Workshop I: Building a Solid Business Case 1_1.pdf• 28% have a "message broker" or a service-oriented-architecture (SOA) bus to link disparate systems. • 49% have a separate system

Workshop I: Building a Solid

Business Case

1

Workshop I: Building a Solid Business

Case

•• 10:00 10:00 –– 10:45: Defining the Smart Grid 10:45: Defining the Smart Grid

components and their Expected Benefitscomponents and their Expected Benefits

• 11:00 – 12:30 Developing your Smart Grid

Vision

• 3:00 – 4:00 Develop your Smart Grid Business

Case

• 4:00 – 4:45 Finishing Your Action Plan

2

Smart Grid Definition in the Eye of the Beholder?

• In 1972, Theodore George “Ted” Paraskevakos, while working with Boeing in Huntsville, Alabama, developed a sensor monitoring system which used digital transmission for security, fire and medical alarm systems as well as meter reading capabilities for all utilities. This technology was a spin off of the automatic telephone line identification system, now known as Caller ID.

• In 1974, Mr. Paraskevakos was awarded a U.S. patent for this technology. In 1977, he launched Metretek, Inc., which developed and produced the first fully automated, commercially available remote meter reading and load management system. Since this system was developed pre-Internet, Metretek utilized the IBM series 1 mini-computer. For this approach, Mr. Paraskevakos and Metretek were awarded multiple patents.

3

• First utility installations in the upper Midwest in 1980s—drive/walk by.

• First radio system, KCP&L in 1990s.

• Terms “Smart Grid” and “Intelligent Utility” emerged between 2000-2005

• Today Smart Grid is much more than just AMR/AMI—Today includes remote switching on the grid, sectionalization, capacitor banks, VoltVar technology, integration of intermittent renewables, HAN, microgrids, etc.

• AMI only part of the solution, about 34-40% all customers now installed, more than 50% with AMR

4

Smart Grid Definition in the Eye of the Beholder?

• Advanced Metering Infrastructure (AMI)

– Smart Meters & AMI Control System

– Meter & Backhaul Communications

• Meter Data Management

• Distribution & Substation Automation

– IT and Field Equipment

• Demand Response & Distributed Energy Resources

– Smart Thermostats

– Endpoint Switches

5

Smart Grid Definition – Key Components

The integrated operating environment

WMS/MWMSGIS

Planning Challenge: Making the Pieces Fit and Unlocking Value

CIS

Smart Grid Implementation Trends

7

From Five Point Partners’ Strategy, Research & Advisory practice:

• AMI has had the largest impact of Smart Grid on utilities with about 44 million

smart meters installed to date. Approximately 20% of utilities are installing

smart meters now.

• The second most active area has been in automating the grid: reclosers,

Volt/Var systems, substation automation, some automated switch and

sectionalization.

• Approximately 38% of utilities have installed Meter Data Management

systems.

• 28% have a "message broker" or a service-oriented-architecture (SOA) bus to

link disparate systems.

• 49% have a separate system or subsystem for bill calculation/bill presentment

to high-end C&I customers.

• 52% have a web self-service portal used in conjunction with their CIS.

• An increasing number of utilities, about 25 percent, say they will consider the

cloud for major systems, but actual implementations have been relatively few.

Benefits also somewhat in the eye of the beholder

– More efficient, automated functionality

– More accuracy/speed in meter reading

– More integration/breaking down internal silos—smart convergence

– More self-healing grid, more reliable electricity

– Societal benefits (still debated)

• More consumer empowerment

• Reducing carbon footprint

• Delaying/reducing need for generation through DR

• Better sustainability

8

What has Really Worked?

• One study showed that the ability to operate a distribution system within tight voltage levels in the lower half of the acceptable range could yield a 1 to 3 percent total energy reduction, a 2 to 4 percent reduction in kW demand, and a 4 to 10 percent reduction in kVAR demand without any negative effect on the customer.

• HANs have had very mixed reviews, Mike Harris, CIO at Clark Public Utilities: “The

HAN portion did not deliver the same level of satisfaction as it was more difficult to

operate and generally was disliked by our pilot participants.”

