Wisconsin Public Service Commission
Technical Conference on Benefit-Cost Analysis
KEMA’s Experiences and Perspectives
June 10, 2011
Agenda
• Smart Grid – Definition and Level Set
• Business and Technology Trends Impacting Smart Grid
– Distributed Energy Resources
– Electric Vehicles
– Smart Phone Applications
– Advanced Demand Response
• The Business Case Process
• Case Studies – Business Case Results
• Typical Recovery Mechanisms
• Key Policy Issues
– Data Management and Privacy
– Command and Control
– Customer Concerns and Options
• Right of Refusal – Opt Out?
• Accuracy
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KEMA Confidential Information
KEMA has been serving clients for more than 80 years
Serving electric utilities ’ diverse needs from generation to retail
• Established in 1927, Arnhem, the Netherlands
• Three primary business lines:
– Consulting
– Testing
– Certification
• 1,850 professionals in more than 20 countries
• Annual revenue of $300+ million
Independent experts to the global energy and utility industry
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KEMA Confidential Information
KEMA Qualifications
Our clients include some of the largest and most complex
global AMI and Smart Grid efforts
Representative Intelligent Networks Clients
6/9/2011
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KEMA Confidential Information
Background on AMI and Smart Grid
Electric Utility Industry – $300B+ in Annual Sales
Number of Customers
Annual Revenue
$350,000
140,000,000
122,471,071
$300,000
Million Dollars ($000,000s)
120,000,000
Number of Customers
100,000,000
80,000,000
60,000,000
40,000,000
Industrial
$200,000
Commercial
$150,000
$100,000
17,172,499
20,000,000
Other
$250,000
Residential
$50,000
759,604
Residential
Source: www.eia.gov
6/9/2011
Commercial
Industrial
KEMA Confidential Information
$0
2000
6
2001
2003
2004
2005
UTILITIES
MARKETS
REGULATORS
SYS OPERATORS
Utility Industry Overview
RETAIL
WHOLESALE
NERC
FERC
PUCs
8 Regions
Federal
50 States
ISOs / RTOs
CAISO, MISO, ERCOT, SPP, ISONE, NYISO, PJM
UTILITIES
GenCo /
IPPs
CONSUMERS
GENERATION
Power
Marketers
Investor-Owned
230
TRANSMISSION
Large
Commercial &
Industrial
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KEMA Confidential Information
Federal-Owned
9
Muni’s/PUDs
2000
DISTRIBUTION
Coops
912
CUSTOMER SERVICES
Medium
Commercial &
Industrial
Residential
7
Changing Utility Business Environment
Deregulation
Restructuring
•
•
•
•
•
More Stringent Reliability Targets
Improved Operational Efficiencies
Tight Capital Budget
Customer Expectations
Utility
Market Expectations
Smart Grid
of the Future
2002010
Increased Focus on the Environment, Infrastructure and Customers
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Utility Industry’s Current Business Concerns
A North American Perspective
N
M
O
EN
VI
R
``
Demand
Response
Y
IT
IL
AB
LI
Renewable
Resources
Aging
Infrastructure
RE
EN
T
Greenhouse
Gases
Capacity
• Automation
• Smart Grid
• Information Technology
Energy
Sources
OPERATIONS EXCELLENCE
Aging
Workforce
6/9/2011
Operational
Efficiency
KEMA Confidential Information
Customer
Satisfaction
9
System Reliability & Customer Expectations
• Improving grid reliability has been a major concern
– Recent power outages
• Limited automation and inability to “see the whole grid”
• Improved Monitoring, Controls and Integrated Information Systems and
Operations
US Averages
US Best Practices
EU Averages
Leading
Practices
Source: Roger N. Anderson Colombia Univ.
6/9/2011
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10
Intermittent and Distributed Resources
Renewable Portfolio Standards (RPS)
• Significant increase in the penetration of intermittent (Wind, Solar)
resources is expected
• Intermittent resources are creating a major challenge for systems operators
– Forecasting, Scheduling, Trading, Balancing, Regulation, Settlement
1,200,000
1,000,000
800,000
4%
4%
2%
2%
8%
15%
Demand Resp.
Other
10%
MW Capacity
7%
Pumped Storage
600,000
13%
40%
Renewables
Hydro
32%
400,000
CA: 33% by
2020
Nuclear
6%
5%
200,000
Gas
Oil
32%
20%
Coal
0
2006
2020
2006 source: US EIA data
– 2020 source: a forecast
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Advanced Metering Infrastructure (AMI)
• Major State-level initiatives for deployment of Smart Meters and AMI
– Enable Demand Response and Time-of-Use Tariff
– Key State Initiatives: California, Texas, New York, New Jersey, Michigan, Oregon,
Ontario, Georgia, Louisiana
• Most AMI business cases heavily rely on the benefits of “Smart Grid” applications
– Enabling Distribution Automation, Demand side management, improved outage management,
condition monitoring
Current National AMI/DR Regulatory Activity - 36-40 States
6/9/2011
KEMA Confidential Information
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Sample AMI / Smart Grid Initiatives in North America
• 5.3 Million Meters
• 9 Million Meters
• 1.4 Million Electric • 1.7 Million Meters
• SmartConnectTM
• Climate Smart
Meters
• Smart Grid
• Circuit of the Future
• Smart Metering &
Infrastructure
• BPL Infrastructure • Intelligent Grid
• Utility of the Future
• Smart Grid Apps
• 4 Million Customers • Highly Mesh Urban
Demonstration Center
• Integration with
• 5 Million Customers
Grid
System Operations
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KEMA Confidential Information
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The Smart Grid Movement
• Smart Grid: An enhanced electric transmission or distribution network that extensively utilizes
sensors, controls, data communications and information technologies to improve reliability, economics
and security of the power system, while accommodating a greater levels of demand response,
distributed and intermittent generation and storage resources, and the overall automation.
