
Jersey Central
Power & Light
60 MW
Florida Power & Light
Kansas City
Power & Light
Otter Tail Power
(Option 1)
Pacific Gas & Electric
Georgia Power
Gulf Power
0%
750 MW
23 MW
1%
2%
3%
4%
5%
Maximum Load Reduction (% of Utility's Peak)
6%
– Only two utilities
(Duke & Georgia
Power) reported
load reductions
greater than 100
MW
RTP as Default Service: Customers Exposed to
Spot Market Prices
Percent of System Peak Load
20%
Default RTP Service
16%
Hourly Pricing w/ Competitive Suppliers
Total Large C&I Class
12%
8%
4%
0%
New Jersey
Maryland
NMPC
Service
Territory
• Potential market impact:
– Niagara Mohawk – curtailments equivalent to about 0.6% of
system peak load
– New Jersey and Maryland – unknown
ISO/Utility DR Program Performance
DR Program Maximum Load Reductions
Percent of Total System (State or Utility) Peak
New York
PJM*
Call Option Load
Reduction Program
Voluntary Emergency
Load Reduction Program
Scheduled Load Reduction
Program
Voluntary Economic Load
Reduction Program
(1)
Duquesne (2)
ComEd
Portland General
(2)
(2)
Georgia Power (1)
0%
•
•
1%
2%
3%
4%
5%
(1) Minimal or no participation
(2) No recent load curtailment
events or no data.
Actual performance tends to vary with program type
– Emergency DR programs yield large reductions when high payments offered (e.g.,
$0.50/kWh)
– Call option programs yield close to participants’ nominated amount
“Emergency DR” programs have thus far demonstrated larger load reductions than
RTP (except for GA)
– but not a direct substitute for RTP
Conclusions: RTP as a Demand Response
Strategy
• “You can build it but they may not come”
– Low enrollment in most optional RTP programs
• “Participation doesn’t guarantee price response”
– Only 10 of 42 Optional RTP programs report load reductions
– 18% of NMPC customers account for 75-80% of DR
• “Even if they come, they may not stick around”
– Expect that most customers will switch from Default RTP
– But Default RTP can yield significant indirect market benefits
• More retail choice customers willing to face hourly prices; but will
they respond?
• Program design, supporting infrastructure and utility incentives are
keys to success
– Default Service RTP: Day-ahead, hourly pricing balances retail
market development and DR
– Optional RTP: Georgia Power’s secrets to success (corporate
commitment, aggressive marketing; customers can hedge; and
CBL rules allow customers to generate bill savings)
– Policymakers must make long-term commitment to build DR
infrastructure (e.g.,customer info, tech. assistance,
codes/standards, mkt. assessment)
Implications: RTP as a Demand Response
Strategy
• Retail choice states
– Will state PUCs have the political will to establish RTP as
default service and for which groups of customers?
– Many customers willing to face hourly prices for some load
under current market conditions (moderate price volatility,
reasonably competitive retail market)
– NMPC experience suggests moderate levels of demand
response at high prices (10%; 50 MW)
– Policymakers need more information on retailer contract types
and response
• Wholesale market design
– Customers will enroll and respond to emergency DR programs
(1-3% of system peak)
– These DR programs are complementary with RTP
– Linking Price Response to ISO Spot Markets
LBNL Reports on RTP Experience
“A Survey of Utility Experience with Real Time Pricing”
G. Barbose, C. Goldman and B. Neenan. LBNL-54238,
December 2004.
“Real Time Pricing as Default or Optional Service for C&I
Customers: A Comparative Analysis of Eight Case
Studies”
G. Barbose, C. Goldman, R. Bharvirkar, N. Hopper, M. Ting
and B. Neenan. LBNL-57661, August 2005.
“Customer Strategies for Responding to Day-Ahead
Market Hourly Electricity Pricing”
C. Goldman, N. Hopper R. Bharvirkar, B. Neenan, R.
Boisvert, P. Cappers, D. Pratt, and K. Butkins. LBNL57128. August 2005.