• Rebecca (Becky) Blalock, CIO (recently retired), Southern Cos: “We plan to be fully

completed by 2012. Currently we are reading the meters four times a day and we

don’t store that data for more than 30 days. “We’re not really mining the data, but

in the future we will. Also, there’s a move in Washington that we should read

meters every 15 minutes, but we don’t have the infrastructure to do that today.”

• Jeanne Vold, CIO, Northwestern Energy: “I think no matter what it is, there is going

to be a remaking of this industry no matter the catalyst. I think renewable energy

is going to continue to be a very big focus, but it’s very hard when you’re in a

recession and people are looking at the costs

9


Case

Questions?Questions?

10


Case

• 10:00 – 10:45: Defining the Smart Grid

components and their Expected Benefits

•• 11:00 11:00 –– 12:30 Developing your Smart Grid 12:30 Developing your Smart Grid

VisionVision


Case


11

Developing your Smart Grid Vision

Objectives:

• Learn how to define your Smart Grid vision by ‘fit/gapping’ your current system to available Smart Grid technologies

• Identify the business case components required to support your Smart Grid vision

• Identify and assess the data required to define the expected costs and benefits for deploying your Smart Grid vision, and present them in an intuitive format

• Create a realistic timeline for garnering internal company support

12

Developing your Smart Grid Vision

Objectives: Said Another Way…

• Define your Smart Grid Vision and Benefits

• Identify Costs to Enable your Smart Grid

Vision

• Define Plan to get Approvals for your Smart

Grid Vision

13

Define your Smart Grid Vision and

Benefits

• Document your Smart Grid Current State

• Define your Smart Grid Future State

• “Fit / Gap” your Current and Future States

• Develop Vision Implementation Approach

14

Document your Current State

• Metering Infrastructure



• Demand Response & Distributed Energy

Resources (DER)

15

State of Systems for Meeting Smart

Grid Demands*

*Source: 2011 CIO Survey by FPP

16

Document your Current State:

Metering Infrastructure

• Residential Meters

• Small Commercial Meters

• Large Commercial & Industrial Meters

• Communications Infrastructure

17


Meter Data Management

• Residential Meters

• Small Commercial Meters

• Large Commercial & Industrial Meters

• Systems:

– MDM

– CIS/Billing

18


Distribution & Substation Automation

• Systems– SCADA

– OMS

– WFMS

– GIS / WMS

• Line Switches and Reclosers

• VAR Support Equipment

• Voltage Regulators

• Automatic Throw-overs (Redundant Service Feeds)

19


Demand Response & DER

• Demand Response



• Distributed Energy Resources (DER)

– Electric Vehicles

– Energy Storage Devices

– Micro turbines

20


System Context Diagram

21

Define Future State: Benefits of

Advanced Metering Infrastructure

22

Advanced Metering Infrastructure Benefits

- Eliminate manual or drive-bys for on-cycle

meter reading

- Eliminate truck rolls for final meter reading

- Reduce manual cut-in/cut outs

- Reduce manual cut for non-pay

- Reduce manual reconnects after cut for non-pay

- Reduce manual same day reconnects after cut

for non-pay.

- Speed cut for non-pay

- Cut for all non-pays (benefit of outstanding

balance vs. cost to roll truck)

- Eliminate move-in/move-out gap lost revenue

Value Proposition Benefits

Remotely read meters automatically

Remotely turn-on/turn-off meters

Reduce revenue leakage due to meter

inaccuracy.

- Increase billed revenue through more accurate

readings



23


- Reduced outage call volume

- Reduced AHT for outage calls

- Increased Customer Satisfaction

- Reduce field patrol drive times

- Eliminate truck rolls for "OK on Arrival"


Proactively communicate with customers about

outages and restoration estimates either

through outbound calling or IVR

Identify and correct instances of current

diversion

- Increase revenue by recovering money lost to

theft of service

Remotely verify outages and restorations



24


Determine phase balance from remotely

measured data

- Eliminate costs for service calls to measure

phase balance

- Reduce supply costs by eliminating kVAs

required for reactive power.

- Avoid or defer upgrade costs due to capacity

freed up by reactive power minimization.

- FUTURE - Reduce carbon offset expenses.

Build PR credibility among the community,

customer base and regulators for "green"

initiatives.

- Positive outlook from external stakeholders and

constituents


Identify and correct customers with poor power

factors.

