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DECEMBER 2010 WORKPAPERS TO PREPARED DIRECT

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DECEMBER 2010 WORKPAPERS TO PREPARED DIRECT Powered By Docstoc
					Application of SAN DIEGO GAS & ELECTRIC                )
COMPANY for authority to update its gas and electric   )
revenue requirement and base rates                     )
effective January 1, 2012  (U 902-M)                   )



Application No. 10-12-___
Exhibit No.: (SDG&E-14-WP)




                                        WORKPAPERS TO
                               PREPARED DIRECT TESTIMONY

                                        OF STEVE RAHON

               ON BEHALF OF SAN DIEGO GAS & ELECTRIC COMPANY




                      BEFORE THE PUBLIC UTILITIES COMMISSION

                               OF THE STATE OF CALIFORNIA



                                         DECEMBER 2010
Application of SAN DIEGO GAS & ELECTRIC                )
COMPANY for authority to update its gas and electric   )
revenue requirement and base rates                     )
effective January 1, 2012  (U 902-M)                   )



Application No. 10-12-___
Exhibit No.: (SDG&E-14-WP)




                                        WORKPAPERS TO
                               PREPARED DIRECT TESTIMONY

                                        OF STEVE RAHON

               ON BEHALF OF SAN DIEGO GAS & ELECTRIC COMPANY




                      BEFORE THE PUBLIC UTILITIES COMMISSION

                               OF THE STATE OF CALIFORNIA



                                         DECEMBER 2010
                                            2012 General Rate Case - APP
                                           INDEX OF WORKPAPERS


                             Exhibit SDG&E-14 - CS - OFFICE OPERATIONS

DOCUMENT                                                                   PAGE




Overall Summary For Exhibit No. SDG&E-14                                     1

Summary of Non-Shared Services Workpapers                                    2
Category: A. Billing Services                                                3
..1OO000.000 - BILLING SERVICES                                              4
Category: B. Office Credit & Collections                                   192
..1OO002.000 - OFFICE CREDIT & COLLECTIONS                                 193
Category: C. Bill Delivery                                                 236
..1OO003.000 - BILL DELIVERY                                               237
..1OO003.001 - BILL DELIVERY - POSTAGE                                     242
Category: D. CS Technology Support                                         254
..1OO004.000 - CS TECHNOLOGY SUPPORT                                       255
Category: E. CS Operations Other                                           262
..1OO005.000 - CS OPERATIONS OTHER                                         263


Summary of Shared Services Workpapers                                      278
Category: A. SOX Project Management                                        279
..2100-3476.000 - SOX PROJECT MANAGEMENT                                   280
Category: B. Director of CS Technology Support                             288
..2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT                           289
..2100-0642.000 - CS TECHNOLOGY MANAGER                                    299
..2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS                              313
Category: C. Business Planning & Budgets                                   324
..2100-3461.000 - BUSINESS PLANNING & BUDGETS                              325
Category: D. Director of Market Services                                   333
..2100-0006.000 - DIRECTOR OF MARKET SERVICES                              334
Category: E. Billed-in from SCG                                            367
..2100-8911.000 - BILLED-IN COST CENTER FOR CS OFFICE OPERATIONS           368


Appendix A: List of Non-Shared Cost Centers                                375
                                        San Diego Gas & Electric Company
                                           Test Year 2012 GRC - APP




Overall Summary For Exhibit No. SDG&E-14

                             Area:          CS - OFFICE OPERATIONS
                             Witness:       Rahon, J Steve


                                                                    In 2009 $ (000)
                              Adjusted-Recorded                               Adjusted-Forecast
Description                          2009                    2010                     2011        2012
Non-Shared Services                     15,658                 15,542                   16,158      17,967

Shared Services                          2,986                  3,885                    4,242       4,663

Total                                   18,644                 19,427                   20,400      22,630




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 1 of 375
                                        San Diego Gas & Electric Company
                                           Test Year 2012 GRC - APP
                                         Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve



Summary of Non-Shared Services Workpapers:
                                                                      In 2009 $ (000)
                                                   Adjusted-
                                                                             Adjusted-Forecast
                                                   Recorded
Description                                          2009          2010               2011       2012
A. Billing Services                                    4,142         4,333               4,415     5,115
B. Office Credit & Collections                         2,331         2,597               2,751     2,776
C. Bill Delivery                                       6,491         6,454               6,480     6,546
D. CS Technology Support                               1,071           694               1,048     1,048
E. CS Operations Other                                 1,623         1,464               1,464     2,482
Total                                                 15,658        15,542              16,158    17,967




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                               Pages 2 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                            Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                A. Billing Services
Workpaper:               1OO000.000

Summary for Category: A. Billing Services

                                                             In 2009$ (000)
                                 Adjusted-Recorded                        Adjusted-Forecast
                                    2009                   2010               2011            2012
             Labor                    3,936                 4,086               4,164            4,854
             Non-Labor                  206                  247                  251                261
             NSE                            0                     0                  0                 0
               Total                  4,142                 4,333               4,415            5,115
               FTE                     65.1                  69.5                70.5                78.5

   Workpapers belonging to this Category:
    1OO000.000 BILLING SERVICES
         Labor                       3,936                  4,086              4,164             4,854
         Non-Labor                     206                    247                251               261
         NSE                             0                      0                  0                 0
            Total                    4,142                  4,333              4,415             5,115
            FTE                       65.1                   69.5               70.5              78.5




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 3 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                   Non-Shared Service Workpapers




                 Beginning of Workpaper
              1OO000.000 - BILLING SERVICES




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                         Pages 4 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                              Non-Shared Service Workpapers


Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               A. Billing Services
Category-Sub            1. CS Operations-Billing Services
Workpaper:              1OO000.000 - BILLING SERVICES

Activity Description:
               Customer billing operations major activities include issuance of special bills that
               require manual calculations, resolution of billing exceptions, addressing customer bill
               inquiries and other billing exception processing. Billing operations support staff
               implement bill and rate changes. Billing operations manages the bill process for
               residential, small and large commercial customers providing support for the implementation of
               new systems that support new billing rates as well as exceptions to the current billing process.
               Contracts and Compliance's primary purpose is to manage the mission-critical processes,
               policies, procedures and quality controls that ensure that bills are prepared in accordance with
               applicable tariffs, statutes, customer contracts and other agreements.
Forecast Methodology:

        Labor - 5-YR Average
               Work volumes in Billing are driven by fluctuations in customer usage, increased complexities
               due to new rates and programs, and automation and business process improvements. For
               these reasons it is logical to project the base future expense by using a five year historical
               average to encompass the fluctuations in work flow volumes over a reasonable timeframe.
        Non-Labor - 5-YR Average
              Work volumes in Billing are driven by fluctuations in customer usage, increased complexities
              due to new rates and programs, and automation and business process improvements. For
              these reasons it is logical to project the base future expense by using a five year historical
              average to encompass the fluctuations in work flow volumes over a reasonable timeframe.
        NSE - 5-YR Average
               N/A


Summary of Results:

                                                                 In 2009$ (000)
                                        Adjusted-Recorded                                     Adjusted-Forecast
Years                     2005        2006        2007         2008        2009           2010         2011       2012
Labor                    3,440       3,524       3,671        3,750       3,936          4,086        4,164       4,854
Non-Labor                  235         274         277          225         206            247          251        261
NSE                          0           0           0            0           0              0            0         0
   Total                 3,675       3,798       3,948        3,975       4,142          4,333        4,415       5,115
   FTE                    64.4        63.3        63.5         63.7        65.1           69.5         70.5        78.5




