Peevey Cooke Ruling Adopting A Business Case Analysis Framework For Adfanced Metering Infrastructure

4 Analysis Parameters

The following parameters should be used consistently for each required scenario analyzed:

1. 2006 to 2021 analysis period;

2. Benefits and costs calculated relative to the Base Case;

3. Costs and benefits presented as 2004 present value dollars, with annualized nominal values in work papers;

4. An extensive literature search to identify data or methods used by other electric or gas utilities to estimate benefits shall be performed. Some combination of the specific methods for gathering benefit and cost information (use of RFPs, benchmarks from other utilities, indirect benchmarks, in-house cost analysis and actual in-house costs) should be used to estimate the benefits for all of the categories above.

5. Potential costs and benefits that cannot be easily quantified or for which no dollar value can be derived because of uncertainty or lack of data should be reflected in the analysis by including a qualitative assessment of that value.

6. Discount rate equals utility cost of capital;

7. Demand response savings estimates based on weighted average of savings under average and hot weather conditions developed using Monte Carlo or other simulation techniques;¹¹

8. Avoided peak demand cost = $85/kW-yr (see Appendix B);

9. Avoided energy cost = $63/MWh (see Appendix B);¹²

To the extent that an analysis parameter is not defined here, but was listed in the Staff Report, utilities should identify the value used for that parameter and supporting rationale for their choice. Uncertainty should be captured in the analysis by using Monte Carlo or other statistical simulation techniques.¹³

Utility workpapers must clearly document the assumptions used for the following parameters in the benefit cost analysis:

1. Data collection interval by customer class (data granularity);

2. Frequency of utility data retrieval;

3. Meter functionality (data beyond usage collected by meter, e.g., voltage, power quality, etc.);

4. Means by which customer will have access to its usage data and projected use by customer class of this access;

5. Customer notification approach when CPP tariffs are triggered;

6. Prices and conditions in tariff structures (current tariffs, TOU, CPP-F, CPP-V, RTP, and CPP-Pure) used to model potential benefits;

7. Avoided transmission and distribution costs;¹⁴

8. Price elasticity assumptions;

9. Methods used to simulate customer price responsive demand;

10. Methods used to project customer choices of different tariffs and resulting share of customer participation in each rate;

11. Estimated cost to ensure that customer information systems (CIS) are compatible with collected data and rationale why utility chose to upgrade CIS, install (and ratebase) new CIS, or outsource CIS functions.

To the extent that the utilities use different assumptions from those recommended in the Staff Report, they must explain why they decided upon a different assumption.

(END OF ATTACHMENT A)

PHASE 1 - START-UP AND DESIGN COSTS

Communication System

C-1

¬ Costs to review and specify systems to ensure physical and logical security, securing data transmission, infrastructure to support security, etc.

C-2

¬ Perform and review site surveys to determine placement of network equipment

C-3

¬ Mapping of network equipment on company facilities (asset facility mapping)

C-4

¬ Staging facilities for WAN/LAN equip and mounting hardware (pre-installation)

C-5

¬ Review and develop strategies to retrieve data from meters and process within billing system

Information Technology and Application

I-1

¬ Network planning and engineering - coverage studies, technology selection, field testing & engineering

Management and Other Costs

M-1

¬ Buy out of Current SCE- or other utility ITRON Contract for 2000 ERT Deployment (350K meters)

M-2

¬ Meter RFP process and contract finalization and administration

PHASE 2 - INSTALLATION COSTS

Meter System and Installation

MS-1

¬ Additional temporary meter reading staff for transitional period/mtr reader transition costs

MS-2

¬ Administration of contracts/supervision of installer workforce

MS-3

¬ Cost of purchasing meters, comm modules and related vendor support equipment & software

MS-4

¬ Installation and testing equipment costs (tools, equipment and vehicles)

MS-5

¬ Installation labor (incl workers comp, P&B, payroll taxes, etc.)