• Smart Grid Initiatives in North America:
–
DOE GridWise / EPRI IntelliGrid initiatives
–
Many US utilities have embraced the need for “grid modernization”, creation of Utility of the Future, and Smart Grid
• Energy Independence & Security Act or 2007 – Signed Dec. 19, 2007
– Title XIII: Smart Grid Provisions
•
Creation of an 8-member Smart Grid Advisory Committee and a Smart Grid Task Force
•
Report to Congress the status of smart grid deployments and any regulatory or government barriers
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KEMA Confidential Information
14
The Smart Grid Move
20th Century Grid
21st Century Smart Grid
Electromechanical
Digital
Very limited or one-way communications
Two-way communications every where
Few, if any, sensors – “Blind” Operation
Monitors and sensors throughout – usage, system status, equipment
condition
Limited control over power flows
Pervasive control systems - substation, distribution & feeder automation
Reliability concerns – Manual restoration
Adaptive protection, Semi-automated restoration and, eventually, selfhealing
Sub-optimal asset utilization
Asset life and system capacity extensions through condition monitoring
and dynamic limits
Stand-alone information systems and
applications
Enterprise Level Information Integration, inter-operability and coordinated
automation
Very limited, if any, distributed resources
Large penetrations of distributed, Intermittent and demand-side resources
Carbon based generation
Carbon Limits and Green Power Credits
Emergency decisions by committee and
phone
Decision support systems, predictive reliability
Limited price information, static tariff
Full price information, dynamic tariff, demand response
Few customer choices
Many customer choices, value adder services, integrated demand-side
automation
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6/9/2011
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New Connections and Functions
Advanced Metering
Information
Technologies
Demand Response
Smart Power
Electronics
Distributed Generation &
Demand Side Resources
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KEMA Confidential Information
17
A Vision of the Future Market Segmentation
Energy Markets
Smart
Smart
Generation
Generation
Centralized
Centralized
Smart
Smart
Grid
Grid
Distributed
Distributed
Transmission
Transmission
Distribution
Distribution
Commercial/
Commercial/
Industrial
Industrial
Residential
Residential
Baseload
Baseload
Transmission
Transmission
Operations
Operations
Distribution
Distribution
Operations
Operations
Smart
Smart Motors
Motors
&
& Devices
Devices
Smart
Smart
Appliances
Appliances
Peaking
Peaking
Information
Information
Systems
Systems
Intermittent
Intermittent
Demand
Demand
Response
Response
Plug-in
Plug-in
Hybrids
Hybrids
Critical
Critical //
Backup
Backup
Asset
Asset
Management
Management
Advanced
Advanced
Metering
Metering
Building
Building
Automation
Automation
Green
Green
Power
Power
Grid
Grid
Monitoring
Monitoring
Site
Site Energy
Energy
Mgmt
Mgmt Systems
Systems
Photovoltaic
Photovoltaic
Power
Power
Electronics
Electronics
Smart
Smart
Storage
Storage
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Smart
Smart
End
End Use
Use
Grid
Grid
Automation
Automation
Communication
Communication
&
& Control
Control
Enterprise
Enterprise
Integration
Integration
KEMA Confidential Information
Smart
Smart
Dist.
Dist. Devices
Devices
© Center for Smart Energy
18
This Lead to the Need for Enterprise-Level Information
Integration
Executive Dashboards
T&D Operations
EMS DMS
Operations
Planning
SCADA
DSM
Resource
Dispatch
Trading &
Contracts
Maintenance
Asset Mgmt
Mgmt
Distribution Management
Enterprise
Information
Integration
Power Procurement & Market Ops
Planning & Bidding &
Forecasting Scheduling
T&D Planning & Engineering
Systems
Planning
GIS
OMS MWM
Customer Services
MDMS
CIS Call Center Billing
Settlements
Communications Infrastructure
Plant
Controls
6/9/2011
Substation
Automation
Feeder
Automation Advanced Metering Infrastructure
KEMA Confidential Information
19
Smart Gird
• A “full” business solution while leveraging the existing and new capabilities
People &
&
People
Process
Process
Policy
Policy
– Technology + People & Process + Policy & Regulations
Regulatory Incentives
Organizational Capabilities
Business Practices and Processes
Technology
Technology
Information / Systems Integration & Interoperability
Data Processing, Analysis & Intelligent Applications
Data Communications
Grid Design & Configuration
Intelligent Devices;
Metering. Protection, Control & Monitoring Equipment
Demand-Side Capabilities
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KEMA Confidential Information
Distributed Energy Resources
20
To set the context of today’s discussion, smart grid can
encompass a wide range of technologies and applications
Traditional Utility Value Chain
Power
Production
Leading Smart
Grid
Applications &
Technologies
• Distributed
generation and
energy systems
• Distributed energy
storage/ renewable
energy
• Conservation
voltage reduction
Transmission
• Synchronized
Phasor
Measurement
Units (PMUs)
• Flexible AC
Transmission
• High Voltage DC
• Substation energy
storage
Distribution
• Advanced Metering
Infrastructure (AMI)
• Line fault sensors
• Automated
reclosers
• Automated
Volt/VAR control
• Automated voltage
regulators
• Automated
capacitor banks
Smart Grid deployment will open a $100B
market in smart technologies1
Degree of
Market
Disruption
Minimal
Moderate
Large
Consumption
•
•
•
•
•
•
•
•
•
•
•
Home area networking
Autonomous DR
Smart appliances
Distributed generation
Integration of building
controls
Plug-in Hybrid Electric
Vehicles
Micro energy storage
Rooftop solar energy
Pre-payment systems
Time-based pricing
Third-party service
providers (e.g., DR)
Transformational
Note 1: Department of Energy; The Reform Institute, “The Smart Alternative: Securing and Strengthening
6/9/2011
KEMA Confidential Information
Page 21
Our
Nation’s Vulnerable Electric Grid”
The U.S. appears to be sufficiently advanced as a global
smart grid leader, although key barriers remain
Strengths
Technological
Advancement
L
H
M
Notable Programs
• Supportive federal policy for grid modernization:
EISA, ARRA, DOE
• More than $9B in grant/privately-funded projects
• Highest energy use in world – key driver
• Rapidly increasing venture and private sector