                    SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 5 of 375
                                                San Diego Gas & Electric Company
                                                   Test Year 2012 GRC - APP
                                                 Non-Shared Service Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 A. Billing Services
Category-Sub:             1. CS Operations-Billing Services
Workpaper:                1OO000.000 - BILLING SERVICES

Forecast Summary:
                                                                       In 2009 $(000)
     Forecast Method                      Base Forecast                  Forecast Adjustments             Adjusted-Forecast
                                       2010         2011     2012       2010       2011    2012          2010     2011        2012
 Labor              5-YR Average       3,664        3,664   3,664        422       500     1,190         4,086    4,164   4,854
 Non-Labor          5-YR Average        243           243        243           4     8        18          247      251        261
 NSE                5-YR Average          0             0          0           0     0          0           0         0         0
 Total                                 3,907        3,907   3,907        426       508     1,208         4,333    4,415   5,115
 FTE                5-YR Average        64.0         64.0    64.0         5.5       6.5     14.5          69.5     70.5       78.5


Forecast Adjustment Details:
       Year/Expl.           Labor              NLbr         NSE        Total        FTE    Adj_Type

         2010                   43              0            0           43          0.0   1-Sided Adj

           1 FTE @ AS5 to support growth in Net Metering customers and expanded renewable
           programs.

         2010                      0            2            0            2          0.0   1-Sided Adj

           Non Labor to support 1 FTE for Net Metering.

         2010                      0            0            0            0          1.0   1-Sided Adj

           1 FTE @ AS5 to support growth in Net Metering Customers and expanded renewable
           programs.

         2010                   94              0            0           94          0.0   1-Sided Adj

           0.5 FTE to support the re-opening of Direct Access (DA SB695), 0.5 FTE for mapping and
           climate zone update and1 full FTE for RTO.

         2010                      0            0            0            0          2.0   1-Sided Adj

           0.5 FTE to support the re-opening of Direct Access (DA SB695), 0.5 FTE for mapping and
           climate zone update and1 full FTE for RTO.

         2010                      0            1            0            1          0.0   1-Sided Adj

           Non Labor in support of 1.5 FTE's for the re-opening of DA and RTO.

         2010                  -81              0            0          -81          0.0   1-Sided Adj

           Smart Meter benefits realized related to fewer re-bills and the elimination of meter read
           exceptions. Figures based on Smart Meter business case original assumptions to actual
           deployment schedule for 2010.




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                               Pages 6 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                            Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             A. Billing Services
Category-Sub:         1. CS Operations-Billing Services
Workpaper:            1OO000.000 - BILLING SERVICES

      Year/Expl.        Labor           NLbr       NSE         Total          FTE   Adj Type

      2010                    0             0            0             0         -2.0   1-Sided Adj

         Smart Meter benefits realized related to fewer re-bills and the elimination of meter read
         exceptions. Figures based on Smart Meter business case original assumptions to actual
         deployment schedule for 2010.

      2010                 366              0            0         366           0.0    1-Sided Adj

         Salary releveling, full year impact salaries for 2009, and FTE adds for Contract and
         Compliance, Billing Ops support, Project Manager in Director cost center, and Project Advisor
         in Mass Market Billing.

      2010                    0             0            0             0         4.5    1-Sided Adj

         Salary releveling, full year impact salaries for 2009, and FTE adds for Contract and
         Compliance, Billing Ops support, Project Manager in Director cost center, and Project Advisor
         in Mass Market Billing.

      2010                    0             1            0             1         0.0    1-Sided Adj

         Non Labor in support of FTE adds for Contract and Compliance, Billing Ops support, Project
         Manager in Director cost center, and Project Advisor in Mass Market Billing.

      2010 Total           422              4            0         426           5.5




      2011                   86             0            0          86           0.0    1-Sided Adj

         2 FTE's (one in 2010 and one in 2011) to support growth in Net Metering customers and
         expanded renewable programs.

      2011                    0             0            0             0         2.0    1-Sided Adj

         2 FTE's (one in 2010 and one in 2011) to support growth in Net Metering customers and
         expanded renewable programs.

      2011                    0             4            0             4         0.0    1-Sided Adj

         Non labor to support growth in Net Metering customers and expanded renewable programs.

      2011                 212              0            0         212           0.0    1-Sided Adj

         1 FTE to support the re-opening of DA, 1 FTE for RTO, 0.5 FTE for Street Lighting, and 1
         FTE in contracts and compliance to reach desired level of compliance and business controls.

      2011                    0             0            0             0         3.5    1-Sided Adj




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                            Pages 7 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             A. Billing Services
Category-Sub:         1. CS Operations-Billing Services
Workpaper:            1OO000.000 - BILLING SERVICES

      Year/Expl.        Labor          NLbr       NSE          Total         FTE     Adj Type
         1 FTE to support the re-opening of DA, 1 FTE for RTO, 0.5 FTE for Street Lighting, and 1
         FTE in contracts and compliance to reach desired level of compliance and business controls.

      2011                    0            2            0              2         0.0   1-Sided Adj

         Non labor in support of 1 FTE to support the re-opening of DA, 1 FTE for RTO, 0.5 FTE for
         Street Lighting, and 1 FTE in contracts and compliance to reach desired level of compliance
         and business controls.

      2011                -199             0            0         -199           0.0   1-Sided Adj

         Smart Meter benefits realized related to fewer re-bills and the elimination of meter read
         exceptions. Figures based on Smart Meter business case assumptions against 2011 actual
         deployment schedule.

      2011                    0            0            0              0        -4.0   1-Sided Adj

         Smart Meter benefits realized related to fewer re-bills and the elimination of meter read
         exceptions. Figures based on Smart Meter business case assumptions against 2011 actual
         deployment schedule.

      2011                 401             0            0         401            0.0   1-Sided Adj

         Salary releveling, full year impact salaries for 2009, and FTE adds for Contract and
         Compliance, Billing Ops support, Project Manager in Director cost center, and Project Advisor
         in Mass Market Billing.

      2011                    0            0            0              0         5.0   1-Sided Adj

         Salary releveling, full year impact salaries for 2009, and FTE adds for Contract and
         Compliance, Billing Ops support, Project Manager in Director cost center, and Project Advisor
         in Mass Market Billing.

      2011                    0            2            0              2         0.0   1-Sided Adj

         Non Labor in support of 5.1 FTE adds for Contract and Compliance, Billing Ops support,
         Project Manager in Director cost center, and Project Advisor in Mass Market Billing.

      2011 Total           500             8            0         508            6.5




      2012                 247             0            0         247            0.0   1-Sided Adj

         5.5 FTE add for complex billing and rates supported in AMI business case 5.5 X $45K

      2012                    0            0            0              0         6.0   1-Sided Adj

         6.0 FTE add for complex billing and rates supported in AMI business case.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                            Pages 8 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                            Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             A. Billing Services
Category-Sub:         1. CS Operations-Billing Services
Workpaper:            1OO000.000 - BILLING SERVICES

      Year/Expl.        Labor           NLbr        NSE         Total          FTE    Adj Type

      2012                  129             0             0         129            0.0   1-Sided Adj

         3 FTE's @ (1 in 2010, 1 in 2011 and 1 in 2012) to support growth in Net Metering customers
         and expanded renewable programs.