Reports available at:
http://eetd.lbl.gov/ea/EMS/drlm-pubs.html
Background slides
Two-part Real-Time Pricing Tariff:
How It Works
2500
Customer Baseline
Load (kW)
2000
Credit for
Unused Energy
Below Baseline
Energy bought
at RTP
1500
1000
500
Baseline Energy
Purchased at
Off-peak Tariff
Rate
Baseline Energy
Purchased at
On-peak Tariff Rate
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Time of Day
• Customer sees hourly prices for their marginal usage
• Customer baseline (historic) usage (CBL) partially
hedges customer against hourly price volatility
Block and Index Pricing
2500
Treatment of energy
use below block level
varies by supplier
and contract type
Total Customer Load (kW)
2000
Load
purchased
at RTP
1500
1000
Load purchased at
on-peak fixed rate
Load
purchased at
off-peak
fixed rate
500
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Time of Day
RTP as Default Service: Customer Enrollment
350
35%
Default RTP Load (MW)
300
30%
5%
0
0%
Maryland
New Jersey
New York
Duquesne
50
NMPC
10%
CHG&E
100
Rockland
15%
PSE&G
150
JCP&L
20%
Atlantic
200
PEPCO
25%
Delmarva
250
BGE
MW
% of Total Customer Class
Penn.
Niagara Mohawk RTP Case Study:
Most Customers Don’t Check Hourly Prices
Never
8%
Routinely
14%
N=76
Weekly
3%
During periods of hot weather
9%
When NYISO emergency events are called
4%
Rarely
62%
• 70% of NMPC customers report never or rarely
checking day-ahead hourly prices
• 13% check when other signals – NYISO events or
hot weather – suggest they are high
• 17% consult prices routinely
Response to Day-Ahead Prices:
NMPC Aggregate Price Response Curve
Reduction in Peak Demand
6.0
$815/$169
4.0
Price Ratio
Average
Peak to
Off-Peak
Price Ratio
$439/$140
3.0
$181/$80
2.0
$77/$51
1.0
0.0
0
10
20
30
MWs
40
50
60
119 SC-3A customers would reduce their load by about 50
MW, or 11% of their peak demand (~500 MW), at high prices
Avg. Pk and Off-Pk Price
($/MWh)
5.0
Price Response of Customers on
Utility RTP Tariffs
• Georgia Power Company (Summer 1999 estimates)
– 750 MW load reduction on an exceptionally high
priced day
– Load reduction = ~15% of participants’ combined
billing demand
• Niagara Mohawk Power Company (2004)
– 50 MW reduction when peak prices = 5x off-peak
prices
– Load reduction = ~10% of participants’ combined
billing demand
Trends in Day-Ahead Market Prices:
Summer, Eastern New York
120
140
On-peak
Off-peak
On-peak
Off-peak
120
Standard Deviation of Price ($/MWh)
Average Price ($/MWh)
100
80
60
40
20
100
80
60
40
20
0
0
2000
2001
2002
2003
2004
2000
2001
2002
2003
*On-Peak defined as 2pm-5pm on weekdays
• Less price volatility since 2002 compared to summers of 2000 and
2001
• Average hourly prices for summer period are relatively stable over 5
years
2004
Georgia Power’s Secrets of Success
• Unique Georgia retail market underlies Georgia
Power’s success with RTP
– “New” C&I customers have a one-time choice of supplier
and GPC is allowed to compete
– High-level corporate commitment to RTP as a tool to
compete for new load
• Key tariff design and implementation details
– Aggressive marketing for >10 yrs
– High degree of ongoing customer support and (re-)training
– Attractive hedging options
• Two-part tariff design with CBL
• Supplemental financial hedging products (caps, collars,
contracts for differences, adjustable CBLs)
– CBL rules have enabled many participants to obtain
substantial bill savings, regardless of load response
Georgia Power RTP:
CBL Rules Enable Bill Savings
• Key fact: On average, each customer on Georgia
Power’s RTP rate has a CBL equal to 60% of its
actual load
– Across a sample of 85 accounts, the CBLs ranged from 0%80% of the customer’s total load
• How can this be?
1. Customers previously on Georgia Power’s Supplemental
Energy rate (a curtailable rate) could receive an initial CBL
equal to their Firm Load Level
2. New customers can receive a CBL below their projected
load
3. All customers can expand their facilities or add load
without adjusting their CBL upward
• Hourly RTP prices for load above the CBL have
historically averaged less than standard tariff rates
– Marginal vs. Embedded Costs
Utility and ISO/RTO DR Program
Enrollment (2004)
Percent of System Peak Load
Call Option Programs and Interruptible/Curtailable Rates (Contracted Load)
Scheduled Load Reduction Program (Nominated Load)
Voluntary Load Reduction Program (Nominated Load)
X = Program offered but enrollment data not available
5%
4%
3%
2%
1%
X X
X X
X
X
0%
New Jersey Maryland
•
X
DLC
New York
ComEd
CG&E
PGE
GPC
Most case study states have call option (or interruptible) and voluntary
load reduction programs for large C&I