SCEs Demand Response Programs and Resource Planning

1
SCEs Demand Response Programs and
Resource Planning

• presented by
• Mark H. Wallenrod
• Manager, Pricing and Load Management

PLMA Fall 2003 Conference Demand Response
Resource Planning -- New York, NY September 8th,
2003
2
Agenda

• Background SCEs Demand Response Programs Past
  and Present
• SCEs DR Programs By the Numbers
• Current Portfolio
• Peak Reduction Capability 2003
• The Future Where Do We Want To Be?
• CA Statewide Initiatives
• Delivering Dependable DR SCEs DR Expansion
  Proposal
• Integration with Resource Planning What Do the
  Planners Want?
• Customer Preferences What Do Customers Want?
• The Bottom Line

3
SCEs DR Programs By the Numbers
Programs
Infrastructure

• 12 Programs (3-Pre 98)
• About 800 MW Peak Response (1500 MW in year 2000)
• 76 Curtailment Events
• (Almost 300 hours)
• Pre-1998 - 4
• 1999 - 1
• 2000 - 21
• 2001 - 38
• 2002 - 3
• 2003 - 9 (Pilot Programs)
• Over 1 million pages and e-mails
• Over 90,000 compliance bills
• Over 100,000 mailings annually
• Over 1,000 customers trained
• Communications in 5 languages

• Over 250,000 Load Control Switches
• 12,000 Real Time Meters
• 5,000 Smart Thermostats
• (2 Way)
• 21 VHF Transmitters
• 2 Secure Websites (Internet)
• 3 Auto Dialers (gt500 lines)
• Real Time Load Display
• (Firewall Protected)
• 1200 Load Monitoring/Alert Devices (Large Power)
• Satellite Paging

4
Demand Response Portfolio Active
Emergency
Economic (Price Response)
5
Demand Response Portfolio Pilot
Emergency
6
Peak Reduction Capacity - 2003


1 Estimates based on average number of
participants and incentives paid in 2002 (except
BIP, which is derived from 2003 results). 2
Available late 2003. 3 Available on, or about
September 1, 2003. 4 Excludes Bill Limiter
(Effective February 21, 2003 the bill limiter was
reinstated to reflect rate changes in effect
after June 2001, including the surcharge.) 5
The results of these pilots will be available in
the Quarter of 200XX 6 Utilizes programmable
thermostat.
7
New DR Targets Where Do We Want To Be?

• From CPUC Decision 03-06-032, dated June 5, 2003
• 2003 150 MW
• 2004 400 MW
• 2005 3 of Annual System Demand
• 2006 4 of Annual System Demand
• 2007 5 of Annual System Demand
• Note Excludes Demand Response from existing
  Emergency Programs
• SCE ordered to include targets in procurement
  plans

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The Goal Significant Increase In Price Response
Capability
1400 MW (7)
1400
1200
1000
5 new Price response (Economic)
900
762 MW (3.9)
(3.7)
800
Peak Reduction Capacity (MW), ( of Peak Demand)
600
762
400
(3.9)
Retain Moderate level of Emergency Capacity ( 2 )
500
200
(2.3)
0
Today
2007 (Goal)
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How Will We Get There?

• CA Statewide Pricing Initiatives (SCE, PGE
  SDGE)
• CPUC Proceeding launched in Summer, 2002 to
  promote DR as a resource to mitigate procurement
  cost and enhance reliability (2 phases)
• Phase 1 for small customers (lt200 kw) authorized
  pilot for 2500 customers of alternative pricing
  designs to provide input to analysis of
  deployment of advanced meters in Phase 2.
  (Approved March 14, 2003)
• Phase 1 for large customers (gt200 kw) adopted new
  Critical Peak Pricing and Demand Bidding Programs
  (including dispatch of CA Power Authority
  Programs). (Approved June 5, 2003)
• Also adopted transitional bill protection and
  technical incentives for 14 months.
• Phase 2 (pending) to address cost effectiveness
  of broader meter deployment based on demand
  elasticity results of
• Phase 1.

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Small Customer Pricing Pilot

• Develop price (demand) elasticities for
  alternative pricing designs. Three basic rate
  designs, including a control group
• Time-of-Use (TOU)
• Traditional two-part TOU rate (seasonal)
• Peak period from 2 p.m. to 7 p.m.
• Critical Peak Pricing-Fixed (CPP-F) (aka Shift
  and Save)
• TOU rate 350 days a year
• Higher price during peak period up to 15 days a
  year.
• Day ahead notification
• Critical Peak Pricing-Variable (CPP-V) (aka
  Shift and Save)
• Similar to CPP-F except notification can be as
  short as 4 hours ahead
• Critical peak period can vary in length from 1 to
  5 hours between 2 p.m. and 7 p.m.
• Consumers offered Smart Thermostat to automate
  response.