Define Future State: Benefits of Meter

Data Management

25

Meter Data Management Benefits

-Increase revenue through pricing during peak

times

- Increase earnings by creating larger spread

during off-peak times

Enable Pre-Pay Rate structures for higher

collection risk customers to reduce

uncollectable A/R.

- Reduce uncollectable A/R

- Optimize asset replacement/maintenance

strategies

- Reduce lost revenue due to outage

Enable customers to manage energy usage and

carbon footprint by providing information on

individual usage, current pricing and carbon

footprint

- Provide tools to incent movement to the higher

margin/lower cost usage timeframe


Increase revenue and earnings through the use

of real time or TOU pricing structures to drive

customers to use power at lower cost/higher

margin times.

Use SmartGrid data analytics to determine

remaining asset life and estimated time to

failure for generation and grid assets



• Data Management Benefits– The smart grid environment envisioned by federal and

state regulators holds real-time, dynamic pricing as a core benefit

• Given this:– Adopt an architecture that can scale to meet anticipated large

volumes of data and this need

– Doing so while data streams are more manageable will be helpful to prepare for larger volumes and increased complexity later

– Ignoring these trends may place utilities at an operational disadvantage – and perhaps even stress an existing CIS system to the point of failure – should large-scale adoption of dynamic pricing occur

26

Meter Data Management – CIS System Readiness Survey

•Respondents were asked to rank

their agreement with the

statements on a scale of 1 – Least

Likely to 5 – Most Likely.

•There is little confidence among

respondents that their existing CIS

systems are fully capable of

handling dynamic pricing and other

complex billing needs without

modification.

•Major programming changes

and/or significant enhancement or

configuration changes will be

necessary for many utilities, if not

a new solution altogether.

•In a related survey, nearly 35

percent of respondents indicated

that they may need to purchase a

new CIS solution and 31 percent

indicated that they might pursue a

major enhancement.

•Respondents were asked to rank

their agreement with the

statements on a scale of 1 – Least

Likely to 5 – Most Likely.

•There is little confidence among

respondents that their existing CIS

systems are fully capable of

handling dynamic pricing and other

complex billing needs without

modification.

•Major programming changes

and/or significant enhancement or

configuration changes will be

necessary for many utilities, if not

a new solution altogether.

•In a related survey, nearly 35

percent of respondents indicated

that they may need to purchase a

new CIS solution and 31 percent

indicated that they might pursue a

major enhancement.

27



28

Distrubtion & Substation Automation Benefits

Use AMI and grid sensors to detect, classify and

locate faults in realtime and track outage

extents and support restoration processes



- Reduce truck rolls for avoided outages

- Reduce supply costs by minimizing line losses

due to higher than required feeder voltage

- Eliminate truck rolls associated with

measuring/changing feeder voltages


Use DA for automatic fault isolation and load

switching and outage restoration



Use AMI and grid sensors to improve overall grid

operations and avoid outages caused by

overloads

Use DA to monitor and manage feeder voltage in

real-time



29

Demand Response & DER Benefits

- Reduce transmission capacity charges based on

peak load


freed up.

- Reduce supply costs by eliminating peak MWhr


- Reduce ancillary services costs by minimizing

required spinning reserves.

- FUTURE - Reduce carbon offset expenses


required balancing reserves.

- FUTURE - Reduce carbon offset expenses


Reduce peak system load via DR and DER

Reduce supply requirements during peak

periods

Reduce spinning reserves via DR and DER, on a

scheduled (day ahead) or real-time (< 10

minute) basis

Reduce balancing reserves via DR and DER, on a

scheduled (day ahead) or real-time (<10 minute)

basis



30

Demand Response & DER Benefits

- Increase revenue by selling back to the market

during peak times.

- Increase earnings by selling back to the market

during peak times.

Supplement generation with dispatchable VPP.

(PHEV, Home Generators)

- Reduce supply costs by allowing for distributed,

lower cost generation options

Use DR and DER to reduce exposure to spot

market pricing when short on forecasting.