funding and innovation
• Predominantly integrated utilities provide
“systems view” of SG
Deployment Track
Record
L
H
Key Barriers
Spending Forecast
M
Policy and
Regulatory Drivers
L
H
M
• Lack of a national energy policy limits overall
direction and certainty (GHG, renewables)
• Limited utility industry R&D funding (<0.2%)
• >3000 total utilities, many at small scale
• Incomplete and ratified industry standards
• Inconsistent regulatory treatment
• Growing misperceptions by consumers (e.g., RF
issue)
• Growing concerns over cyber security
Source: GTM Research
6/9/2011
KEMA Confidential Information
Page 22
Favorable developments in the U.S. smart grid industry
include legislation and demonstrations
• American Recovery and Reinvestment Act (ARRA) with >$9B in total grant/private
project funding
• Various advocacy organizations such as the GridWise Alliance, GridWise
Architecture Council, and the DOE Electricity Advisory Committee
• Many Advanced Metering Infrastructure (AMI) projects, including ICT and power
electronics as well as smart appliances and home automation
• A number of utility-funded smart energy demonstration centers
Duke Energy
Envision Center
6/9/2011
Consumers Energy
Smart Services Learning Center
KEMA Confidential Information
CenterPoint Energy
Technology Center
Page 23
Trends for AMI and Smart Grid
What is happening now:
• FERC Order Demand Response Compensation in Wholesale
Markets is a Big Event
http://www.ferc.gov/EventCalendar/Files/20110315105757-RM10-17-000.pdf
– Orders market operators to respond by July 12 2011 with
analyses
– Orders proposed tariffs by Sept 12 2012
– What Else??? Changes to M&V, settlements, Systems
Recent History:
FERC NOI on VER
Integration
FERC Report on Demand
Response
FERC NOPR on Fast
Regulation from Storage
6/9/2011
KEMA Confidential Information
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Order 134 FERC ¶ 61,187 (Issued March 15, 2011)
FEDERAL ENERGY REGULATORY COMMISSION
• In this Final Rule, the Federal Energy Regulatory Commission
(Commission) amends its regulations under the Federal Power Act to
ensure that when a demand response resource participating in an
organized wholesale energy market administered by a Regional
Transmission Organization (RTO) or Independent System Operator (ISO)
has the capability to balance supply and demand as an alternative to a
generation resource and when dispatch of that demand response
resource is cost-effective as determined by the net benefits test described
in this rule, that demand response resource must be compensated for the
service it provides to the energy market at the market price for energy,
referred to as the locational marginal price (LMP).
• This approach for compensating demand response resources helps to
ensure the competitiveness of organized wholesale energy markets and
remove barriers to the participation of demand response resources, thus
ensuring just and reasonable wholesale rates.
6/9/2011
KEMA Confidential Information
26
EV and renewable DG market penetration estimates suggest
sizable growth in ten years
Solar Installations: California (GW – 2007 to 2013)
30
Existing installations - start of year
New installations
25
9.0
20
15
8.5
10
17.5
6.0
5
9.0
0
2007
2008
2009
2.0
1.0
3.0
2010
2011
2012
Given the potential
nature for these
impactful
technologies,
distribution utilities
need to take a
“systems” view of
their expected impact
(especially on a
circuit level)
2013
6/9/2011 KEMA Research and analysis, GfK Automotive
KEMA Confidential
Source:
Purchase Information
Funnel Benchmarks
27
Impacts to electric distribution grid can be substantial
Summary of Forecasted Impacts to Electricity T&D System, 2020
Based on forecasts of smart energy technologies, KEMA expects 20 to 30% of 25 kVA
transformers on 13 kV feeders for this utility could reach max. design loading by 2020.
6/9/2011
KEMA Confidential Information
Source: KEMA Research and analysis, North American client
Page 28
1. Introduction – What is “Markets 3.0”
Deregulation has driven the
development of wholesale energy
markets which strive to optimize the
economics and competition around
supply and demand. These markets
are characterized by the following
trends:
• Need to manage new products
such as Demand Response,
Storage, and Variable Energy
Resources
• Penetration and coupling into the
retail – industrial, commercial and
residential DG and smart load
resources
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2. Stages in North American Market Evolution
Markets 3.0
• Renewables as Market Resources
• Dynamic Retail Pricing
• Demand Response for Ancillaries
• Capacity Markets for Renewable Firming and DR
• Dynamic Intra Hour Scheduling for Renewables
• Storage as Resource
• Tighter Linkage of Gas and Electric Supply
2011-2020
Markets 2.0
• Co-optimized Energy and Ancillary Services
• Congestion Pricing
• Nodal Real Time Dispatch
• Capacity Markets for DR
2001 – 2010
Markets 1.0
• Wholesale Day Ahead Energy on Hourly
Schedules
• Ancillary Services
• Balancing and Regulation
• Transmission Rights
6/9/2011
1995 - 2003
KEMA Confidential Information
30
3. Drivers affecting the trend to Markets 3.0
RPS
Goals
Conventional Backup
Reserves and Ancillaries
Since we are spending
$$B on Smart Grid
(aka AMI), we need to
use those meters to
enable dynamic pricing
and customer
participation in markets
and operations .
6/9/2011
Forecasting
Ramping
Variability
Renewable
Penetration
1 GW Conventional Backup
for Every 1 GW of Renewables
250MW Ancillaries for Every 1 GW
Expensive
Polluting
Carbon
Reliance on gas fired back-up links to
gas supply contingencies
Electricity Storage
Automatic Demand Response
Dynamic Pricing
KEMA Confidential Information
Still Really
Expensive
Cheap & Clean &
Virtuous
31
Enabling Advanced Demand Response and
Dynamic Pricing in the Markets and Operations
• Identify DDR potential - consideration of what DDR does and does not
include and the optimal ways to quantify and segment this data set for the
market territory.
• Identify specific technologies and key attributes - including timelines and
costs - that are necessary to realize DDR potential in the wholesale
markets.
• Integrate DDR potential with dynamic pricing in the markets through
market simulation modeling. Examine impact on demand elasticity of
reduced direct access threshold.