      2012                    0             0             0             0          3.0   1-Sided Adj

         3 FTE's (1 in 2010, 1 in 2011 and 1 in 2012) to support growth in Net Metering customers and
         expanded renewable programs.

      2012                    0             6             0             6          0.0   1-Sided Adj

         Non Labor in support of 3 FTE's (1 in 2010, 1 in 2011 and 1 in 2012) to support growth in Net
         Metering customers and expanded renewable programs.

      2012                  187             0             0         187            0.0   1-Sided Adj

         1 FTE to support the re-opening of DA, 1 FTE for RTO, and 1 FTE in contracts and
         compliance to reach desired level of compliance and business controls.

      2012                    0             0             0             0          3.0   1-Sided Adj

         1 FTE to support the re-opening of DA, 1 FTE for RTO, and 1 FTE in contracts and
         compliance to reach desired level of compliance and business controls.

      2012                    0             2             0             2          0.0   1-Sided Adj

         Non labor to support 1 FTE to support the re-opening of DA, 1 FTE for RTO, and 1 FTE in
         contracts and compliance to reach desired level of compliance and business controls.

      2012                  154             0             0         154            0.0   1-Sided Adj

         Salary increase required above inflation will be required to attract/retain employees for more
         analytical assignments. 19.4% increase to impacted employees.

      2012                 -262             0             0        -262            0.0   1-Sided Adj

         Smart Meter benefits realized related to fewer re-bills and the elimination of meter read
         exceptions. Figures based on Smart Meter business case assumptions against 2012 actual
         deployment schedule.

      2012                    0             0             0             0         -6.3   1-Sided Adj

         Smart Meter benefits realized related to fewer re-bills and the elimination of meter read
         exceptions. Figures based on Smart Meter business case assumptions against 2012 actual
         deployment schedule.

      2012                  735             0             0         735            0.0   1-Sided Adj




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                            Pages 9 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             A. Billing Services
Category-Sub:         1. CS Operations-Billing Services
Workpaper:            1OO000.000 - BILLING SERVICES

      Year/Expl.        Labor          NLbr       NSE          Total         FTE    Adj Type
         Salary releveling, full year impact salaries for 2009, and FTE adds for Contract and
         Compliance, Billing Ops support, Project Manager in Director cost center, and Project Advisor
         in Mass Market Billing and 4 employees currently providing support to the Smart Meter
         project will be brought back to Billing Ops Support to provide maintenance on the system.

      2012                    0            0            0              0         8.8   1-Sided Adj

         Salary releveling, full year impact salaries for 2009, and FTE adds for Contract and
         Compliance, Billing Ops support, Project Manager in Director cost center, and Project Advisor
         in Mass Market Billing and 4 employees currently providing support to the Smart Meter
         project will be brought back to Billing Ops Support to provide maintenance on the system.

      2012                    0           10            0           10           0.0   1-Sided Adj

         Non Labor in support of FTE adds for Contract and Compliance, Billing Ops support, Project
         Manager in Director cost center, and Project Advisor in Mass Market Billing and 4 employees
         currently providing support to the Smart Meter project will be brought back to Billing Ops
         Support to provide maintenance on the system.

      2012 Total         1,190            18            0        1,208         14.5




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 10 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               A. Billing Services
Category-Sub:           1. CS Operations-Billing Services
Workpaper:              1OO000.000 - BILLING SERVICES

Determination of Adjusted-Recorded:
                                2005 ($000)              2006 ($000)         2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                               2,686                2,790              3,013          3,143        3,410
     Non-Labor                             204                  248                262            225          206
     NSE                                     0                    0                  0              0            0
         Total                           2,889                3,039              3,275          3,369        3,615
         FTE                              55.4                 54.2               54.3           54.0         55.8
  Adjustments (Nominal $) **
     Labor                                   0                     0                 0             -3            0
     Non-Labor                               0                     0                -1              0            0
     NSE                                     0                     0                 0              0            0
         Total                               0                     0                -2             -3            0
         FTE                               0.0                   0.0               0.0            0.0          0.0
  Recorded-Adjusted (Nominal $)
     Labor                               2,686                2,790              3,012          3,140        3,410
     Non-Labor                             204                  248                261            225          206
     NSE                                     0                    0                  0              0            0
          Total                          2,889                3,039              3,273          3,366        3,615
          FTE                             55.4                 54.2               54.3           54.0         55.8
  Vacation & Sick (Nominal $)
     Labor                                 388                  448                452            517          526
     Non-Labor                                0                    0                  0              0            0
     NSE                                      0                    0                  0              0            0
          Total                            388                  448                452            517          526
          FTE                               9.0                  9.1                9.2            9.7          9.3
  Escalation to 2009$
     Labor                                 367                  285                207             93            0
     Non-Labor                               32                   25                 16             0            0
     NSE                                      0                    0                  0             0            0
         Total                             399                  311                223             92            0
         FTE                                0.0                  0.0                0.0           0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                               3,440                3,524              3,671          3,750        3,936
     Non-Labor                             235                  274                277            225          206
     NSE                                     0                    0                  0              0            0
         Total                           3,675                3,798              3,948          3,975        4,142
         FTE                              64.4                 63.3               63.5           63.7         65.1



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 11 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               A. Billing Services
Category-Sub:           1. CS Operations-Billing Services
Workpaper:              1OO000.000 - BILLING SERVICES


Summary of Adjustments to Recorded:

                                                              In Nominal $ (000)
 Year                                    2005             2006              2007       2008            2009
    Labor                                  0                 0            -0.260         -3               0
    Non-Labor                              0                 0                -1         0                0
    NSE                                    0                 0                   0       0                0
        Total                              0                 0                -2         -3               0
    FTE                                   0.0              0.0               0.0        0.0             0.0


Detail of Adjustments to Recorded:

Year/Expl.      Labor         NLbr        NSE       FTE      Adj_Type      From CCtr          RefID

2005 Total           0               0          0   0.0



2006 Total           0               0          0   0.0



2007                 0        -0.079            0   0.0 1-Sided Adj        N/A                  SDALEY2009092
                                                                                                   9070338460
   CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2007                 0            -1            0   0.0 1-Sided Adj        N/A                  SDALEY2009092
                                                                                                   9070508930
   CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2007            -0.260               0          0   0.0 1-Sided Adj        N/A                  SDALEY2009092
                                                                                                   9071511490
   CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2007 Total      -0.260            -1            0   0.0



2008                -2               0          0   0.0 1-Sided Adj        N/A                  SDALEY2009092
                                                                                                   9070623027
   CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2008                -1               0          0   0.0 1-Sided Adj        N/A                  SDALEY2009092
                                                                                                   9070724137
   CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2008 Total          -3               0          0   0.0




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 12 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                            Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               A. Billing Services
Category-Sub:           1. CS Operations-Billing Services
Workpaper:              1OO000.000 - BILLING SERVICES


Year/Expl.      Labor         NLbr        NSE      FTE      Adj Type     From CCtr   RefID

2009 Total          0              0         0     0.0




                 SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                         Pages 13 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                   Non-Shared Service Workpapers




     Supplemental Workpapers for Workpaper 1OO000.000




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 14 of 375
                              San Diego Gas & Electric Company
                                 Test Year 2012 GRC - APP
                               Non-Shared Service Workpapers




      ALJ/TRP/jt2                                Date of Issuance 3/15/2010


      Decision 10-03-022 March 11, 2010

       BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

      Rulemaking regarding whether, or subject to
      what Conditions, the suspension of Direct         Rulemaking 07-05-025
      Access may be lifted consistent with Assembly      (Filed May 24, 2007)
      Bill 1X and Decision 01-09-060.