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Illustrative CPP Rate Design Shift and Save
Applicable up to 15 days per year (Monday
Friday)
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Shift and Save Pricing Plan (aka CPP)
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Large Customer Critical Peak Pricing

• Applicable to utility service customers only,
  including agricultural customers
• Triggered on day-ahead basis
• Maximum of 12 CPP days called per summer
  (business days only)
• Effective Rates
• On-peak CPP period energy charge set at 5 x
  otherwise applicable tariff (OAT) on-peak charge
• Mid-peak CPP period energy charge set at 3 x OAT
  mid-peak charge
• Non-CPP period On- and Mid- peak energy charges
  discounted from OAT

14
Large Customer Demand Bidding

• Applicable to utility service customers only
• Participants must designate committed load
  reduction amount.
• Minimum bid of 100 kW per hour.
• Demand reduction must be greater than or equal to
  50 of bid and up to 150 of bid.
• Price trigger
• IOUs to forecast hourly price offer on day-ahead
  basis
• DBP is triggered when price offer exceeds .15
  per kWh for 4 consecutive hours between noon and
  8 p.m.
• Incentive paid price x measured kWh reduction
• Reliability trigger
• DBP may be triggered on day of basis, when deemed
  necessary by ISO.
• Incentive paid .50 per kWh x kWh reduction
• Emergency Tests may be conducted twice per year
  and are limited to 4 hours in duration.

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Demand Bidding Internet Notifications and
Customer Interface
Customer Reviews Curtailment Event

• Receives pager/email notice
• Reviews event hours and incentive amount
• Places load curtailment bid

Customer Monitors Performance

• BaselineLoad
• Target Load
• Actual Load

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Status of CA Pricing Initiatives

• Small Customers
• (lt200 kW)
• Pilot launched July 1, 2003
• 9 Events
• Some preliminary results expected by year end
• Pilot scheduled to run through 2004

• Large Customers
• (gt 200 kW)
• New rates launched September, 2003
• Recruiting underway

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SCEs Resource Planning DR Proposal

• Supplement untested price response capability
  with aggressive expansion of proven price
  response direct load control (DLC) capability
  consistent with CPUC vision
• Leverage existing infrastructure with next
  generation of proven technology (controllable
  T-Stats).
• Enable future pricing programs
• Add 500 MW of new peak reduction capacity over 7
  years (500,000 customers)
• Promote reduced cycling or temperature setback
  strategies to minimize impacts on customer
• Price triggered DLC is the least cost, most
  reliable option available today for small
  customers
• A Resource Planners Dream Dependable,
  dispatchable load relief in 10 minutes or less.

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A Resource Planners DR Checklist

• Program Trigger (Price, Emergency, or Both)
• Dispatch Authority Who Pulls Trigger?
• Timing of Response How Fast?
• Resource Availability (Frequency, Duration)
• Operating Experience / Performance
• Incremental Cost / Cost-Effectiveness Measure
• Load Validation / Settlement
• Real Time Load Visibility
• Impact on Revenues
• Simplicity
• Compatibility with Energy Markets
• Rebound Effect
• Systems Database Integration

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Integrated DR Resource Value

• Non-Firm
• Dispatch by Multiple Parties (day ahead or
  longer)
• Limited Operating History
• Voluntary Pay for Performance (No Penalty)

• Firm (Dependable)
• UDC Dispatch (lt10 minutes)
• Real Time Visibility or Statistical Validation
• Mandatory Guaranteed Payment (Penalty for
  Non-Performance)

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The DR Resource Planning Continuum
Regulation / Pre- Deregulation
Fully Integrated Resource Planning
Transition
Over Capacity Who needs DR?
DR programs need to be fully integrated with
resource planning NOW!!
Somebody elses problem!
Deregulation
Recovery
Where was DR? We need DR Programs!
Market Failure
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What Do Customers Want?

• Customers Want . (or what they say the want)
• 100 Reliability . at NO additional cost.
• A lower (stable) bill . without changing any
  habits.
• A guaranteed payment for
• willingness to curtail load . without having
  to curtail load.
• A fair baseline . calculated my way.
• Energy Information . when I want it, the way I
  want it.
• DSM Benefits . but have someone else pay for it.
• Flat Rates . if currently have time varying
  rates.
• Time Varying Rates . if currently have Flat
  Rate.
• A Long Term Contract . unless prices decline.