• Identify market and operations impacts and suggest market, program, or
other approaches to enable greater demand side participation in
wholesale markets and operations.
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Understanding Dispatchable Demand Response
• Assess DDR Potential in Markets
– By customer segment and end use
– Identify available data to leverage
– Assess against DR market
products and market product
Conceptual Relationship Between Current, Future, and Technical
requirements
Potential DDR Total Load
• Latency
• Duration
• Fatigue
Total Load
• Verifiability
• Certainty / Yield
Technical Potential
• Understand customer behavior
around Dynamic Pricing and DDR
Interaction
Future Accessible
• Key challenges:
– Existing data (public, utility,
Currently
proprietary) available
Accessible
– Confirming optimal leverage and
data modeling approach
– Linking available end use data to
pricing assumptions for price
elasticity and technical
performance in DDR by time of
day, day type and season
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Unlocking Demand Response Potential
• Technology Roadmap
– Develop a matrix to identify and compare key elements of DP/DDR
enabling technologies
– By end use application / market product (Wholesale and Retail
dimensions)
• Communications for information
• Communications for control
• End use control systems – HW / SW
• Measurement & Verification
• Other categories?
– Segment and assess the role of different “players” in the value chain –
aggregators, utilities, associations, the internet / self aggregation
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34
DDR and Dynamic Pricing in the Markets
• Market Design Assessment – how will DP and DDR “fit” together in
markets
– Interaction between DP and DDR at customer end
– Role of DP and DDR in DA, HA, RT markets and ancillary services
– Settlements
• Market simulation to explore interactions and design consequences
between all wholesale and retail market participants and DR business
Processes
• Markets 2.0 Achieved Convergence of Spot (Real Time), HA, DA
markets – How will DDR and DP affect market stability
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Market 3.0 Design Issues
Time Dynamics
Process Error Effects
Inon-stationary processes
Latency
Forecasting
Duration
Estimated Elasticity
DA and HA prices will affect
“downstream” autonomous
demand decisions
Information
Propagation (Price
Forecasts, Prices)
Estimated Demand
Which Prices (HA,
DA, RT) for what
Resources?
Estimated Duration
Response Realization
Estimated Fatigue
End Users will want
to pay the price that
they responded to !
6/9/2011
KEMA Confidential Information
Load Forecast “Training”
behavior and ability to respond
to non-stationary demand
behavior
Demand will anticipate price
effects of weather – esp under
high renewables penetraton
and altered production
36
IDENTIFYING ARCHITECTURE
• What concepts should receive focus for this effort and which can
be assessed at another time? What are the subsystems?
– Not defining what a model has purposefully left out ‘undercuts the
utility of your model and weakens the ability of people to learn form
and improve it.’
Wholesale
Market
DP
• Enrollment
• Expected demand
• Price elasticity
• Actual demand
• Response time
• Rates
• DR savings
• Cost to curtail
6/9/2011
• Market prices
• Settlement
• Forecast demand
• Forecast supply
Generation
supply
DDR
• Availability
• Intermittency
• Actual supply
• Response time
• Bid profitability
• Operational Cost
• Enrollment
• Bids
• Price elasticity
• Actual demand
• Response time
• DDR profitability
• Cost to curtail
KEMA Confidential Information
• Bids
Page 37
Simple Business Dynamics Modeling Example
Fractional growth
rate
-
-
Price elasticity of
demand
+ Demand
Demand
+
Price
DDR bid +
-
-
+Bid amount
-
-
DDR
DDR
+
Cost to Curtail
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KEMA Confidential Information
+
Generation
+
Generation
+
+
expected profiability
of DDR bid
expected
profitability of bid
operational costs
+
38
Modeling Architecture Example
6/9/2011
KEMA Confidential Information
39
Business Case Process
Approach
Traditionally, an AMI Business case begins with the
development of a strategy that aligns business needs with
appropriate technology and deployment options
E.ON-U.S. Organizational Structure and Objectives
Legend
Internal
Focus
External
Focus
External/ Internal
Efficiency
Climate,
Green, CO2
Safety
Energy
Services
Fiscal Responsibility
Energy Delivery
Executive
Distribution Operations
Extend
Asset Life
Improve
SAIDI/SAIFI
Retail Operations
Help with
System
Planning
Improve
Customer
Satisfaction
Manage
Revenue
Services
New EE
Customer
Offers
CFO
T&G / Energy Markets Power
Production
Extend
Accounta
Txmssion
bility
Assets
Comply w
Accounta
Fed/State
bility
Regulation
Integrated
Accounta
Resource
bility
Planning
Corp
Planning
Accounta
Investment
bility
Analysis
General Counsel
Fin. &
Acct
State and
Federal
Accounta
Cash
bility
Mgmtn
Accounta
Meet
bility
Reqments
External
Affairs/
Comms
Corporate
Accounta
Citizen
bility
Information
Technology
Human
Resource
Systems
Utilization
Strategic
Planning
Operational
Accounta
Efficiency
bility
Accounta
(i.e.,
CCS)
bility
Data
Planning
Technology
Approach
Deployment
Strategy
Remote
Reading
End-point
Data
AMR
Tamper
Orange
Power
Outage
+
Remote
Program
Relay
AMI
Basic
TOU
Net
Metering
On/Off
Limiting
HAN
Appliance
Control
Energy
Monitoring
DSM
Line Fault
Detection
Westchester
Rockland
Bronx
Auto
Recloser
Smart
Grid
Volt/VAR
Mgmnt
Brklyn
Building
Mgmt
Queens
DER
Control &
Mgmnt
Legend
Costs
SI
Represents strong support
Represents mild or secondary support
Represents limited or no support
Benefit Area Identification
Interviews
and validation
+
Data Input and
Documentation
Request
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Page 41
Business Factors
+
KEMA Confidential Information
Benefits
Approach
The following list captures the majority of cost items
that are generally considered in the business case
Capital Costs (illustrative)
• Smart Metering
– Electric meters and gas meter modules
– Communications network
• IT Back-Office Systems (New / enhancements)
• Project Management (PMO)
• Applications (as required)
– Distributed generation, including solar
– Electric storage
– Energy efficiency, including in-home systems
– PHEV
• Transmission and/or Distribution Automation
– Line sensors and aggregator
– Substation communications
– Circuit breakers and circuit breaker relays
– Regulator automation
– Capacitor automation
– Sectionalization
– Self-healing technology Other Costs
– Obsolescence
– Training
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KEMA Confidential Information
O&M Costs (illustrative)
• Meter and communications equipment
power costs
• On-going communications costs (backhaul
connectivity, e.g. digital cellular or other
carrier services)
• Communications license fees (would
depend on technology chosen)
• Meter and communications equipment
service contracts and/or maintenance fees
• Data transfer fees
• Power theft investigation
• Training
• Corporate overheads
The cost areas cover virtually all of these components:
Approach
Additional considerations
Meter System and
Installation
Communications modules, deployment design & planning, maintenance,
warehousing, meter adapters, locking rings, bullets, uniforms, installer training, meter
testing, database integration, meter failure rates, device management services (flash
downloads) non-warranty costs, employee transition costs, certification costs.