                      DECISION REGARDING INCREASED LIMITS
                        FOR DIRECT ACCESS TRANSACTIONS




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                                                          Table of Contents

                Title                                                                                                                Page

         DECISION REGARDING INCREASED LIMITS FOR DIRECT ACCESS
         TRANSACTIONS............................................................................................................ 1
          1. Summary .................................................................................................................. 2
          2. Background.............................................................................................................. 3
          3. Authorized Increases for Direct Access Cap ...................................................... 6
             3.1. Discussion....................................................................................................... 8
          4. Phase-In Schedule for Increased Cap................................................................. 10
             4.1. Parties’ Positions ......................................................................................... 10
             4.2. Discussion..................................................................................................... 13
          5. Process to Implement New DA Enrollments.................................................... 15
             5.1. Parties’ Positions ......................................................................................... 15
             5.2. Discussion..................................................................................................... 17
          6. Waiver of DA Switching and Notice Rules
             and Subsequent Rights to Acquire DA.............................................................. 19
             6.1. Parties’ Positions ......................................................................................... 19
             6.2. Discussion..................................................................................................... 22
          7. Meter Installation Waiver .................................................................................... 23
             7.1. Parties’ Positions ......................................................................................... 23
             7.2. Discussion..................................................................................................... 24
          8. Compliance with Procurement and Resource Planning Rules ...................... 25
             8.1. Parties’ Positions ......................................................................................... 26
             8.2. Discussion..................................................................................................... 28
          9. Categorization and Assignment of Proceeding ............................................... 30
         10. Comments on Proposed Decision ...................................................................... 30
         Findings of Fact ............................................................................................................. 31
         Conclusions of Law....................................................................................................... 32
         ORDER ........................................................................................................................... 34

        Appendix 1 – Authorized Increases in Caps on Direct Access Transaction by
        Service Territory
        Appendix 2 – Adopted Enrollment Procedures for the Phase-In Period
        Appendix 3 – Adopted Temporary Treatment for Local Resource Adequacy
        Obligations During Direct Access Reopening



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                          DECISION REGARDING INCREASED LIMITS
                            FOR DIRECT ACCESS TRANSACTIONS

         1.     Summary
                By this decision, we authorize and implement a plan for increased limits in
         the allowed level of direct access (DA) transactions within the service territories
         of California’s three major investor-owned electric utilities: Pacific Gas and
         Electric Company, Southern California Edison Company, and San Diego Gas &
         Electric.
                The authorization for increased limits in DA transactions is implemented
         in accordance with the provisions of Senate Bill (SB) 695 (Stats. 2009, ch. 337).
         Among other issues, SB 695 amends the previously effective suspension of DA,
         and requires the Commission to authorize increases in the maximum kilowatt-
         hour limit on DA transactions. Effective April 11, 2010, all qualifying customers
         will be eligible to take DA service, up to the new maximum cap subject to the
         conditions as set forth herein. The increased DA allowances shall be phased in
         over a four-year period, subject to annual caps in the maximum DA increase
         allowed each year. DA remains suspended, except as provided by this decision
         implementing SB 695. Existing rules and processes currently in place for DA
         service shall remain in place, except for changes specified herein as necessary to
         implement the provisions of SB 695.
                This decision only addresses those implementation issues that must be
         resolved in order to begin the process of new enrollments of DA load effective
         April 11, 2010. Additional issues that relate to SB 695 implementation will be
         addressed expeditiously in a subsequent decision.




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         2.    Background
               Through direct access (DA), eligible retail customers have the choice to
         purchase electric power directly from an independent electric service provider
         (ESP) rather than only through an investor-owned utility (IOU). DA was first
         instituted as an option for retail electric service in 1998, as part of an industry
         restructuring program to bring retail competition to California electric power
         markets.1
               The electric industry restructuring program was cut short, however, by the
         events of 2000-2001 which led to extraordinary wholesale power cost increases,
         threatening the solvency of California’s major electric utilities and the reliability
         of electric service. On February 1, 2001, AB 1 from the First Extraordinary
         Session (Ch. 4, First Extraordinary Session 2001) (AB1X) was signed into law,
         implementing measures to address the energy crisis. Among other measures,
         AB1X required the California Department of Water Resources (DWR) to procure
         electric power supplies sufficient to meet the net short for customers of the
         IOUs.2
               DWR formally began procuring electric power for customers in the service
         territories of the three major IOUs in early 2001. AB1X authorized DWR to
         recover its power costs from electric charges established by the Commission.
         (Water Code § 80110.)



         1 See Decision (D.) 95-12-063, as modified by D.96-01-009 (1995) 64 Cal. PUC 2d 1, 24
         (Preferred Policy Decision). The Legislature codified the Preferred Policy Decision in
         Assembly Bill (AB) 1890 (Stats. 1996, ch. 854) (AB 1890).
         2 The net short is the difference between customer loads and the power already under
         contract to the utilities or generated from a utility-owned asset.




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                To ensure that DWR procurement costs were assigned fairly and
        recovered from a stable customer base, the Legislature, among other measures,
        suspended the DA program. Pursuant to AB1X, the Commission suspended the
        right to enter into new contracts for DA after September 20, 2001,3 permitting no
        new DA contracts, but allowing preexisting contracts to continue in effect. The
        Commission opened this proceeding to investigate conditions whereby DA may
        be reinstituted in the future, although the suspension has continued in effect up
        until the present time.
                On October 11, 2009, Senate Bill (SB) 695 was signed into law as an
        urgency statute. SB 695 adds Section 365.1 (b) to the Public Utilities Code, which
        states in pertinent part:
                The commission shall allow individual retail nonresidential end-use
                customers to acquire electric service from other providers in each
                electrical corporation’s distribution service territory, up to a
                maximum allowable total kilowatt hours annual limit.
                Except for this express authorization for increased DA transactions under
        SB 695, the previously enacted suspension of DA transactions remains in effect
        until repealed by legislation, or until additional DA transactions are otherwise
        authorized.
                Within six months from the effective date of SB 6954 or July 1, 2010,
        whichever is sooner, the Commission must adopt and implement a schedule to
        begin the phase-in of authorized increases in the maximum amount of DA
        transactions over a period of at least three years, but not more than five years.

        3   See D.01-09-060 and Pub. Util. Code §§ 366 or 366.5.
        4 SB 695 was chaptered on October 11, 2009 and as urgency legislation, took effect
        immediately. Six months from the effective date of SB 695 is April 11, 2010.