- Reduce expensive spot market power purchases


Increase revenue and earnings by selling back

power into the market during peak times throgh

the use of DR and DER

31

Define Future State: Advanced Metering Infrastructure

32

Define Future State: Advanced Metering Infrastructure

Define Future State:


• Smart Metering:

– Residential

– Commercial / Industrial

– Remote Switching

• Meter Communications

• Backhaul Communications

• AMI Control Application (Head End)

33

34





• Validate/Estimate/Edit and Store Usage

• Billing Rate Management

– ‘Scalar Read’-Based (e.g. monthly reads)

– Time of Use / Critical Peak Pricing

– Pre-Pay

• Initiate Device Commands

• Share Meter data with Enterprise systems

• Provide Customers with detailed energy usage information to encourage usage reductions

35




– OMS

– WFMS

– GIS / WMS





36

37

Define Future State: Demand Response & DER



• Demand Response






– Micro turbines

38



39

“Fit/Gap” Current and Future State:


• Smart Metering:

– Residential

– Commercial / Industrial

– Remote Switches

• Meter Communications

• Backhaul Communications

• AMI Control Application (Head End)

40



• Validate/Estimate/Edit and Store Usage

• Billing Rate Management

– ‘Scalar Read’-Based (e.g. monthly reads)

– Time of Use / Critical Peak Pricing

– Pre-Pay

• Initiate Device Commands

• Share Meter data with Enterprise systems

• Provide Customers with detailed energy usage information to encourage usage reductions

41




– OMS

– WFMS

– GIS / WMS





42



• Demand Response






– Micro turbines

43

Define Vision Implementation

Approach

• Integration Approach

– Identify System Interface Alternatives

– Identify Integration Protocols (e.g. MultiSpeak)

– Define Approach

• Big Bang or Phased

– Risks of each Approach

• If Phased, then what Sequence?

– Business Drivers set Priority?

– External Drivers (Regulatory, Other)?

44

Integration Approach

45

Interface Alternatives:

Big Bang or Phased?

46

Could be a Loud Bang with all of this to Deploy!

• AMI Systems & Equipment– Advanced Metering, AMI Head End SW

– Communications & Backhaul

• Customer Systems & Equipment– CIS/Billing, MDM

– Customer Portals

– Load Management

• Distribution Automation Systems & Equipment– OMS, GIS, WFMS, WMS

– DA Equipment

• Demand Response & DER– DR Programs, Systems & Equipment

Big Bang or Phased?

47

• Big Bang Considerations

– Complexity

– Resource Constraints

– Potential for Lower Total Cost

• Phased Considerations

– Scope and Resources More Manageable

– Potential for “Throw-Away” Interfaces

– Declare ‘Victories’ Sooner

Big Bang or Phased?

48

Example: AMI followed by MDM

Vision Implementation Approach:


49

Customer Information System

(CIS)

Outage Mgt

Work

Management

Electric

Outage Data

Service

Request

& Compleion

Electric

Completion Data

Work Status

Mobile

DispatchMobile

Data /WFMS

Electric

Field

Activities

ITRON

Meter

Reading

RoutesMeter

Reads

GIS

Electric

Map Numbers

FlexNet

Meter

Reading

Routes

Meter Reads

Advanced Rates

Cut In / Cut Out

Remote Connect

Disconnect

Load Mgt Info

Meter Installs /

Change Outs

MDM

Meter Reads

Advanced Rates

Cut In / Cut Out

Remote Connect

Disconnect

Load Mgt Info

Meter Installs /

Change Outs

Outage Information

Identify Costs to Enable your Smart

Grid Vision

• Advanced Metering Infrastructure



• Demand Response & Distributed Energy

Resources

50


Costs• Smart Meter acquisition and installation

• Meter Communications Infrastructure /System acquisition and

installation

• Backhaul Communications Infrastructure / System acquisition and

installation

• AMI Control Application / Head End System acquisition and

implementation (includes integration with applicable business systems,

such as CIS, GIS, MDM, OMS)

• IT Architecture for AMI Application

51

Meter Data Management Costs

• Meter Data Management system acquisition and implementation

(include integration with applicable business systems, such as AMI, CIS,

GIS, OMS)

• IT Architecture for MDM system

• CIS software upgrade / replacement (acquisition and implementation)

52


Costs

• Engineering Planning Services

• Systems acquisition and implementation

– SCADA, OMS, Engineering Analysis, GIS, WFMS, WMS

• Equipment acquisition and installation

– Voltage / VAR Control

– Line Switching

• IT Architecture for Systems

53

Demand Response & Distributed

Energy Resources Costs

• System acquisition and implementation

– Demand Response / Load Management

• Equipment acquisition and installation

– Demand Response / Load Management

– Smart Thermostats / Home Area Networks

54

Define Business Case Format

• Summarize and Sell the Vision

– Define your destination(s) and how it makes you better (Scope and Benefits)

– Describe how you’ll get there (Costs and Schedule)

• Present the Numbers

– Cash Flow View

– Income Statement View

• Define Risks

55

Plan your Vision’s Approval

• Who are Approvers?