Communications
Radio license fees, third party attachment fees, replacement costs (obsolesce factor),
etc.
Information Technologies
MDMS upgrades and on-going service contracts, Data Acquisition System, Workforce
Management System, Ancillary system upgrades (e.g., OMS), Asset Management
Upgrades
Customer Services
Upgrades to CIS and support staff, dual system support during transition
Management and other
costs
Process engineering, meter shop re-tooling, QA/QC
Options
AMI
Service relay, home area network enablement, in-home display units, links to water or
other meters
SmartGrid Equipment
Distribution Automation, DER monitoring, PHEV control, Voltage Regulator, Capacitor
Bank, Intelligent Switches, Line Fault Indicators, Transformer Monitoring, Phasor
Measurement Units, Reclosers, etc.
Page 43
Approach
Normally, benefits that are considered include
utility operational, and customer/societal areas.
Typical Benefit Areas (illustrative)
Utility Operational Benefits
• Reduced regular meter reading
•
•
•
•
•
•
•
•
•
•
•
•
•
costs
Reduced meter order costs (off cycle
reads, move-ins, move-outs,
disconnects, etc.)
Decreased power theft
Decreased meter repair costs
Increased meter accuracy
Reduced outage assessment and
outage verification time
Increased system voltage control
Increased system fine tuning
Improved asset management
Decreased manual circuit breaker
and capacitor inspections
Increased call center efficiency
based on access to timely meter
data
Reduction in estimated bills
Decrease in vehicle costs
Increase in safety
6/9/2011
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Utility System Benefits
•
•
•
•
•
•
•
Improved reliability
Deferred capital spending for
generation, transmission and
distribution investments
Reduced air emissions
Increased efficiency of power
delivery
Integration of renewable energy
distributed resources
Improved system security
Increased energy efficiency /
demand side management
participation
Customer / Societal Benefits
• Access to expanded data
•
•
•
•
•
•
•
•
•
KEMA Confidential Information
(consumption and power cost)
Faster outage response
Improved environment
Possible decreased power usage
(Prius Effect)
Increased ability to address PHEV
power requirements
Increased consumption
management
Cost savings from peak load
reduction
Increased energy efficiency
capabilities
Enhanced customer service
Expanded billing options; e.g., TOU
rates, selected billing dates, prepaid
metering, etc.
Approach
The CBA generally has key benefit areas such as:
Area
Additional Considerations
Ease to
Quantify
Range of
Variability
System Operational
Benefits
•Elimination of scheduled meter type replacement costs
•Incremental cost to investigate theft of service
•Short term increased cost at call center
•Accuracy improvement claw-back (short term benefit)
Moderate will
require
diligence and
data
Limited but based
on level of
diligence
Customer Service
Benefits
•E-bill payment savings (postage, paper, bounced check)
•Improved outage handling (IVR- ETR)
•Trouble isolation (load side of meter issues)
Moderate based
on projections
and data
Moderate level of
variability, may
dependent on
indeterminate
factors
Demand response
Benefits
•E-bill payment savings (postage, paper, bounced check)
•Improved outage handling (IVR- ETR)
•Trouble isolation (load side of meter issues)
Moderate to
difficult to
estimate
customer take
rates and
participation
results
Greater variability
driven by many
factors, e.g.,
incentives, rate
design, economic
condition
Management and other
• Possible higher inventory requirements (Comm modules,
Moderate will
require
diligence and
data
Limited but based
on level of
diligence
Societal and
Future Benefits
•GHG
•Carbon Credits
•Predictability and certainty of unknown impacts, e.g.
Difficult to
establish
baseline,
requires
projections and
estimations
High level of
variability
batteries, etc.)
•Ability to file for Stimulus Funding
EPHEV, etc
Page 45
Key Lesson Learned: Benefit
Documentation
• Itemize key findings and facts, basis, key assumptions
and calculation methodologies used;
• Socialize these and gain acceptance from
stakeholders;
• Maintain and update these as additional facts are
uncovered.
6/9/2011
KEMA Confidential Information
Page 46
Approach
An example of a Benefit Worksheet
Financial Model Summary
Benefits – Outage Restoration
Increased Revenue due to Reduced
Outage Restoration Time (E)
Other inputs
Description:
Intelligent Devices on the distribution network will provide additional information and isolation of outage conditions. With this information
outage restoration reporting functionality can be expected to reduce total time for service restoration, thus increasing the utility’s ability
shorten the loss of revenue associated with customers whose service has been severed during outage events. Additional strategic
benefits (e.g., improved regulatory response, improved customer satisfaction and public perception) would also expect to accrue but
would not be quantified.
Assumptions1
Process
• This benefit would be realized using Line Fault Indicators with reporting capability
• This can leverage AMS communications networks provided they are battery backed up
and sustainable during outages.
• The benefit level realized would be based on the percentage deployment of LFI.
• Functionality would require the use of a data Management system to effectively
interface with relevant systems (e.g., OMS).
• An estimated 50% of the potential outage restoration time improvement would result in
direct revenue enhancement, the other 50% would be attributed to error correction in
data reporting.