MS-6

¬ Meter installation tracking systems (Endpoint Link-other), Meter info/records admin/GPS

MS-7

¬ Panel reconfiguration/replacement costs (A base, other)/Meter socket repairs

MS-8

¬ Potential customer claims related to damages during meter installation and/or panel upgrades

MS-9

¬ Salvage/Disposal process for removed meters

MS-10

¬ Supply chain management including development of staging facilities, shipment & handling of new meters

MS-11

¬ Training (meter installers, handlers, shippers)

Communication System

C-6

¬ Auxiliary equipment (e.g. remote antennas, isolation transformers, surge protection devices, etc).

C-7

¬ Costs of Pole replacement - to "fit" concentrators

C-8

¬ Development of communications link from meters to data center, LAN/WAN/servers for storage & processing

¬ Development of Internet based usage data communication

C-9

¬ Install costs of Cross arms (e.g. streetlight arms for pole top installations) and other mounting

C-10

¬ Purchase network communications equipment and hardware

C-11

¬ Training for installation of WAN/LAN equipment (including install labor for wireless circuits)

Information Technology and Application

I-2

¬ Computing system implementation in data center (new hardware/software, IT security review & compliance)

I-3

¬ Data center facilities

I-4

¬ Develop and process dynamic rates in CIS billing systems

I-5

¬ New information management software applications

I-6

¬ Records - databases, drawings of field network and data center servers

I-7

¬ Update work management interface to process additional volume of meter changes, data scripts

Customer Services

CU-1

¬ Customer records/billing and collections work associated with roll-out of meter change process

CU-2

¬ Increased call center activity during transition from existing to new rates /meter change appointments

CU-3

¬ Modification and customer support costs for OIS and other system changes

CU-4

¬ Process meter changes for new meter installations and DA accounts

Management and Other Costs

M-3

¬ Customers access to usage information through communications medium

M-4

¬ Employee communications and change management

M-5

¬ Employee training for deployment and O&M of new systems, rate structures, etc.

M-6

¬ Meter reader reroute administration (assuming gas meters are not included - will continue to be read)

M-7

¬ Overall project mgmt costs (and overhead) including customer service, IT and other functions

M-8

¬ Recruiting of incremental workers

M-9

¬ Supervision/overhead of contracts and technology personnel assigned to hardware and systems development

M-10

¬ Training for other traditional classifications (records, call centers, meter readers, T-men, etc)

M-11

¬ Work management tools

Gas Services Impacts

GS-1

¬ Gas Index/Module Purchases

GS-2

¬ Purchase/replacement of non-retrofittable gas meters

GS-3

¬ Replacement of gas meter module, battery purchases and replacement labor

GS-4

¬ Warehousing operations for gas modules

PHASE 3 - OPERATION AND MAINTENANCE COSTS (O & M)

Meter System and Installation

MS-12

¬ Cost of Maintaining Existing Metering Systems

¬ Additional costs to O&M/more complex metering & comm infrastructure (labor, tools, equip, vehicles)

MS-13

¬ Pickup reads (remote retrieval not available/possible)

MS-14

¬ Potentially higher meter replacement costs relative to existing mechanical meters (shorter life cycle)

Communication System

C-12

¬ Cost of Existing communication systems that take data from meters on monthly basis and turn it into bills

¬ Cost of attaching comm. concentrators (e.g., rent or lease charges by cities or other 3rd parties-not owned by utility)

C-13

¬ Costs of contracts to retrieve meter data and services

C-14

¬ Dispatching and O&M of field LAN/WAN and infrastructure equipment

C-15

¬ Electric power consumed by LAN/WAN equipment and/or meter modules

Information Technology and Application

I-8

I-9

¬ Cost of Maintaining Existing hardware and software that translates meter reads to customer bills

¬ Aggregating, validating and creating billing determinant data for electric billing

I-10

¬ Contract administration and database management of public network connections

I-11

¬ Exceptions processing (develop, update, and execute data cleanup routines)

I-12

¬ License and O&M software fees

I-13

¬ Ongoing data storage and handling costs/incl test, QA environments, business continuity, disaster recovery

I-14

¬ Ongoing IT system operations & maintenance (usage, software, internet application)

I-15

¬ Operating costs - retrieval and delivery of mtr, maint & outage information systems data and alarms

I-16

¬ Server replacements (every 3-4 years) for 15 year life cycle

Customer Services

CU-5

¬ Additional rate analysis due to multiple TOU options.