– Internal (Board, Executives, Management)

– External (State PSC, Federal – DOE)

• What are Approvers’ Requirements?

– Internal (Financial, Non-Financial)

– External (Energy Efficiency, Consumer Options)

• Position the Vision

• Develop Approval Timeline and Get Started

56

External Approval Notes

• The National Association of Regulatory Utility Commissioners (NARUC) issued 10 resolutions to help guide state regulatory commissioners’ efforts to formulate policies in their respective states.

• Overall, NARUC’s resolutions provided a good reminder that “development of smart grid standards can best be achieved through a partnership among the states, the federal government, and industry.”

• NARUC also stressed that state regulators have authority over issues related to cost recovery for investments.

• Utilities have paid careful attention to NARUC’s statements regarding cost recovery and are working carefully with their regulators to ensure prudency of investments.

57


Case


58


Case




Vision

•• 3:00 3:00 –– 4:00 Develop your Smart Grid Business 4:00 Develop your Smart Grid Business

CaseCase


59

Developing your Smart Grid Business Case

Objectives:

• Understanding the data collected

• Plugging in the right data into the business

case equation

• Crunching the numbers-comparing “what if”

scenarios

• Manage expectations and set strategy for

business case approval

60

Developing your Smart Grid Business Case

Objectives: Said Another Way…

• Assess and understand your specific data

• Use your data to present your case

• Be ready to review alternatives

• Set your approval strategy and get started

61

Assess & Understand your Specific Data

• Benefits Data

• Costs Data

• Does Recommendation “Add Up”

• Risks

62

Benefits Data

63

Sample Benefits Data:

Advanced Metering Infrastructure:

Benefits

64


- Eliminate manual or drive-bys for on-cycle

meter reading

- Annual meter reading costs Cost Reduction

- Eliminate truck rolls for final meter reading - Annual number of final meter

readings*Average cost per final read

Cost Reduction

- Reduce manual cut-in/cut outs - Annual number of truck rolls for cut-in/cut-

out*Average cost cut-in/cut-out

Cost Reduction

- Reduce manual cut for non-pay - Annual number of cut for non-pay * Average

cost per cut for non-pay

Cost Reduction

- Reduce manual reconnects after cut for non-pay - Annual number of reconnects * Average cost

per reconnect

Cost Reduction

- Reduce manual same day reconnects after cut

for non-pay.

- Annual number of same-day connects *

Average cost per same-day connect

Cost Reduction

- Speed cut for non-pay - Per day revenue of outstanding cut for non-

pay * delay from order generation to cut

Cost Reduction

- Cut for all non-pays (benefit of outstanding

balance vs. cost to roll truck)

- Uncollected revenue below the threshold Cost Reduction

- Eliminate move-in/move-out gap lost revenue - Lost move-in/move-out revenue Cost Reduction

Remotely turn-on/turn-off meters

Benefit Type

Remotely read meters automatically

Value Proposition Benefits Metrics Ap

p


Benefits

65


- Number of electromechanical meters *

$/meter

Revenue Increase

- Same Earnings Increase

- Reduced outage call volume - Number of Outage Calls eliminated *

Average Cost per Outage Call

Cost Reduction

- Reduced AHT for outage calls - Seconds of AHT reduction * $/second of call

handling

Cost Reduction

- Increased Customer Satisfaction N/A

- Annual revenue lost to theft of service* Theft

of Service recovery percentage

Earnings Increase

- Same Revenue Increase

Identify and correct instances of current

diversion

- Increase revenue by recovering money lost to

theft of service

Reduce revenue leakage due to meter

inaccuracy.