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        The allowable limit of DA power supplied by other providers in each electric
        utility's distribution service territory will be increased to the maximum allowable
        annual limit for that utility's distribution service territory as of the effective date
        of SB 695. The Commission may, if appropriate, modify its currently effective
        rules governing DA transactions, but such review shall not delay the phase-in
        schedule.
              In order to expeditiously implement SB695, the assigned Commissioner
        initiated this sub-phase of the proceeding by issuing a ruling amending the scope
        of this proceeding to address issues as necessary for implementing the
        provisions of SB 695 relating to DA. By ruling dated November 18, 2009, the
        assigned Commissioner identified the pertinent DA provisions of SB 695 to be
        addressed in this proceeding, and established a schedule to meet the SB 695
        timing requirements. Parties filed comments on the scope of issues to be
        addressed in this sub-phase on December 7, 2009. The assigned Commissioner
        issued a ruling modifying the scope of issues to be addressed by ruling dated
        December 17, 2009. The record was developed through the filing of written
        comments, with one workshop. No evidentiary hearings were necessary.
              Substantive comments were filed on January 5, 2010.5 A workshop was
        convened on January 11, 2010, to facilitate discussion and seek consensus on
        issues in dispute. Reply comments were filed on February 1, 2010.

        5 Opening Comments and/or reply comments were filed by the California Alliance for
        Choice in Energy Solutions and the Alliance for Retail Energy Markets
        (CACES/AReM), the Direct Access Customer Coalition (DACC), Pacific Gas and
        Electric Company (PG&E), BP America (BP), the California Large Energy Consumers
        Association (CLECA), California Manufacturers and Technology Association (CMTA),
        Commercial Energy of California (CEC), the Division of Ratepayer Advocates (DRA),
        The Utility Reform Network (TURN), the Natural Resources Defense Council (NRDC),

                                                                     Footnote continued on next page


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         3.    Authorized Increases for Direct Access Cap
               We herein authorize increased limits on the maximum level of DA
         transactions that may be allowed beginning effective April 11, 20106. The basis
         for the increased allowances is prescribed by Sec. 365.1 which states that the
         maximum limit:
               … shall be established by the commission for each electrical
               corporation at the maximum total kilowatt hours supplied by all
               other providers to distribution customers of that electrical
               corporation during any sequential 12-month period between
               April 1, 1998, and the effective date of this section.
               (Emphasis added.)
               The statute defines “other provider” as any person, corporation, or other
         entity that is authorized to provide electric service within the service territory of
         the electrical corporation, but does not include sales to or by a community choice
         aggregator. Individual retail non-residential end-use customers in an electrical
         corporation’s service territory will be allowed to acquire electric service from
         providers other than the electrical corporation up to a maximum total kilowatt
         hour (kWh) annual limit. In response to the Administrative Law Judge (ALJ)
         ruling issued November 18, 2009, each of the IOUs provided the relevant data
         identifying the applicable amount of DA load subject to the increased DA cap
         pursuant to the requirements of SB 695.



         Southern California Edison Company (SCE), the Safeway Parties (Safeway), San Diego
         Gas & Electric Company (SDG&E), Silicon Valley Leadership Group, School Project for
         Utility Rate Reduction, the California State Universities, and Customized Energy
         Solutions, LTD.
         6 The implementation date of April 11, 2010 represents the time limit required to begin
         implementation under SB 695, representing six months from the statute’s effective date.




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                The IOUs and the Commission’s Energy Division provided clarification at
        the workshop of the differences between the numbers in the December 3, 2009
        and December 29, 2009, informational filings and the numbers provided in the
        IOUs’ monthly DA activity reports. The general consensus among parties at the
        workshop was that formal independent verification of the data submitted by the
        IOUs was not necessary, and that the time required to implement such
        verification process could unduly delay the reopening of DA. The Commission
        already has the ability to verify the load data provided by the IOUs in case of a
        dispute.
                The applicable new DA load increase relating to each of the IOU service
        territories is set forth as follows:
                                                            In gigawatt hours
        Line
                                                   SCE            PG&E           SDG&E
        No.
          1  Load Cap Pursuant to SB 695           11,710          9,520          3,562
          2  Existing Base Line DA                  7,764          5,574          3,100
          3  New DA Load Allowance                  3,946          3,946            462
             (Line 1 less Line 2)

                The new load eligible for DA service represents a relatively small portion
        of each of the utilities’ portfolios, involving less than 10 million megawatt hours
        (MWh) of annual usage across the entire state. This amount is less than 6% of the
        entire load served, and is much less than the annual variation in electricity
        consumption across the state due to the weather and the economy.
                The SB 695 cap limits any potential risk associated with reopening of DA
        by eliminating uncertainty associated with load migration. The adopted
        phase-in schedule will provide enough lead time for the IOUs to account for
        small shifts in load and thereby avoid unwarranted cost shifting and stranded
        load.


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              3.1.     Discussion
              We conclude that the utilities reported load figures reasonably comply
        with the criteria set forth in SB 695. We adopt those figures for use in this
        decision in implementing SB 695 caps. The SCE figures require some
        explanation.
              In its opening comments, SCE set forth the overall DA cap under SB 695
        and the baseline amount for SCE’s service area,7 as follows:
              • Based on kWh sales data maintained in SCE’s billing system, the
                maximum recorded sales to SCE distribution customers by all
                other providers for any sequential 12-month period was 11,710
                GWh from July 2003 through June 2004.
              • SCE’s current level of DA in its service territory, expressed as the
                annual load of those customers taking DA as of November 30,
                2009, is 7,627 GWh.
              Subsequent to the filing of these comments, SCE subsequently amended its
        initial calculation of DA baseline amounts to recognize the effects of the MWh
        set-aside granted for the City of Cerritos (Cerritos). The Commission issued
        D.10-01-012 determining the rights of Cerritos under AB 80. As a result of this
        decision, SCE revised its reported baseline of current DA load in its service
        territory to include the set-aside of MWh for Cerritos, which the Commission
        found to be required by AB 80.
              In D.10-01-012, the Commission concluded that AB 80 authorizes Cerritos
        to enter into direct transactions with any retail end-use customer in its
        jurisdiction on an opt-in basis up to Cerritos’ generation entitlement share of the



        7 See SCE Opening Comments at 7, citing its December 3 and December 29, 2009 data
        response filed in this proceeding.




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        Magnolia Power Plant (MPP) output.8 D.10-01-012 clarified that AB 80 does not
        require Cerritos to provide opt-out service, as is provided by community choice
        aggregators.9
                  Cerritos currently serves about 13.02 megawatts (MW) of opt-in,
        non-residential load. However, D.10-10-012 makes clear that Cerritos has a right
        “to sell all of its entitlement share [of MPP’s output] on a retail basis.”10 SCE has
        calculated Cerritos’ share of the annual MPP output as 137.5 gigawatt hours
        (GWh).11 Therefore, under D.10-01-012, Cerritos is entitled to serve 137.5 GWh of
        annual, opt-in load.
                  D.10-01-012 affects the implementation of SB 695 in the following manner:
                  • Because Cerritos is not a community choice aggregator, it is
                    considered to be an “other provider” within Section 365.1 of the
                    Public Utilities Code. Therefore, the maximum allowable total
                    kWh annual limit in SB 695 should include customers’
                    acquisition of electrical service from Cerritos.
                  • Unlike all other providers, Cerritos has been found by the
                    Commission to have a right to sell a certain annual amount of
                    energy via direct transactions to retail end-use customers. This
                    necessitates a permanent “set-aside” for Cerritos under SB 695’s
                    overall annual kWh cap, thereby increasing the baseline for SCE’s
                    service area.
                  Accordingly, SCE’s current level of DA in its service territory, expressed as
        the annual load of those customers taking DA as of November 30, 2009, plus


        8    See generally D.10-01-012, issued January 21, 2010 in A.09-06-008.
        9    See id. at 7-8.
        10   See D.10-01-012 at 13.
        11SCE must file an advice letter to set forth Cerritos’ share of the MPP output; therefore
        SCE’s calculation is subject to Commission review for compliance with D.10-01-012.