CU-6

¬ Cost of complying w/ regulations - providing alternative safety measures (due to removal of electric mtr readers)

CU-7

¬ Cost of reduced customer safety (meter readers no longer available)

CU-8

¬ Customer education of rate changes/customer communications campaign

CU-9

¬ Customer support for internet based usage data communication

CU-10

¬ Out-bound communications (mass media costs, e.g., print, radio, TV)./CPP or other rate notifications

Management and Other Costs

M-12

¬ Capital financing costs- discuss alternative methods of procuring the equipment or services (such as leasing or outsourcing) reviewed and rejected.

M-13

¬ Cost of increased load during mid-peak and off-peak periods

M-14

¬ Customer acquisition and marketing costs for new tariffs

M-15

¬ Risk contingencies (e.g., technology obsolescence/reliability)¹⁵

Gas Services Impacts

GS-5

¬ Aggregation/Validation of monthly/hourly reads for gas billing

GS-6

¬ Cost of complying w/ regulations - providing alternative safety measures (due to removal of gas mtr readers)

GS-7

¬ Energy diversion or safety inspection of service and meter facilities on some periodic basis (currently MRs)

GS-8

¬ Increased O&M on gas meters/modules due to addition of electronic modules

GS-9

¬ Performing atmospheric corrosion inspections (currently performed by meter readers)

Potential Benefits

Systems Operations Benefits

SB-1

¬ Reduction in Meter Readers, Mgmt & Admin Support (and associated costs)

SB-2

¬ Field service savings (turn-on's / turn-off's) and lower need for pickup reads

SB-3

¬ Reduced energy theft-May provide ability to ID active accounts for metered accts not being billed, broken meters, wrong multipliers

SB-4

¬ Phone Centers - Reduced FTEs in the long term due to anticipated lower customer call volume (estimated / disputed bills)

SB-5

¬ Possible productivity enhancement / rate changes simplified / possible reprogram rather than meter change

SB-6

¬ Outage management benefits (momentary checking for PG&E)

SB-7

¬ Better meter functionality / equipment modernization

SB-8

¬ Remote service connect / disconnect

SB-9

¬ Meter accuracy- improved and more timely load information could increase forecasting accuracy and reduce resource acquisition costs and reduced customer complaints about faulty meter reads

SB-10

¬ System planning design efficiency- savings from more accurate information on status of transformers and distribution lines and when they need to be replaced/repaired

SB-11

¬ Reductions in Unaccounted for Energy (UFE)-CEC and ISO studies have identified significant percentages of total system energy deliveries that cannot be accounted for by retail sales or transmission losses. AMI systems identify the source and solution for these problems and reduce energy costs for all customers.

SB-12

¬ Ability to monitor customer self generation into system on a real time basis

SB-13

¬ Reduction in the amount of time to implement new rates and or load management programs.