- Increase billed revenue through more accurate

readings

Proactively communicate with customers about

outages and restoration estimates either

through outbound calling or IVR

Benefit TypeValue Proposition Benefits Metrics Ap

p


Benefits

66


- Reduce field patrol drive times - Annual field patrol costs * estimated

reduction in patrols

Cost Reduction

- Eliminate truck rolls for "OK on Arrival" - Annual "OK on Arrival" instances * Average

$/truck roll

Cost Reduction

Determine phase balance from remotely

measured data

- Eliminate costs for service calls to measure

phase balance

- Number of phase balance truck rolls * $/truck

roll

Cost Reduction


required for reactive power.

- kVAR hours eliminated annually*$/kVAR

hour

Cost Reduction



- Capital Investement Deferred*Cost of

Capital*number of years deferred OR Capital

Investment Deferred * ROIC

Earnings Increase

- FUTURE - Reduce carbon offset expenses. Cost Reduction

Build PR credibility among the community,

customer base and regulators for "green"

initiatives.

- Positive outlook from external stakeholders and

constituents

N/A

Identify and correct customers with poor power

factors.

Remotely verify outages and restorations


p

Meter Data Management: Benefits

67

Meter Data Management Benefits

-Increase revenue through pricing during peak

times

- Increased revenue from peak pricing -

reduction in revenue from off-peak pricing

Revenue Increase

- Increase earnings by creating larger spread

during off-peak times

- Additional margin from off-peak usage Earnings Increase

Enable Pre-Pay Rate structures for higher

collection risk customers to reduce

uncollectable A/R.

- Reduce uncollectable A/R - Annual Uncollected Receivables * %

reduction of Uncollected Receivables

Cost Reduction

- Optimize asset replacement/maintenance

strategies

- Savings in asset replacement/maintenance Cost Reduction

- Reduce lost revenue due to outage - Annual revenue lost due to outages related

to equipment failure * Failure Outage

Reduction Percentage

Increase Revenue

Enable customers to manage energy usage and

carbon footprint by providing information on

individual usage, current pricing and carbon

footprint

- Provide tools to incent movement to the higher

margin/lower cost usage timeframe

N/A

Use SmartGrid data analytics to determine

remaining asset life and estimated time to

failure for generation and grid assets

Increase revenue and earnings through the use

of real time or TOU pricing structures to drive

customers to use power at lower cost/higher

margin times.


p

Distribution & Substation

Automation: Benefits

68

Distribution & Substation Automation Benefits

Use AMI and grid sensors to detect, classify and

locate faults in realtime and track outage

extents and support restoration processes

- Reduce lost revenue due to outage - Annual revenue lost to outage * Outage

revenue recovery percentage

Revenue Increase

- Reduce lost revenue due to outage - Number of outages avoided * Average lost

revenue per outage

Revenue Increase

- Reduce truck rolls for avoided outages - Number of avoided outages * $/truck roll Cost Reduction

- Reduce supply costs by minimizing line losses

due to higher than required feeder voltage

- Line lose kVA eliminated * Average $/kVA Cost Reduction

- Eliminate truck rolls associated with

measuring/changing feeder voltages

- Truck rolls for voltage maintenance * $/truck

roll

Cost Reduction


Use AMI and grid sensors to improve overall grid

operations and avoid outages caused by

overloads

Use DA to monitor and manage feeder voltage in

real-time


p


Energy Resources: Benefits

69

DR & DER Benefits


required for reactive power

- kVAR hours eliminated annually*$/kVAR

hour

Cost Reduction






Earnings Increase


- Reduce transmission capacity charges based on

peak load

- Peak MW reduction * Transmission Cost/MW Cost Reduction


freed up.




Earnings Increase

Use VPP capability with DA to supply power via

islanding during an outage.



Revenue Increase

Use DR to assist with load management for

outage restoration via automatic switching



Revenue Increase

Use DA to minimize reactive power via

IVVC/DR/DER control

Reduce peak system load via DR and DER


p



70

DR & DER Benefits

- Reduce supply costs by eliminating peak MWhr - (Avg peak season $/MWhr * - Avg.

Price/MWhr) * Peak usage eliminated

Cost Reduction



required spinning reserves.

- MWhr of spinning reserve eliminated

annually * Average $/MWhr of spinning

reserve

Cost Reduction

- FUTURE - Reduce carbon offset expenses Cost Reduction


required balancing reserves.

