2 Scenarios to be Analyzed

This section describes the scenarios to be analyzed. The Base Case analysis under the current tariffs will establish the baseline for evaluating cost effectiveness of the other scenarios. The scenarios described in this section will each be analyzed under different tariff assumptions, as described in Section 3 (and illustrated in Table 1) to allow for comparison between scenarios.

2.1 Base Case (Business as Usual)

This scenario includes the expected capital and maintenance costs associated with maintaining current metering and communication systems for all customer classes, including planned upgrades to metering and billing systems for the 2006 to 2021 period. Costs should be estimated on an annualized basis for the analysis period wherever possible.

Cost estimates to support the current information technology system used for processing current meter reads and converting them into bills for each cost category should be specified for the Base Case to ensure a fair comparison between the business as usual, partial, and full scale deployment of AMI.

2.2 Partial Deployment

The Partial Deployment analysis should include a description of the functional capabilities of the new meters and supporting network, the AMI rollout options considered by the utility and its rationale for choosing its preferred case. The number of advanced meters to be installed each year by customer class for each Partial Deployment case should be identified, whether the meter will be capable of reading gas usage, and the utility's plans regarding using the new meter to collect gas readings. The criteria used to select the preferred partial deployment case (for example, contiguous neighborhoods with high "meter density", identification of zones or areas with high potential for price responsive demand, etc.) should be explicitly identified. This case should explicitly identify the costs of the billing system(s) needed to bill customers with the new meters and those customers that remain on the old meter system and integration of the two systems.

To facilitate the Commission's understanding of the implications of the preferred Partial Deployment cases (and options considered but eliminated), each utility should also separate the costs in its analysis into:

1. Start-up and design costs (design, contracting, training, hiring temporary installation crews, etc.)

2. Installation costs (purchase and installation of advanced meters, installation and testing at customer premise and system headquarters, new software, communications networks, etc.)

3. Operations and maintenance costs (cost of reading meters, translating data to bills, sending bills out and managing the network, etc.)

Appendix A separates the potential cost categories provided by the Working Group subcommittee into the above three categories. The categories listed in Appendix A generally correspond to those found in Appendices C and D of the Staff Report, but some terms have been reworded to clarify the meaning of the language in the subcommittee report. In addition, additional cost and benefit categories have been added that were not originally included in the subcommittee report.3

The Partial Deployment case assumptions should be used to review the different AMI utilization scenarios as described below.

2.2.1 Operational Scenario

This scenario assumes that no new tariffs are established as a result of the partial deployment of AMI, so costs and benefits that derive from the rollout of new tariffs are excluded in this case. The cost categories4 that must be analyzed in the Partial Deployment Operational Scenario are:

The benefit categories5 that must be analyzed in the Partial Deployment Operational Scenario are:

· Systems Operation Benefits

· Customer Service Benefits (all except CB-6)

· Management and Other Benefits (all except MB-7 and MB-9)

Two different financing/implementation approaches should be analyzed and reported for the Partial Deployment Operational Scenario: (1) internal financing/implementation and (2) outsourcing. In the internal financing/implementation analysis, costs of AMI acquisition and installation are considered conventional assets owned by the utility and included in rate base with ongoing operation and maintenance provided in-house or by third parties. In the outsourcing analysis, AMI acquisition, installation, and operations and maintenance are obtained under contract, through leasing agreements, limited partnerships or other business arrangements with third party providers. Contractual arrangements determine the tax implications and whether the AMI asset and related implementation costs are rate based or treated as an operating expense.

2.2.2 Demand Response Scenario

This scenario assumes that new tariffs are established as a result of the partial deployment of AMI, so costs and benefits that derive from the rollout of a specified set of new tariffs are included in this scenario.6 The Partial Deployment Demand Response Scenario includes all of the potential costs and benefits from the Operational Scenario as well as all categories listed in Appendix A that result from implementing the specified new tariffs for customers expected to receive new meters under the partial deployment scenario from the utility and societal perspectives. This scenario should explicitly describe the financing approach for any new metering, billing, or communications equipment necessary to support the partial deployment.

2.2.3 Demand Response + Reliability Scenario

This scenario assumes that the AMI systems installed in a partial deployment scenario are actively utilized to manage peak loads during times when reserve margins shrink to unacceptable levels, and to help restore power more quickly to customers in the event of temporary loss of power or rolling blackouts. This active utilization comes from the installation and use of automated control technology at the customer level to achieve reliability benefits. This analysis should allow assessment of whether deployment of AMI coupled with active use of automated control technology and price differentiated tariffs provides value by reducing the probability that rolling blackouts will be required in emergency situations.

The Partial Deployment Demand Response + Reliability Scenario includes the costs and benefits described in the Partial Deployment Demand Response Scenario plus the costs of any additional control and communication systems necessary to automatically reduce the load of customers who have agreed to a predetermined peak load reduction (of 10- 20%) during emergency conditions. This scenario should explicitly describe the financing approach for any new metering, billing, or communications equipment necessary to support the partial deployment and whether the controls to ensure load reduction would be utility or customer financed.

As shown on Table 1, the utilities need only perform the analysis on two tariff structures for this case, both analyses are for optional tariff structures. Section 3 describes how to develop estimates of costs and benefits for these tariffs.