Customer Service Benefits

CB-1

¬ Improves billing accuracy - provides solution for inaccessible / difficult to access sites - eliminates "lock-outs"

CB-2

¬ Early detection of meter failures and distribution line stresses can reduce outages and improve customer service

CB-3

¬ May provide additional opportunity to inspect panel, reattachment of unsecured meter boxes, ID any unsafe conditions

CB-4

¬ Improves billing accuracy - reduced estimated reads / estimated billing - reduced exception billing processing

CB-5

¬ Customer energy profiles for EE / DR targeting (marketing)

CB-6

¬ Customer rate choice / new rate options

CB-7

¬ Customized billing date

CB-8

¬ Energy Information to customer can assist in managing loads

CB-9

¬ Enhanced billing options could be a source of revenue and increased customer satisfaction

CB-10

¬ Load Survey- AMI systems allow utilities to perform load surveys remotely and no longer require recruitment and site visits

CB-11

¬ On-line bill presentment with hourly data / more timely and accurate information about electricity / info access

CB-12

¬ Lower customer bills

CB-13

¬ Value to customers of more timely & accurate bills

Demand Response Benefits

DR-1

¬ Procurement cost reduction - deferral of capacity, consumption shift to off-peak and/or reduction, lower net emissions

DR-2

¬ System reliability benefits (capacity buffer)- increased level of dispatchable load reductions could increase effective capacity margin and reduce loss of load probability.

DR-3

¬ Dynamic fuel switching / Dynamic integration of conventional and distributed supplies

DR-4

¬ Avoided / deferred transmission and distribution (T&D) additions / upgrade costs

Management and Other Benefits

MB-1

¬ Reduced equipment and equip maintenance costs (software maintenance & system support, handheld reading devices, uniforms, etc.)

MB-2

¬ Reduced misc. support expenses (including office equipment and supplies)

MB-3

¬ Reduced battery replacement / calendar resets / meter programming

MB-4

¬ Reduced meter inventories / inventory management expenses due to expanded uniformity

MB-5

¬ Summary billing cash flow benefits (existing customers)

MB-6

¬ Possible reduction in "idle usage", meter watt losses - at the very least quicker resolution of idle usage episodes

MB-7

¬ Possible new rev source / new business ventures / new products & srvs/web based interval & power-quality data

MB-8

¬ May facilitate ability to obtain GPS reads during mtr deployment-improving Franchise & Utility Users Tax processes

MB-9

¬ Tariff planning - more flexibility of rate contacts & options within standard customer rate classes / dynamic tariffs

MB-10

¬ Potential for tax savings from federal investment tax credits

(END OF APPENDIX A)

Cost Calculation for a Peaking Turbine to Serve Peak Load

1. $ Fixed costs (levelized) = $85 per kW-year (Reference 1)

2. Operating Costs- Heat rate of 9, 300 Btu/kWh at $5 per MMBtu = 47 $ per MWh (fuel cost) + 16 $ per MWh for variable O&M = 63 $ per MWh. (Reference 1 and 2)

Reference 1- For CT costs see Electricity and Natural Gas Assessment Report, (CEC pub 100-03-001) Appendix D has the specific capital and O&M costs for combustion turbines.

Reference 2- Gas costs http://www.energy.ca.gov/reports/2003-08-08_100-03-006.PDF page 10 assume $ 5 per million Btu (year 2000 $) for natural gas.

Summary: These assessments suggest use of $ 85 per kW year and $ 63 per MWh for cost of peak generation facilities- actual costs will be higher because the costs estimates do not include higher transmission and distribution costs found during most critical peak periods when CPP rates are likely to be called. A conservative estimate to cover this "congestion cost is an additional $7/MWh or .7 cents/kWh resulting in a total on peak energy cost of $70/MWh.

(END OF APPENDIX B)

CERTIFICATE OF SERVICE

I certify that I have by mail, and by electronic mail to the parties to which an electronic mail address has been provided, this day served a true copy of the original attached Administrative Law Judge and Assigned Commissioner's Ruling Adopting a Business Case Analysis Framework for Advanced Metering Infrastructure on all parties of record in this proceeding or their attorneys of record.

Dated July 21, 2004, at San Francisco, California.

/s/ KRIS KELLER

Kris Keller

NOTICE

Parties should notify the Process Office, Public Utilities Commission, 505 Van Ness Avenue, Room 2000, San Francisco, CA 94102, of any change of address to ensure that they continue to receive documents. You must indicate the proceeding number on the service list on which your name appears.