- MWhr of balancing reserve eliminated

annually * Average $/MWhr of spinning

reserve

Cost Reduction

- FUTURE - Reduce carbon offset expenses Cost Reduction

Reduce spinning reserves via DR and DER, on a

scheduled (day ahead) or real-time (< 10

minute) basis

Reduce balancing reserves via DR and DER, on a

scheduled (day ahead) or real-time (<10 minute)

basis

Reduce supply requirements during peak

periods


p



71

DR & DER Benefits

- Increase revenue by selling back to the market

during peak times.

- Annual MWhr sold into market *(Peak

$/MWhr - Avg Price $/MWhr)

Revenue Increase

- Increase earnings by selling back to the market

during peak times.

- Annual MWhr sold into market *(Peak

$/MWhr - Avg Cost $/MWhr)

Earnings Increase

Supplement generation with dispatchable VPP.

(PHEV, Home Generators)

- Reduce supply costs by allowing for distributed,

lower cost generation options

- Annual VPP MWhr dispatched * (Spot Market

Price - VPP price)

Cost Reduction

Use DR and DER to reduce exposure to spot

market pricing when short on forecasting.

- Reduce expensive spot market power purchases - Annual instances being short * Average cost

of spot power during peak times

Cost Reduction

Increase revenue and earnings by selling back

power into the market during peak times throgh

the use of DR and DER


p

Costs Data

7272

Sample Costs Data:

Advanced Metering Infrastructure: Costs

Data

• Acquire, Install/Implement & Maintain:– Smart Meters

– Communications Infrastructure

– AMI Software & Hardware

• Cost Metrics– Regardless of Communication Methods, typical costs range

from $110 to $155 per meter*

– Ongoing Maintenance: $0.65 to $0.90 per meter

– Remaining Life Depreciation Expense Write-off for Existing Meters

* Assumes 25% Remote Disconnect Meter coverage, using dynamic, targeted deployment. Includes integration of AMI system with OMS, GIS and CIS systems.

73

Meter Data Management: Costs Data

• Acquire, Install/Implement & Maintain:

– MDM Software & Hardware

– CIS System (If needed)

• Cost Metrics

– MDM: Typical costs range from $20 to $30 per

meter, which includes integration with AMI

system

– CIS: Typical cost of about $60 per customer

– Ongoing Maintenance: 20% of Software Purchase

74

Distribution & Substation

Automation: Costs Data

75

• Acquire, Install/Implement & Maintain:– DA Equipment (Switching, Volt/VAR Control)

– Software & Hardware (SCADA, OMS, WFMS, GIS/WMS)

• Cost Metrics– Systems:

• SCADA (about $40k-$50k per Substation)

• OMS (about $10 - $12 per customer)

• WFMS (about $5 - $8 per customer)

• GIS (about $6M - $12M)

• WMS (about $10 per meter)

• Engineering Analysis (about $50k - $100k)

• Ongoing Maintenance: 20% of Software Purchase

– Smart Switches (about $30k each)

– Reclosers (about $20k each)

– Capacitors (about $4k each)

Demand Response & DER:

Costs Data

• Acquire, Install/Implement & Maintain:



– DR Software & Hardware

• Cost Metrics

– Endpoint Switches ($75 - $90 each)

– DR Software/HW ($0.30 per meter, if not included in AMI costs)

• Ongoing Maintenance: 20% of Software Purchase

– Turnkey DR Program (about $150 per switch)

76

Use your Data to present your Case

• Cash Flow view

• Income Statement view

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Cash Flow View

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AMI Business Case - Cash View (in millions)

0 1 2 3 4 5 6 7 8 9 10

Implementation Cost ($26.33)

Annual Incremental Ongoing Expense ($0.15) ($0.15) ($0.15) ($0.15) ($0.15) ($0.15) ($0.15) ($0.15) ($0.15) ($0.15)

Annual Benefit $5.89 $5.89 $5.89 $5.89 $5.89 $5.89 $5.89 $5.89 $5.89 $5.89

Annual Cash Flow ($26.33) $5.74 $5.74 $5.74 $5.74 $5.74 $5.74 $5.74 $5.74 $5.74 $5.74

Year

Income Statement View

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AMI Business Case - Income Statement View (in millions)

0 1 2 3 4 5 6 7 8 9 10

Implementation Cost ($2.63) ($2.63) ($2.63) ($2.63) ($2.63) ($2.63) ($2.63) ($2.63) ($2.63) ($2.63)