2.3 Full Deployment

Analysis of the Full Deployment scenarios should include a description of the functional capabilities of the new meters and supporting network, the AMI rollout options considered by the utility and its rationale for choosing its preferred case. The number of advanced meters to be installed each year by customer class for each Full Deployment case should be identified, whether the meter will be capable of reading gas usage, and the utility's plans regarding using the new meter to collect gas readings. The criteria used to select the preferred deployment schedule should be explicitly identified as well as the fraction of customers who would not be reached under the preferred case. In no event should the deployment schedule exceed five years or reach less than 90% of the utility's customer base. The analysis should include all costs associated with meter testing, beta testing of software interfaces between systems, and any other quality control milestones necessary during the transition period before AMI is fully deployed and integrated into the network.

To facilitate the Commission's understanding of the implications of the preferred Full Deployment case each utility should separate costs in its analysis into:

1. Start-up and design costs (design, contracting, training, hiring temporary installation crews, etc.)

2. Installation costs (purchase and installation of advanced meters, installation and testing at customer premise and system headquarters, new software, communications networks, etc.)

3. Operations and maintenance costs (cost of reading meters, translating data to bills, sending bills out and managing the network, etc.)

Appendix A separates the potential cost categories provided by the Working Group subcommittee into the above three categories. The categories listed in Appendix A generally correspond to those found in Appendices C and D of the Staff Report, but some terms have been reworded to clarify the meaning of the language in the subcommittee report. In addition, additional cost and benefit categories have been added that were not originally included in the subcommittee report.

The Full Deployment case assumptions should be used to review three different AMI utilization scenarios as described below.

2.3.1 Operational Scenario

This scenario assumes that no new tariffs are established as a result of the full deployment of AMI, so costs and benefits that derive from the rollout of new tariffs are excluded in this case. The cost categories7 that must be analyzed in the Full Deployment Operational Case are:

The benefit categories8 that must be analyzed in the Full Deployment Operational Case are:

· Systems Operation Benefits

· Customer Service Benefits (all except CB-6)

· Management and Other Benefits (all except MB-7 and MB-9)

The same two financing/implementation approaches analyzed and reported for the Partial Deployment Operational Scenario should also be performed for the Full Deployment Operational Scenario.

2.3.2 Demand Response Scenario

This scenario assumes that new tariffs are established as a result of the full deployment of AMI, so costs and benefits that derive from the rollout of a specified set of new tariffs are included in this scenario.9 The Full Deployment Demand Response Scenario includes all of the potential costs and benefits from the Operational Scenario as well as all categories listed in Appendix A that result from implementing the specified new tariffs for customers expected to receive new meters under the full deployment scenario from the utility and societal perspectives. This scenario should explicitly describe its financing approach assumptions.

2.3.3 Demand Response + Reliability Scenario

This scenario assumes that the AMI systems installed in a full deployment scenario are actively utilized to manage peak loads during times when reserve margins shrink to unacceptable levels, and to help restore power more quickly to customers in the event of temporary loss of power or rolling blackouts. This active utilization comes from the installation and use of automated control technology to achieve reliability benefits. This analysis should allow assessment of whether deployment of AMI coupled with active use of automated control technology and price differentiated tariffs provides value by reducing the probability that rolling blackouts will be required in emergency situations.

The Full Deployment Demand Response + Reliability Scenario includes the costs and benefits described in the Full Deployment Demand Response Scenario plus the costs of any additional control and communication systems necessary to automatically reduce the load of customers who have agreed to a predetermined peak load reduction (of 10- 20%) during emergency conditions. This scenario should explicitly describe the financing approach used to procure the customer control equipment.

As shown on Table 1, the utilities need only perform the analysis on two tariff structures for this case. Section 3 describes how to develop estimates of costs and benefits for these tariffs.

Advanced Metering Infrastructure Business Cases to be Analyzed

    
             
 

Tariff Assumptions

          
 

Current

Time-of-Use (two period)

Critical Peak Pricing- Fixed, Variable, RTP*

Current

Current

Utility Preferred

 

n/a

Current or CPP-F

Current or TOU

Critical Peak Pricing- Pure^

CPP-F or CPP-V

  

Case Assumptions

            

Base Case

X

          
             

Partial Deployment

            

Operational- Conventional Financing

X

          

Operational- Outsourced Financing

X

          

Demand Response

  

X#

X#

X

X

O

Demand Response + Reliability

      

X

X#

O

             

Full Deployment

            

Operational- Conventional Financing

X

        

O

Operational- Outsourced Financing

X

        

O

Demand Response

  

X

X

X

X

O

Demand Response + Reliability

    

X

X

  

O

Cases Required

5

2

3

4

3

  

Total Cases

17

          
   

Default Tariff

        
   

Optional Tariff Choices

      
 

*

Default Tariff based on customer type/size.

    
 

^

Customers electing to receive CPP-Pure would receive a discount on off-peak rates to compensate for CPP exposure.

  
 

#

Utilities should discuss the feasibility of implementing a new default tariff to some portions of a customer class in a partial deployment scenario.

  

3 This report was drafted by a subcommittee of WG 3 members including David Hungerford, CEC, Tim Vahlstrom, PG&E, Jana Corey, PG&E, Paul Kasick, SCE (by phone), Doug Kim, SCE, Jeff Nahigian, TURN, Tanya Guleserian, CUE, Ward Camp, DCSI, Chris King, CCEA, and JC Martin, SDG&E .
4 References are to Appendix A.
5 References are to Appendix A.
6 The minimum set of tariffs to be offered are listed in Section 3 below.
7 References are to Appendix A.
8 References are to Appendix A.
9 The minimum set of tariffs to be offered are listed in Section 3 below.

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