¹¹ For purposes of this parameter average weather is defined as 1 in 2 year weather and hot is a 1 in 10 year weather condition.

¹² These avoided energy and demand cost assumptions should be used in all required scenarios, utilities may develop their own assumptions under the optional cases.

¹³ The analysis should include a section discussing how uncertainty in estimated costs and benefits for the parameters discussed in this Attachment affect the results derived in the scenario analyses by providing examples of the range of benefit and cost values discovered during the uncertainty analysis.

¹⁴ The utilities may develop their own estimates or use the avoided transmission and distribution costs developed by E3 and presented to the Commission (Energy and Environmental Economics, A forecast of Cost Effectiveness, Avoided costs, and Externality Adders: Prepared for Eli Kollman: January 20, 2004). The Report can be downloaded at: http://www.cpuc.ca.gov/static/industry/electric/energy+efficiency/rulemaking/cpucdraft01082004.pdf.)

¹⁵ If considered, these risks must be balanced by consideration of opportunity costs of not proceeding with the AMI system.

C-1	¬ Costs to review and specify systems to ensure physical and logical security, securing data transmission, infrastructure to support security, etc.
C-2	¬ Perform and review site surveys to determine placement of network equipment
C-3	¬ Mapping of network equipment on company facilities (asset facility mapping)
C-4	¬ Staging facilities for WAN/LAN equip and mounting hardware (pre-installation)
C-5	¬ Review and develop strategies to retrieve data from meters and process within billing system

M-1	¬ Buy out of Current SCE- or other utility ITRON Contract for 2000 ERT Deployment (350K meters)
M-2	¬ Meter RFP process and contract finalization and administration

MS-1	¬ Additional temporary meter reading staff for transitional period/mtr reader transition costs
MS-2	¬ Administration of contracts/supervision of installer workforce
MS-3	¬ Cost of purchasing meters, comm modules and related vendor support equipment & software
MS-4	¬ Installation and testing equipment costs (tools, equipment and vehicles)
MS-5	¬ Installation labor (incl workers comp, P&B, payroll taxes, etc.)
MS-6	¬ Meter installation tracking systems (Endpoint Link-other), Meter info/records admin/GPS
MS-7	¬ Panel reconfiguration/replacement costs (A base, other)/Meter socket repairs
MS-8	¬ Potential customer claims related to damages during meter installation and/or panel upgrades
MS-9	¬ Salvage/Disposal process for removed meters
MS-10	¬ Supply chain management including development of staging facilities, shipment & handling of new meters
MS-11	¬ Training (meter installers, handlers, shippers)

C-6	¬ Auxiliary equipment (e.g. remote antennas, isolation transformers, surge protection devices, etc).
C-7	¬ Costs of Pole replacement - to "fit" concentrators
C-8	¬ Development of communications link from meters to data center, LAN/WAN/servers for storage & processing ¬ Development of Internet based usage data communication
C-9	¬ Install costs of Cross arms (e.g. streetlight arms for pole top installations) and other mounting
C-10	¬ Purchase network communications equipment and hardware
C-11	¬ Training for installation of WAN/LAN equipment (including install labor for wireless circuits)

I-2	¬ Computing system implementation in data center (new hardware/software, IT security review & compliance)
I-3	¬ Data center facilities
I-4	¬ Develop and process dynamic rates in CIS billing systems
I-5	¬ New information management software applications
I-6	¬ Records - databases, drawings of field network and data center servers
I-7	¬ Update work management interface to process additional volume of meter changes, data scripts

CU-1	¬ Customer records/billing and collections work associated with roll-out of meter change process
CU-2	¬ Increased call center activity during transition from existing to new rates /meter change appointments
CU-3	¬ Modification and customer support costs for OIS and other system changes
CU-4	¬ Process meter changes for new meter installations and DA accounts