• Average total annual outage events2:
• Network = 6,181; Non-network (radial) = 5,622;.
• Average $0.211/kWh revenue per residential electric customer and $0.1334/kWh
revenue per residential electric customer in 2008.
• Average 0.577 kWh/residential customer/hour (5,052 kWh/8,760 annual hours) for
• Avg. customers affected per outage2:
• Non-network = 68.8; Network = 4.8;
• = 107.9.
• LFI power-up functionality can be expected to reduce outage restoration times:
- Network customers (limited SCADA visibility) = 10 minutes
- Radial customers (considering existing SCADA knowledge) = 2.5 min.
Step 1.
Determine total
average consumer
revenue per hour.
Step 2.
Determine total annual
projected outage
reduction time due to
LFI.
Step 3.
Determine total kWh
avoided energy loss
generated by LFI.
Step 4.
Determine total kWh
avoided energy loss
generated by AMI,
based on deployment
scope.
Calculation
Total avg. residential
electric revenue ($/kWh)
X Total annual avg. res.
customer kWh/hour
Total est. outage
restoration time reduction
X Total avg. # annual
outage events X
Percentage reduction
due to AMI
Total annual outage
savings X Total avg. #
customers
affected/outage
Total annual avoided
kWh loss X Total avg.
consumer revenue per
hour X deployment
scope
27
Page 47
• Case Studies:
Identify where possible
how this is supported
by available industry
case studies and
research results
• Stakeholder Review:
Show source of
information
assumptions, data, and
calculations
• Technology Alignment:
Indicate if this needs to
be aligned with
specific technologies to
enable functionality
and support the
identified, potential
improvement
Key Lesson Learned: Benefit Variables
• Often benefits and costs cannot be represented by a
single fixed value.
• Drivers influencing these may have bounded ranges
and a probability curve associated with them.
• These must to be factored into the business case
model to develop a set of most likely answers.
• Monte Carlo simulation techniques should be used to
assess the interaction and likelihood cases based on
the impact of multiple variables
6/9/2011
KEMA Confidential Information
Page 48
Many key drivers have associated
limited ranges of variability
Operational Benefit Drivers
Ref.
#
Tab
Name
Approach
Driver Information
Benefit Area
Description
Category
Type
Variable
Baseline
Range Used
1
Field Services
Meter Reader FTE Savings
Labor
Percent
% Work Reduction Estimated
96%
-6% to +4%
2
Field Services
Service Tech FTE Savings
Labor
Volume
# Off-Cycle Minutes per Day per Tech
106
-20% to +20%
3
Field Services
Service Tech FTE Savings
Labor
Volume
# Disconnect Minutes per Day per Tech
428
-20% to +20%
4
Field Services
Service Tech FTE Savings
Labor
Percent
% Work Reduction Estimated - Off Cycle Reads
90%
-20% to +10%
5
Field Services
Service Tech FTE Savings
Labor
Percent
% Work Reduction Estimated - Disconnects
95%
-20% to +10%
6
Field Services
Equipment Avoided Costs
Non-Labor
Rate
Equipment to Labor Savings Ratio - Meter Reader
3%
-2% to +2%
7
Field Services
Equipment Avoided Costs
Non-Labor
Rate
Equipment to Labor Savings Ratio -Service Techs
3%
-2% to +2%
30
Distribution Operations False Outage Dispatch Reductions
Labor
Volume
# Avg. Minutes per False Outage Visit
101
-50% to +10%
31
Distribution Operations Distribution Planning Capital Deferral
Cash Flow
Percent
% Capital Project $$ Deferred due to AMI
5%
-5% to +5%
32
Distribution Operations Distribution Planning Line Loss
Revenues
Percent
% Estimated Improvement in Line Loss
1.00%
-20% to + 20%
33
Distribution Operations Improved Customer Reliability - CAIDI
Revenues
Percent
% Estimated Reduction of CAIDI minutes
20.00%
-20% to + 20%
6/9/2011
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KEMA Confidential Information
Approach
However, other drivers often have a
higher level of variability
Societal Benefit Drivers
Driver Information
Benefit Area
Description
Ref.
#
Tab
34
TOU
DR Load Shift & Conservation
Societal
Volume
Estimated Summer On Peak Hours
36
TOU and PEAK
DR Load Shift & Conservation
Societal
Rate
37
TOU and PEAK
DR Load Shift & Conservation
Societal
38
TOU
DR Load Shift & Conservation
39
TOU
40
Baseline
Range Used
1,267
-50% to + 10%
Customer Adoption Rate - RES
10.00%
-5% to + 40%
Rate
Customer Adoption Rate - COM
10.00%
-5% to + 40%
Societal
Percent
Percent kWh OnPeak Shift - RES
1.00%
-50% to +50%
DR Load Shift & Conservation
Societal
Percent
Percent kWh OnPeak Shift - COM
0.25%
-50% to +50%
TOU
DR Load Shift & Conservation
Societal
Rate
Effective Elasticity Rate - COM
42%
-20% to + 20%
41
TOU
DR Load Shift & Conservation
Societal
Rate
Residential Conservation Rate
2.00%
-50% to +50%
42
TOU
DR Load Shift & Conservation
Societal
Rate
Commercial Conservation Rate
0.84%
-50% to +50%
43
PEAK
DR CPP Energy & Capacity
Societal
Percent
Percent kWh Reduced at CPP - RES
0.90%
-50% to +50%
6/9/2011
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Category
Type
KEMA Confidential Information
Variable
Approach
Business Case Modeling Stages and Key Elements
Once a baseline is established it is necessary to
evaluate the sensitivity of key factors.