Accelerated Meter Depreciation ($11.89)

Annual Incremental Ongoing Expense ($0.15) ($0.15) ($0.15) ($0.15) ($0.15) ($0.15) ($0.15) ($0.15) ($0.15) ($0.15)

Annual Benefit $5.89 $5.89 $5.89 $5.89 $5.89 $5.89 $5.89 $5.89 $5.89 $5.89

Annual Profit/Loss ($14.52) $3.11 $3.11 $3.11 $3.11 $3.11 $3.11 $3.11 $3.11 $3.11 $5.74

Year

Does Recommendation Add Up?

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Smart Grid Deployment Risks

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Risk Risk Description AMI Billing Support The ability of the AMI system to provide the data

elements that are required for billing and customer information purposes

AMI Communication The ability of the AMI system to communicate the necessary information from the meter to the Head End system.

AMI Communication Interference from other sources such as Wi-Fi. Integration Integration of the new system with our existing

systems Vendor Viablity Vendor must continue to provide support for the

product. AMI Equipment Procurement Meter manufacturer must be able to provide meters

on planned inventory receipt dates AMI Equipment Installation Meter installation vendor must be able to complete

installations based on a pre-defined schedule AMI Software Release Stability Proven track record with current version Integration with Outage Management Integration of the new system with existing outage

analysis and management system Data Validation for Billing Meter Data must be validated for use in billing

process

Customer Claims from Meter Change Outs

Some customers may view their meter change out as a chance to make an unwarranted claim for damages

Integration with MDM Solution Integration of the new system with existing billing system.

Be Ready to Review Alternatives

• Drivers for Alternatives

– Implementation Approach

– Key Assumptions and Risks

• Develop “What If” Scenarios around

Alternatives

• Plug in numbers for “what if” scenarios

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“What If” Scenarios

• Difference Smart Grid Components

Implemented

• Alternate Integration Approach

– AMI to OMS?

• Alternate Implementation Approach

– Phasing Sequence

83

Plug in the Numbers for ROI Options

• Revised Benefits and Associated Savings

• Revised Smart Grid Deployment Costs

84

Set Approval Strategy and Get Started

Strategy Components:

• What is driving start date?

• What are key selling points?

• How does ROI compare with that of other approved projects?

• Why should this project be approved?

• Decision Makers’ Perspectives

– Supporter or Detractor

– What do they get out of it?

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Deliverables

• Business Case White Paper

• Business Case Management Presentation• Supporting Documentation:

– Smart Grid Value Drivers Worksheet

– Income Statement

– Cash Flow Statement

– Solution Selection Plan/Schedule

– Implementation Plan/Schedule

– Purchase Quotes

– Resource Plan (Internal and External)

– Internal Resources’ Change Impact Assessment

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Case


87


Case




Vision


Case

•• 4:00 4:00 –– 4:45 Finishing Your Action Plan4:45 Finishing Your Action Plan

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Finishing Your Action Plan

Objectives:

• Create Customized Plans for your Company

• Approval Timeline: Set realistic deadlines for

signoff from management

• Set Deployment Goals: Copy the success of

already proven community support campaigns

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Create Customized Plans for Your

Company

See Vision Definition Worksheet

• Current State

– Itemize Smart Grid Assets

– Context Diagram

• Future State

– Potential Benefits

– Itemize Smart Grid Assets

– Context Diagram

• “Fit/Gap” to identify Vision Requirements

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Create Customized Plans for Your

Company

See Vision Definition Worksheet

• Estimated Savings from Benefits

– By Component

• Estimated Costs to Deploy Vision

– By Component

• ROI Analysis

– Cash Flow View

– Income Statement View

91

Approval Timeline: Set realistic deadlines for

signoff from management

• Internal Approvals

– Requirements

– Timing

• External Approvals

– Requirements

– Timing

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Set Deployment Goals: Copy the success of already

proven community support campaigns

• Previous Community Support Campaigns

– What worked?

– What didn’t work?

• Smart Grid Community Support Requirements

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Case


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Documents

Workshop I: Building a Solid Business Case 1_1.pdf• 28% have a "message broker" or a service-oriented-architecture (SOA) bus to link disparate systems. • 49% have a separate system