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         Cerritos’ set-aside of 137.5 GWh under D.10-01-012, is adjusted to 7,764.5 GWh.
         Cerritos’ set-aside will not be available for other providers, even if Cerritos does
         not sell all 137.5 GWh annually to retail end-use customers in SCE’s service area.

         4.       Phase-In Schedule for Increased Cap

                  4.1.   Parties’ Positions
                  The statute requires that the new DA load growth be phased in over a
         period of not less than three years and not more than five years.12 Certain parties
         express support for a three-year phase-in period, arguing that it offers the most
         efficient and consumer-friendly approach. PG&E, SDG&E, and various parties
         representing DA interests believe that a three-year phase-in period will
         accommodate IOU long-term procurement and resource planning needs. All
         parties generally agree to defining the duration of each phase-in interval as a
         calendar year, with the exception of the first year, which would cover only the
         period from the effective date of this decision through December 2010.
                  PG&E recommends an annualized usage cap increment of 1,500
         GWh/year for each year of the phase-in period. If additional DA load is fully
         subscribed each year, the phase-in would then be completed in three years. If,
         however, DA demand varied from year to year, the cap would guard against the
         potential for extreme load changes from any one year to the next, but could
         extend the phase-in period up to the five years allowed under the statute.
                  PG&E states that establishing an annual cap will address the potential
         procurement issues that could otherwise occur if there were extreme differences
         in demand for new DA from one year to the next during the phase-in period.


         12   Pub. Util. Code § 365.1(b).




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              To provide additional flexibility, however, PG&E expresses a willingness
        to employ a “soft” cap each year of the phase-in period to allow a customer
        whose load may slightly exceed the annual cap to proceed with enrollment onto
        DA service. PG&E believes that an additional 5% over the annual cap is
        reasonable.
              A group of parties (Joint Parties) entered into discussions after the initial
        round of comments were filed, and agreed upon a joint proposal.13 In entering
        into the joint proposal, some of the Joint Parties modified their previous position
        set forth in opening comments.
              The Joint Parties propose a four-year phase-in period, structured to allow
        up 50% of the room available under the cap in the first year, up to 70% in the
        second year, up to 90% in the third year, and up to 100% in the fourth year of the
        phase-in period. The Joint Parties argue that a four-year phase-in with a larger
        increment available initially, will accommodate a larger influx while avoiding
        the need for customers to rush to get in under the cap at the outset if they are not
        ready to do so.
              SCE argues that allowing excessive DA enrollment in the first year could
        detrimentally impact the administration and processing of Direct Access Service
        Requests (DASRs) as well as the utility’s ability to meet procurement
        requirements to accommodate changes in load.
              TURN joins with the other Joint Parties in proposing a four-year phase-in
        period. Alternatively, assuming that the Commission is convinced that a rush of


        13Parties sponsoring the joint proposal were TURN, SCE, CACES/AReM, the
        California State Universities, DACC, Silicon Valley Leadership Group, and School
        Project for Utility Rate Reduction.




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        new customers could reasonably be expected at the initial reopening, TURN
        believes that a three-year phase-in might be warranted. TURN supports the
        establishment of annual GWh caps in advance, independent of the amount of
        actual load migration in prior years of the transition.
              TURN believes that monitoring must continue beyond the initial phase-in
        period to keep up with changes in DA load. The level of the DA cap will remain
        in effect beyond the end of the phase-in period unless or until changed by future
        legislation. The IOUs will need to know on an ongoing basis whether or not they
        can accept new DASRs, and ESPs will need to know whether they is any further
        room available for marketing purposes.
              CLECA and California Manufacturers & Technology Association (CMTA)
        jointly argue that the Commission should phase in the reopening over the full
        five-year period, rather than a three-year period. DRA agrees with CLECA and
        CMTA. CLECA believes that three-year phase-in period, with as much as 75% of
        the available headroom made available to new customers during a 60-day open-
        enrollment period, will create a “gold rush” mentality, resulting in a variety of
        negative consequences. For example, CLECA expresses concern that customers
        would be motivated to act quickly, perhaps precipitously, to exercise their option
        to acquire DA, without having adequate time to analyze and absorb the many
        factors that should be weighed in such a decision. CLECA also argues that a
        gold rush environment would tend to increase transactional costs, particularly
        for the IOUs’ processing of new requests to switch to DA.
              CLECA notes that if a DA-eligible customer returned to bundled service in
        July 2009, that customer could return to DA service immediately during the
        initial enrollment period after the April 2010 reopening of DA, but if the
        customer did not make the election during the initial enrollment period, the


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        customer would have to wait more than two years after that reopening to make
        its return to DA service. CLECA expresses concern that an existing DA-eligible
        customer could find that it had lost entirely the ability to return to DA if the
        Commission were to permit a rapid phase-in of the new DA service for non-DA-
        eligible customers.
              CLECA also proposes that the Commission should permit additions per
        year of no more than 20% of the total allowed increment in new DA. CLECA
        argues that this slower pace of phase-in would reduce transitional and
        generational planning issues.
              CEC suggests a three-year phase-in schedule, with 75% of total load
        permitted in the first year, and the remaining 25% spread equally over the
        following two years. In this manner, subsequent adjustments can be made based
        on the first year’s experience.

              4.2.   Discussion
              We have considered the range of proposals as to the duration and pacing
        of phase-in, ranging from three years to five years. We conclude that a three
        year period is too short, and could cause an excessive surge in demand for new
        DA, resulting in potential negative consequences, as noted by CLECA and DRA.
        We likewise conclude that a five-year phase-in period is too long, and would
        unduly prolong the phase-in of new DA. We shall therefore adopt a four-year
        phase-in period. Our adopted phase-in generally incorporates the Joint Parties’
        proposed four-year phase-period, but we shall apply a more gradual pace in
        annual DA limits compared with the Joint Parties’ proposed first-year limit of up
        to 50%. A front-loading of 50% in the first year could create a surge in demand
        for DA concentrated in the open enrollment window between mid April and
        June 30, 2010. This surge could be amplified especially since Year 1 will be


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        truncated to nine months with an April 11 start date. Joint Parties’ proposal for a
        cumulative DA load cap of 70% by the second year only leaves 20% in the second
        year if enrollment reaches 50% in the first year. As a result, customers could feel
        pressured to rush to sign up before the June 30th deadline.14 The truncated first
        year could create an undue burden on the program’s first year.15
              We shall therefore adopt annual DA caps of up to 35% in the first year, up
        to 70% in the second year, up to 90% in the third year, and up to 100% in the
        fourth year. Limiting the adopted limits in this manner reduces the burden on
        potential DA customers to sign up in the first year, and correspondingly
        increases the load available for new DA customers in the second year.
        Moderating the first year’s cap to 35% will help prevent the potential for
        customers to become aggrieved by being rushed into signing up for direct access
        without adequate time to consider all of the factors involved.
              We conclude that the four-year phase-in period, with the related annual
        limits on new enrollments, strikes a reasonable balance, providing for an orderly
        implementation schedule that is manageable by the IOUs while still satisfying
        the requirements of SB 695 in a timely manner. We find that adopted phase-in
        schedule reasonably addresses the relevant concerns that must be balanced in
        crafting the appropriate pacing of the phase-in process. The first year of the
        phase-in covers the partial period beginning on the effective date of this decision,



        14Appendix 2 at 4, 8.a., “Customers may submit 6-month advance NOIs starting July 1,
        2010 to switch to DA in 2011.”
        15Reply Comments of The Division of Ratepayer Advocates on Assigned
        Commissioner’s Ruling Regarding Issues Associated With Senate Bill 695 Relating To
        Direct Access Transactions (February 1, 2010) at 5.