Analytics
Inputs
Key
Assumptions
Pertinent
Artifacts
Define
Universe of
Possible
Benefits
Scenario
Benefits
Refine
Benefits
Model
Benefit
Practical
Adjustments
Benefit
Summary
Benefit
Model
Sensitivity
Testing
KEMA and
Client source
information
Assessment of
Client as-is
and key
drivers
Formula
and
Baselines
Deployment
Staffing
Alignment
with other
intersecting
efforts
Baseline
Income
Statement
KEMA and
Client source
information
Define all
potential cost
elements
Key
Assumptions
Pertinent
Artifacts
RFI or Prior
information
Refine Costs
Formula
and
Baselines
Model
Costs
Monte Carlo
Simulation
Analyze and
Optimize
Deployment
Staffing
Alignment
with other
intersecting
efforts
Practical
Adjustments
Costs
Cost
Summary
Model
Variation
Dimentions
Cost
Model
Approach
The output from the simulation and sensitivity
analysis will help identify key financial risk areas.
• Probabilistic Analysis Tools
• Deployment Scenarios
6/9/2011
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KEMA Confidential Information
Total NPV
AMR
Outage
Detection
Substation
NPV $M
• Options Modeling and Evaluation
Market Examples
Duke – Project Specifics (Indiana)
•Volume
– 809k electric meters
•Capabilities
– AMI and SmartGrid
•Benefits
– Direct cost reductions $141.9 M
– increased revenues $23.7 M
– Avoided costs $206.1 M
– Customer outage benefits $128.1 M
– Other customer - societal benefits $474.2 M
– Qualitative benefits (not included)
•Costs
– Capital $482.6 M
– O&M $168.4 M
•20 year NPV
– $365 M
Cost Recovery Method (filed not yet approved)
– Rate Base
Page 54
6/9/2011
KEMA Confidential Information
Duke Energy Filing
Summary DE Indiana Results – Graphic
(All values are 20-Year NPV in $ millions)
$ (millions)
$474.2
$800
$700
Total Quantifiable DE Indiana
Operational Benefits - $371.7
$600
$200
IT Back-Office Systems - $60.2
Data Transfer Costs - $
New Equipment O&M (PD) - $20.0
Network Infrastructure Support Labor - $11.4
Integrated Comm Box Software Mnt - $
Modem Billing Management Fee - $
All Other O&M - $27.3
Customer Feedback:
$442.86
PHEV: $31.30
Capital Expeditures - $482.6
Other - $3.6
Outage - $8.1
Distribution - $8.1
Metering - $122.2
$141.9
Direct Expense
Reductions
Endpoint Equipment - $
Communications Equipment - $
Installation / Deployment Costs - $
Distribution Automation - $52.6
IT Back-Office Systems - $36.6
PMO - $9.9
$23.7
Other - $0.7
Outage - $1.7
Metering - $21.3
$100
$
-
$555.9
$128.1
$206.1
$400
Includes affect of negative taxes
O&M Expenses - $168.4
Distribution - $179.3
Metering - $178.2
Outage - $9.8
Other - $4.3
$500
$300
Project NPV
$417.99
(including customer/
societal benefits
Increased
Revenues
Distribution - $171.3
Metering - $34.8
Avoided
Costs
$(100)
Customer
Outage Benefits
Other
Customer /
Societal
Benefits
Qualitative
Societal /
Customer
Benefits
Taxes - ($95.0)
Costs
Quantifiable DE-Indiana Benefits
6/9/2011
Page 55
Note 1: Example information from Duke Energy Indiana information
(publicly available
information
from DE Indiana filing)
KEMA Confidential
Information
Pacific Gas & Electric – Project Specifics
•Volume
– 5.1M electric meters; 4.2M gas
meters
•Capabilities
– AMI – HAN
•Benefits
– Meter Reading $1.085 B
– Customer Services $172 M
– Operations $728 M
– Capital Savings $41M
– Demand Response $348 - 529 M
– Qualitative Benefits (not included)
•Costs
– Capital $1.864 B
– O&M $381 M
PG&E’s initial technology choice related to the 2006 filing
only allowed a Basic Option 3 implementation
•20 year NPV
– 4% delta positive
In Jan. 2008 they revised their filing to move to full option 3.
They modified their technology choice.
Cost Recovery
– Balancing Account
Page 56
6/9/2011
KEMA Confidential Information
Pacific Gas & Electric – Discussion
•What they are getting
– Automated Meter reading.
– Prepay metering.
– Remote on / off.
– Outage detection.
– Service restoration notification.
– Avoided dispatches / truck rolls (labor
savings and carbon reduction).
– Call volume reductions.
– Records exception reductions.
– Complex billing ability (TOU, CPP).
– Capacity planning (detailed info).
– Demand response.
•Issues they are dealing with
– Piloting some Option 4 components:
Looking now at adding solar
generation measurement.
Looking at “Smart” charging.
Page 57
6/9/2011
KEMA Confidential Information
Comparison of California IOU Business Case Results
Source: CPUC Presentation
6/9/2011
Page 58
Source: Presentation by Tom Roberts CPUC 6/23/2008
KEMA Confidential Information
6/9/2011
Page 59
KEMA Confidential Information
Con Edison AMI Filing, March 2007
Optimal AMI Solution
15-Year NPV ($M)
$900
$800
$272.4
$712.8
• Deferred generation
• “Next Waves” deferrals
• Improved Environment
• Decrease Customer
Costs for Outages
$(202.7)
$700
“Societal” Benefits Include
$600
$510.1
$500
$400
$300
$200
$100
$0
Total Costs
Total Operational
Benefits
Total Shortfall
Total Societal and
Future Benefits
Page 60
Typical Benchmark Data AMI Cost and Performance Summary
• Costs are the capital cost of meters and communications, installed
Example Benefit Matrix NY State Assessment
Anticipated Benefits
Thought Starter
Direct Customers (rate payers)
Residential
1.
Commercial
Institutional
In Direct
Users
NY Residents
Electric Sector
Utilities
Utility
Shareholder
Academia
Other
Academia
Improved Cost Management and Customer Satisfaction
1.1 Lower Customer Electric Bills
1.2 Increased Customer Satisfaction
1.3 Lower Market-Based Cost due to Price Response
1.4 Reduced Congestion Costs
1.5 Access to New Products and Services
2.
Enhanced Power Quality & Reliability
2.1 Smart Grid devices on the T&D system
2.2 Asset Infrastructure Optimization
3.