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The Bottom Line

• Programs must provide a balance between both
  resource planning and customer needs.
• DR Resources must be cost-effective!!
• New programs will require time to demonstrate
  reliable response.
• Build on what WORKS today!
• DR isnt REAL until it becomes a dependable,
  dispatchable resource fully integrated into short
  and long term resource plans.

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Appendix Operating Experience
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SCE Demand Response Capability Infrastructure
CUSTOMER DATABASES
Customer / Program Info Equipment / Maintenance
Reporting / Billing
AUTO DIALERS
GRID DISPATCH
INTERNET
MULTIPLE CONTROL PLATFORMS
Secured website (SSL) Smart T-stat
program Bidding based programs Near real-time
load display Paging and email notices
Redundant rack systems Firewall
protected Real-time load display 128 telephone
lines 21 FM Transmitters(VHF) 5-min to call 1200
RTUs
Two external providers Remotely served gt500
lines
Event Launching Bidding Platform Notification
Platform Load Verification
MULTIPLE COMMUNICATION PROTOCOLS
Radio
FM Radio Pager / Satellite Internet Telephone
Pager
Land Line
Internet
COMMERCIAL / INDUSTRIAL
AG PUMPING
RESIDENTIAL
END-USER DEVICES AND INTERFACE

• 12,000 Real-time energy meters
• Real-Time load display
• 1200 Load monitoring/Alert devices
• 45,000 A/C DLC Switches
• 5,000 Smart T-stats (2-way)
• Satellite Paging

AC Cycling Load Control Switch
Remote Terminal Units Load Control Switches Smart
T-stat RTEM Meters Internet Applications
Load Control Switch

• 500 DLC Switches
• Radio Controlled
• Regional Load Control

• 200,000 A/C DLC switches
• Radio Controlled
• Regional Load Control

24.
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Key Operating Stats
A/C Work Orders
Todays Outlook

• Over 10,000 processed annually

• E-mail
• Over 1 million e-mails

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Customer Communications
Web Sites
Communication Documents

• 2 webs sites supported sign-ups for some
  programs available
• Over 2,000,000 hits on I-6 site in 2001 (over a
  3-week period)

• Over 1.2 million bill inserts featuring demand
  response programs since 2001
• Over 100,000 brochures mailed for Smart
  Thermostat
• Over 100,000 brochures mailed for residential A/C
  cycling
• Over 100,000 program mailings each year
• Up to 800 separate communication documents
  produced annually
• Communications in 5 languages

Recognized for excellence in marketing and
outreach by Industry and Peer Groups Peak Load
Management Alliance Assoc. of Energy Service
Professionals
Customers Contacted by Account Reps Annually
Customer Training

• 5,000 large power customers (in-person)
• 4,000 small business customers (phone)

• Over 1000 customers completed courses since 2001

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Emergency I-6 Performance (2000)
Process Industries
Transportation/Comm. Utilities
Ag and Water Pumping
Assembly Industry
Warehouses
College/Trade School
Lodging
Schools
Market Segment
Food Stores
Government
Hospitals
Military
General Office
Retail Stores
Medical Office
Nursing
0
10
20
30
40
50
60
70
80
90
100
of Available Peak Reduction Delivered
28
Price Response DBP (aka VPRC) 2000 Program
Performance
40
100
Recap - Key Facts
90
35

• 144 eligible service accounts
• Activated 37 times
• Maximum available peak load 279 MW
• Peak response 35 MW
• 39 of participants submitted bids for each
  event (average)
• 76 of bid commitment achieved (average)
• Participation declines significantly when MCP is
  lt than 23 cents/kWh

80
30
70
25
60
No. of Customers Participating
Peak MW Committed Reduced
20
50
40
15
30
10
20
5
10
0
0
gt50
46-50
41-45
36-40
31-35
26-30
25
24
23
22
21
20
lt20
MCP Range (cents/kWh)
Peak MW Committed
Actual MW Reduced
No. of Service Accounts
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SCE Energymart ThermostatSM Program (STP)
Broadcast Curtailment Message Wireless/Override
Acknowledgments from all EMis
Carrier EMi Thermostat
Curtailment Request
Verification of Load Reduction and
Override Notices
SCE Operator
Pager
Fan Coil Unit
Standard Web Browser

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Smart Thermostat Load Reductions
SCE RUNTIME ANALYSIS
Impact Analysis - All Participants
2.5
23 Activations
2.0
Temperature Setback
Override
8 15 23
0 2 4
1.5
kW
Est. Response 1.5 kw/Customer
1.0
0.5
0.0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
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Adj. Baseline
Control Day