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         and continuing through the end of the 2010 calendar year. Each subsequent
         phase-in period shall cover a full 12-month calendar year.
               If any annual allocation of DA allotments under the cap is not fully
         subscribed in any one year, the unused portion shall be rolled over to the
         subsequent years. Each individual year’s DA limit shall stand alone, and not be
         dependent on the amount of actual migration in prior years of the phase-in.
               All DA-eligible customers will be free to switch to DA at any time, subject
         to the applicable switching rules, as long as room exists under the overall cap.
         Monitoring shall continue beyond the phase-in period because the cap on DA
         will remain in effect and must be enforced unless or until changed by future
         legislation.

         5.    Process to Implement New DA Enrollments

               5.1.     Parties’ Positions
               The Joint Parties presented a detailed proposal for a utility enrollment
         process during the phase-in period that is set forth in Appendix 2 of this
         decision. SCE joined in the Joint Party proposal. The Joint Party proposal calls
         for an initial open enrollment period going through June 30, 2010, with a
         temporary one-time waiver of the 6-month advance notice requirement and one-
         time waiver of the bundled service commitment under Rule 22.1. The details of
         the proposal for the receipt, review, and approval of customer requests to switch
         to DA service under SB 695 are set forth in detail in Appendix 2 of this decision.
               PG&E presented its own separate proposal for enrollments. Every
         customer would be required to submit a notice to their IOU that they want to
         switch to DA service. Upon acceptance of a customer notice to switch to DA
         service, PG&E will provide instructions for DASR submittal in a confirmation
         letter. If a valid DASR is submitted during the DASR window indicated in the


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        customer confirmation letter, the customer will switch on the date indicated. If
        no DASR is received by the close of the DASR window, the account will be
        placed on Transitional Bundled Service or “safe harbor” status. That means it
        will be billed on the Transitional Bundled Commodity Cost (TBCC) rates and
        given an additional 60 days in which to submit a valid DASR. If no DASR is
        submitted during this additional 60-day period, the customer notice is cancelled,
        the account continues on the TBCC rates for an additional six months, and then
        the account is committed to bundled portfolio service for a three-year period. In
        addition to following the existing switching rules, this would also discourage
        speculative submittals of customer notices, and allow customers who are serious
        about switching to DA service the ability to do so without the impediment of
        over-subscription of available load under the cap by more speculative
        participants.
              SDG&E also presented its own proposal (as Attachment A of its
        February 1, 2010 Reply Comments) as to the processing protocols for enrolling
        customers under the provisions of the SB 695 cap. SDG&E’s proposed approach
        is similar to the approaches proposed by SCE and CACES/AReM. SDG&E’s
        process calls for the customer to submit a notice of intent (NOI) within the
        designated open enrollment period, subject to a daily batching process. SDG&E
        would apply a “soft cap,” not to exceed 10% of the annual cap, in evaluating
        whether a request was to be approved. Customers would be notified within 20
        calendar days as to whether their NOI was accepted. DASRs would be
        processed in accordance with SDG&E’s Rule 25.
              DACC points to the customer application and tracking process adopted for
        the California Solar Initiative as an example to follow for administering the DA
        allocations. As proposed by DACC, a customer interested in transferring load to


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        DA service would submit a “Customer-Originated Direct Access Service
        Request” (CODASR) to its local IOU(s). Each CODASR would correspond to a
        customer utility service identification (ID) account number, covering the entire
        load served through that ID, as measured by the preceding 12-month billing
        period. Customers submitting completed CODASRs would be allocated priority
        rights to the available DA capacity on a first-come, first-served basis. The
        customer would have 30 calendar days to complete negotiations with a supplier,
        and for the supplier to submit a traditional DASR for the customer. If no DASR
        was submitted on behalf of a customer within the 30-day period, the rights to the
        available DA capacity previously allocated to that customer would be allocated
        to the customer with the next lower priority of rights.

              5.2.   Discussion
              We shall adopt an enrollment process for customers to sign up for direct
        access subject to the revised SB 695 limits under the provisions adopted in this
        decision, as set forth in Appendix 2 of this decision.
              The adopted process incorporates the four-year phase-in discussed above.
        It also incorporates a uniform treatment of all qualifying customers, without a
        separate set-aside or preferential treatment of existing DA-eligible customers.
        We address this issue further in Section 6. We also adopt a two-day window for
        customers to correct NOI deficiencies. The two-day limit will facilitate timely
        processing of daily NOI batches.
              In comments to the proposed decision, the Joint Parties argued that each
        IOU should be authorized to maintain a limited wait-list during the OEW to
        back-fill any room under the first-year allocation occupied by NOIs that are
        submitted but ultimately voided for failure to submit a DASR or correct a




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        deficiency. We find this proposal to be reasonable, and shall incorporate a wait-
        list process into the adopted procedure set forth in Appendix 2.
              The utilities shall begin placing submitted NOIs on an OEW wait-list on a
        first-come, first-served basis when or if the Year 1 allocation becomes fully
        subscribed during the OEW. There will be no wait-list after the OEW closes.
        The OEW shall be filled up to 25% of the Year 1 allocation. The IOU shall notify
        the customer that they are on the wait-list within 20 days after submission of the
        customer’s NOI. Notifications to customers that they are eligible to come off the
        wait-list (on a first-come, first-served basis) shall be made by email within one
        business day of the utility’s determination that space is available under the
        Year 1 allocation. All such notices shall be made no later than June 29, 2010, the
        last day of the OEW. The submission and processing schedule, as set forth in
        Appendix 2 shall apply.
              Each IOU shall be required to indicate on its public website whether
        notices of intent to switch to DA service are being accepted, and to update this
        information regularly. This information should be sufficient to inform customers
        and ESPs whether there is room under the annual limits during the phase-in
        period or the overall cap after the phase-in. Each IOU shall notify all DA-eligible
        customers of their opportunity to obtain generation service from another
        provider of the Effective Date. Each IOU shall provide a link to the new DA
        provisions on their respective web sites and shall also provide additional
        notification via bill inserts and onserts. ESPs shall notify their customers of their
        procurement-related obligations.