M-3	¬ Customers access to usage information through communications medium
M-4	¬ Employee communications and change management
M-5	¬ Employee training for deployment and O&M of new systems, rate structures, etc.
M-6	¬ Meter reader reroute administration (assuming gas meters are not included - will continue to be read)
M-7	¬ Overall project mgmt costs (and overhead) including customer service, IT and other functions
M-8	¬ Recruiting of incremental workers
M-9	¬ Supervision/overhead of contracts and technology personnel assigned to hardware and systems development
M-10	¬ Training for other traditional classifications (records, call centers, meter readers, T-men, etc)
M-11	¬ Work management tools

GS-1	¬ Gas Index/Module Purchases
GS-2	¬ Purchase/replacement of non-retrofittable gas meters
GS-3	¬ Replacement of gas meter module, battery purchases and replacement labor
GS-4	¬ Warehousing operations for gas modules

MS-12	¬ Cost of Maintaining Existing Metering Systems ¬ Additional costs to O&M/more complex metering & comm infrastructure (labor, tools, equip, vehicles)
MS-13	¬ Pickup reads (remote retrieval not available/possible)
MS-14	¬ Potentially higher meter replacement costs relative to existing mechanical meters (shorter life cycle)

C-12	¬ Cost of Existing communication systems that take data from meters on monthly basis and turn it into bills ¬ Cost of attaching comm. concentrators (e.g., rent or lease charges by cities or other 3rd parties-not owned by utility)
C-13	¬ Costs of contracts to retrieve meter data and services
C-14	¬ Dispatching and O&M of field LAN/WAN and infrastructure equipment
C-15	¬ Electric power consumed by LAN/WAN equipment and/or meter modules

I-8 I-9	¬ Cost of Maintaining Existing hardware and software that translates meter reads to customer bills ¬ Aggregating, validating and creating billing determinant data for electric billing
I-10	¬ Contract administration and database management of public network connections
I-11	¬ Exceptions processing (develop, update, and execute data cleanup routines)
I-12	¬ License and O&M software fees
I-13	¬ Ongoing data storage and handling costs/incl test, QA environments, business continuity, disaster recovery
I-14	¬ Ongoing IT system operations & maintenance (usage, software, internet application)
I-15	¬ Operating costs - retrieval and delivery of mtr, maint & outage information systems data and alarms
I-16	¬ Server replacements (every 3-4 years) for 15 year life cycle

CU-5	¬ Additional rate analysis due to multiple TOU options.
CU-6	¬ Cost of complying w/ regulations - providing alternative safety measures (due to removal of electric mtr readers)
CU-7	¬ Cost of reduced customer safety (meter readers no longer available)
CU-8	¬ Customer education of rate changes/customer communications campaign
CU-9	¬ Customer support for internet based usage data communication
CU-10	¬ Out-bound communications (mass media costs, e.g., print, radio, TV)./CPP or other rate notifications

M-12	¬ Capital financing costs- discuss alternative methods of procuring the equipment or services (such as leasing or outsourcing) reviewed and rejected.
M-13	¬ Cost of increased load during mid-peak and off-peak periods
M-14	¬ Customer acquisition and marketing costs for new tariffs
M-15	¬ Risk contingencies (e.g., technology obsolescence/reliability)¹⁵

GS-5	¬ Aggregation/Validation of monthly/hourly reads for gas billing
GS-6	¬ Cost of complying w/ regulations - providing alternative safety measures (due to removal of gas mtr readers)
GS-7	¬ Energy diversion or safety inspection of service and meter facilities on some periodic basis (currently MRs)
GS-8	¬ Increased O&M on gas meters/modules due to addition of electronic modules
GS-9	¬ Performing atmospheric corrosion inspections (currently performed by meter readers)