Positive Societal/Environmental Impact
3.1 Job Creation
3.2 Enabling More Renewables And Storage
3.3 Adoption of Electric Vehicles
3.4 Enhanced Quality of Life
Primary/Direct Beneficiary
Secondary/Indirect Beneficiary
Not Applicable
62
Recovery Mechanisms
Regardless of the specific architecture, many utilities are
focused on similar core issues or potential program risks
Selected Utility Smart Grid Efforts
Intelligent Grid Technologies1
High
Self-Correcting
Line Switching
PHEVs
Enterprise
Data
Systems
Automated
Line
Sensors Energy
Storage
Complexity
Home Area
Networks
DER
AMI
Low
2008
High Speed
Communications
2013
2018
• How can initial investments in AMI or
Smart Metering be leveraged into a
broader Smart Grid architecture?
• Which technologies are ready for
investment now? Which ones should be
deferred?
• What is the right regulatory recovery
scheme (short and long-term)?
• How will consumers accept and interact
with these applications?
• How will incremental CapEx
requirements be integrated into existing
grid resource plans?
• What rate and service offerings are
needed to maximize consumer
participation?
• How well will standards drive innovation,
while maintaining security and reliability?
Time to Market Scalability
6/9/2011
Note 1: Partial listing
KEMA Confidential Information
Page 64
Given these factors, seeking to apply traditional utility
cost recovery mechanisms to smart grid creates the
need for variations in economic treatment
Traditional Utility Cost
Recovery Methods
Variations within Smart Grid Cost
Recovery Categories
• Caps on Smart Grid/ AMI cost recovery
categories (e.g., operational, capital)
Surcharges – Often approved
as a tariff rider, rather than
incorporated into the rate base
initially; utilize true-ups of actual
vs. estimated costs in different
intervals.
• Revenue requirements and risk of overrecovery, if benefits not fully realized/ tracked
• Carrying costs
• Accelerated depreciation for short-life assets
Trackers – Enables cost
recovery as they arise, rather than
requiring a prediction of costs and
conducting a true-up of actual vs.
estimated costs
Rate Base recovery – Program
costs are treated as a prudent
capital expenditure and are
approved in rate proceedings
6/9/2011
• Total Resource Cost test (TRC) metrics and
thresholds for costs v. benefits
• Timing of cost/ benefit evaluation (in a pre- or
post-deployment test year)
• Timing of recovery (pre, during, or post
deployment)
• Hybrid - track some costs and recover, others
via rate base
KEMA Confidential Information
Page 65
Smart grid or AMI cost recovery is well underway in
numerous jurisdictions
There are emerging variations in tariffs, rate design, utility and state revenue and
ratemaking requirements – yet no definitive trend has emerged
Cost Recovery Mechanism
States/ Utilities
Surcharge (tariff rider) with periodic true-ups
IL (ComEd); MA (Fitchburg, Western Mass Electric); NJ
(ACE, JCP&L; PSE&G); OH (all IOUs); OK (OG&E); OR
(PGE); PA (DQE, FE, PECO, PPL); TX (Oncor,
CenterPoint Energy, TNMP, AEP); VT (Central VT PS)
Rate base recovery - (either approved or
deferred)
AZ (APS); DC (Pepco); DE (Delmarva); IN (Duke Energy,
AEP); MD (BGE, Pepco, Delmarva); MI (CE, DTE)
Allowed rate-basing of some capital
investment
CA; CO (Xcel); MA; OR (PGE)
Cost Recovery Tracker
CA; MA (NSTAR); ME (CMP, BHE); WI (WP&L)
AMI or smart grid under consideration; cost
recovery ruling pending
CT (CL&P); FL (FPL); GA (Southern); ID (Idaho Power);
KY (Duke); SC (Duke)
AMI or smart grid ruling requires utility refiling
HI (HECO); IA (IP&L); NY (all IOUs)
6/9/2011
KEMA Confidential Information
Page 66
With these proceedings, other key trends are emerging
related to economic analysis and cost recovery
Cost Recovery Trends
• Most business cases are challenged to quantify enough operating benefits
to cover program costs – customer or societal benefits often needed to
reach a positive NPV, yet not consistently considered in each state
• Security / cyber security represents a growing regulatory issue, not just a
federal concern, and is requiring greater focus (and program cost impacts)
• Concerns over data privacy and protection are also increasing, with
inconsistency in state requirements and variations in regulatory attention
• As a result of strong reliance on energy efficiency and demand response
in the business case, we should see more utilities seek rate decoupling
options
• Level of intervention from consumer groups and other interested parties is
increasing the complexity of proceedings and depth of discussion
regarding risks, suitability of costs, and ability to achieve benefits
• Program drivers and performance metrics (e.g., cost, quality, time) will
emerge more often for implementation tracking and risk mitigation
6/9/2011
KEMA Confidential Information
Page 67
TRC or RIM
• In many cases it will be nearly impossible to isolate
respective costs and benefits for different tests:
– AMI Meter – TRC
– Incremental cost to add HAN for DR – RIM
– Communications network to support both Metering
and DR
• Pro rate based on % of communication ?
– Back office systems often have multiple uses
6/9/2011
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KEMA Confidential Information
Key Policy Issues
Distributed Energy Resources
•
•
•
•
Ownership and Control
Integrating intermittent resources into the grid
Reserve margin for DER
Safety and Security
– Back feed
– Partial voltage
• Credits
• Performance based incentives
6/9/2011
KEMA Confidential Information
Page 70
Command and Control
• Utility Responsibilities
– Safety
– Reliability
– Compliance to standards
– Availability
• Customer Responsibilities
– No harm
– Response
• DMZ Concept
– Neutral zone
• Prosumer
– Interaction
6/9/2011
KEMA Confidential Information
Page 71
Customer Rights
• Issues:
– Information Security
– Data Privacy
– Rights to access information
– Participation or opt out of DR programs
– Opt out of AMI (RF fear)
– Information in aggregate
– Community Energy Storage
– NIMBY pole top solar
6/9/2011
KEMA Confidential Information
Page 72
Open Dialog
Thank you for your interest.
Ron Chebra
Vice President
KEMA Inc.
[email protected]
609-865-0166