SB-1	¬ Reduction in Meter Readers, Mgmt & Admin Support (and associated costs)
SB-2	¬ Field service savings (turn-on's / turn-off's) and lower need for pickup reads
SB-3	¬ Reduced energy theft-May provide ability to ID active accounts for metered accts not being billed, broken meters, wrong multipliers
SB-4	¬ Phone Centers - Reduced FTEs in the long term due to anticipated lower customer call volume (estimated / disputed bills)
SB-5	¬ Possible productivity enhancement / rate changes simplified / possible reprogram rather than meter change
SB-6	¬ Outage management benefits (momentary checking for PG&E)
SB-7	¬ Better meter functionality / equipment modernization
SB-8	¬ Remote service connect / disconnect
SB-9	¬ Meter accuracy- improved and more timely load information could increase forecasting accuracy and reduce resource acquisition costs and reduced customer complaints about faulty meter reads
SB-10	¬ System planning design efficiency- savings from more accurate information on status of transformers and distribution lines and when they need to be replaced/repaired
SB-11	¬ Reductions in Unaccounted for Energy (UFE)-CEC and ISO studies have identified significant percentages of total system energy deliveries that cannot be accounted for by retail sales or transmission losses. AMI systems identify the source and solution for these problems and reduce energy costs for all customers.
SB-12	¬ Ability to monitor customer self generation into system on a real time basis
SB-13	¬ Reduction in the amount of time to implement new rates and or load management programs.

CB-1	¬ Improves billing accuracy - provides solution for inaccessible / difficult to access sites - eliminates "lock-outs"
CB-2	¬ Early detection of meter failures and distribution line stresses can reduce outages and improve customer service
CB-3	¬ May provide additional opportunity to inspect panel, reattachment of unsecured meter boxes, ID any unsafe conditions
CB-4	¬ Improves billing accuracy - reduced estimated reads / estimated billing - reduced exception billing processing
CB-5	¬ Customer energy profiles for EE / DR targeting (marketing)
CB-6	¬ Customer rate choice / new rate options
CB-7	¬ Customized billing date
CB-8	¬ Energy Information to customer can assist in managing loads
CB-9	¬ Enhanced billing options could be a source of revenue and increased customer satisfaction
CB-10	¬ Load Survey- AMI systems allow utilities to perform load surveys remotely and no longer require recruitment and site visits
CB-11	¬ On-line bill presentment with hourly data / more timely and accurate information about electricity / info access
CB-12	¬ Lower customer bills
CB-13	¬ Value to customers of more timely & accurate bills

DR-1	¬ Procurement cost reduction - deferral of capacity, consumption shift to off-peak and/or reduction, lower net emissions
DR-2	¬ System reliability benefits (capacity buffer)- increased level of dispatchable load reductions could increase effective capacity margin and reduce loss of load probability.
DR-3	¬ Dynamic fuel switching / Dynamic integration of conventional and distributed supplies
DR-4	¬ Avoided / deferred transmission and distribution (T&D) additions / upgrade costs

MB-1	¬ Reduced equipment and equip maintenance costs (software maintenance & system support, handheld reading devices, uniforms, etc.)
MB-2	¬ Reduced misc. support expenses (including office equipment and supplies)
MB-3	¬ Reduced battery replacement / calendar resets / meter programming
MB-4	¬ Reduced meter inventories / inventory management expenses due to expanded uniformity
MB-5	¬ Summary billing cash flow benefits (existing customers)
MB-6	¬ Possible reduction in "idle usage", meter watt losses - at the very least quicker resolution of idle usage episodes
MB-7	¬ Possible new rev source / new business ventures / new products & srvs/web based interval & power-quality data
MB-8	¬ May facilitate ability to obtain GPS reads during mtr deployment-improving Franchise & Utility Users Tax processes
MB-9	¬ Tariff planning - more flexibility of rate contacts & options within standard customer rate classes / dynamic tariffs
MB-10	¬ Potential for tax savings from federal investment tax credits