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         6.       Waiver of DA Switching and Notice Rules and
                  Subsequent Rights to Acquire DA

                  6.1.   Parties’ Positions
                  Under current rules,16 former DA customers currently receiving bundled
         utility service must provide six-months’ notice in order to leave bundled utility
         service. The same six-month notice requirement applies for customers that
         switch back to DA. Also, a DA customer who returns to bundled service must
         commit to stay for at least a three-year period.
                  PG&E proposes that the current three-year minimum bundled service
         commitment for customers now on bundled portfolio service be waived for an
         initial implementation period, starting on the date established by the
         Commission and extending for 60 days. Absent such a waiver, existing Bundled
         Portfolio Service (BPS) customers may be precluded from switching to DA
         service if the maximum load cap is reached before these customers complete
         their three-year commitment period.
                  In addition to waiving the three-year commitment period, PG&E would
         support giving BPS customers a higher priority to return to DA compared with
         “new prospective” DA customers, limited to the initial implementation period.
                  SCE does not support providing a preference to existing DA-eligible load,
         but proposes that all DA-eligible customers be provided an equal opportunity to
         enroll in DA if they so choose. SCE supports a temporary, one-time waiver of
         the six-month advance notice requirement during the open enrollment period.
         SCE also supports a one-time waiver to all DA-eligible customers under current
         BPS commitments, so that these customers can take DA service at any time upon

         16   See D.03-05-034 and D.03-06-035.




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        notice of intent (during the open enrollment) or a six-month advance notice (after
        the open enrollment), assuming that there is sufficient room under the annual
        limits or overall cap. SCE proposes that the three-year BPS commitment period
        continue to apply anytime that a DA customer returns to BPS.
              After the open enrollment period ends, SCE proposes that the DA
        switching rules apply equally to all DA-eligible customers, including bundled
        service customers wishing to switch to DA for the first time, unless and until the
        Commission reviews and modifies these rules in a subsequent phase of the
        proceeding.
              SCE proposes to establish a wait list and to enroll customers on DA service
        on a first-come, first served basis, as room becomes available under the annual
        limits or overall cap.
              TURN argues that there is no compelling need for granting any special
        preference for load that is DA-eligible under the current rules. TURN believes
        that there is minimal risk that load that is DA-eligible under the current rules,
        and subject to the three-year minimum stay on bundled service will be
        “squeezed out” by new DA load. The highest annual figure reported by any of
        the IOUs for potential DA-eligible bundled load returning to DA service is 475
        GWh for PG&E during the period from April 2010 through April 2011. That
        amount is only about 50% of the quantity proposed by TURN to be made
        available in the first year of the phase-in period. The other utilities and the other
        years for PG&E show an even smaller percentage.
              TURN argues that no special set-aside preference should be granted to
        existing customers who are DA-eligible under current rules other than to allow
        them to terminate their three-year minimum commitment on bundled service in
        April of the year which the commitment would otherwise expire. In this


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        manner, these customers could request DA service as soon as the next phase-in
        step occurs. TURN believes that such provision would be sufficient to prevent
        any DA-eligible customer from being “stranded” on bundled service because of
        the new total GWh cap on DA. TURN argues that updates on DA load should be
        posted at least monthly, and perhaps more frequently in a month when a utility’s
        DA load is approaching the cap level.
              TURN does not object to a temporary suspension of the six-month notice
        requirement for customers switching from bundled service to DA, but only
        during the first year of the phase-in period. TURN does not believe that a
        continued waiver period beyond the first year is necessary, because customers
        will be in a better position to provide notice in subsequent years of the phase-in
        period.
              TURN proposes that any and all customers returning to bundled service
        from DA should remain subject to at least a six-month notice period during
        which time they would be subject to the Transitional Bundled Service (TBS) rate
        if they return to bundled service prematurely. TURN believes that at least a one-
        year notice should be required in order for the returning customer to avoid
        becoming subject to the TBS rate. If a customer returns to the IOU with less than
        a one-year notice, the IOU would have to obtain additional resource adequacy
        (RA) resources outside of the normal procurement cycle, potentially resulting in
        higher costs for the IOU and bundled customers.
              The Joint Parties argue that all customer eligible to switch to DA under
        SB 695 should be provided an equal opportunity to enroll in DA as of the
        effective date if they so choose.




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              6.2.   Discussion
              We shall grant all DA-eligible customers currently under BPS
        commitments a one-time waiver of their BPS commitments to allow them an
        equal opportunity to enroll in DA as of the Effective Date of this decision. A
        temporary one-time waiver of the six-month advance notice requirement shall
        also be granted to all DA-eligible customers to allow them an equal opportunity
        to enroll in DA during the initial open enrollment window, as described in
        Appendix 2 hereto. The waivers shall apply only during the initial open
        enrollment window. The long-term applicability of the three-year minimum BPS
        commitment and six-month advance notice requirements shall be addressed in a
        subsequent phase of this proceeding. We shall not grant a special preference or
        set-aside of load to existing DA-eligible customers. Instead, an equal
        opportunity to enroll in DA shall apply to all eligible customers.
              SCE suggested in its comments that residential customers who have taken
        DA service in the past, but now take utility bundled service (considered as
        “DA-eligible” under the Commission’s rules in effect prior to the enactment of
        SB 695), would be permitted to switch back to DA service during the phased
        reopening period. TURN disagrees, however, arguing that SCE’s interpretation
        is inconsistent with SB 695.
              SB 695 repealed the prior statutory provisions regarding the suspension of
        DA which had been in effect since 2001, and replaced those provisions with a
        new statute, Public Utilities Code Section 365.1. The new statute provides, in
        relevant part, as follows:
                365.1. (a) Except as expressly authorized by this section, and
              subject to the limitations in subdivisions (b) and (c), the right of
              retail end-use customers pursuant to this chapter to acquire service




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               from other providers is suspended until the Legislature, by statute,
               lifts the suspension or otherwise authorizes direct transactions. . . .
                  b) The commission shall allow individual retail nonresidential
               end-use customers to acquire electric service from other providers in
               each electrical corporation’s distribution service territory, up to a
               maximum allowable total kilowatt hours annual limit. . . . .
               (Emphasis added.)
               TURN argues that Section 365.1(a) suspends the right of retail end-use
         customers provided elsewhere in statute (in the AB 1890 revisions to the Public
         Utilities Code) to acquire service from other providers except as authorized
         therein and subject to the limitations in subdivisions (b) and (c). Among those
         limitations is the provision that allows only nonresidential end-use customers to
         acquire DA service, up to a maximum annual kWh limit.
               We agree with TURN’s interpretation. Nothing in the statutory language
         indicates that any residential customer not already taking DA service would be
         permitted to take service from another provider under the annual kWh limit
         during the period of the suspension. Accordingly, we affirm that the right to
         acquire new DA pursuant to SB 695 excludes residential customers who are not
         already taking DA service. However, an existing DA-eligible residential
         customer on bundled service that has already given its six-month notice to return
         to DA prior to the effective date of this decision would still retain the right to
         return.

         7.    Meter Installation Waiver

               7.1.   Parties’ Positions
               Under current rules, any customer with a peak load that is greater than
         50 kilowatts (kW) is required to install an approved interval meter. Interval




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        meters allow customers better access and control to their load consumption, and
        are a step toward a smarter, more efficient electric grid.
              CACES believes that the requirement for DA customers to install interval
        meters in order to receive DA service should be modified to allow a customer to
        choose whether or not they want to install such a meter in advance of the
        “Advanced Meter Initiative” deployment. CACES argues that such DA
        customers should not be required to pay for an interval meter that will soon be
        replaced by an Advanced Metering Infrastructure (AMI) meter, particularly
        because they are already paying for the AMI deployment.
              All customers with load greater than 200 kW already have interval meters.
        CACES argues that any commercial/ industrial customers whose peak load is
        between 50 kW and 200 kW should have the choice of whether to install an
        interval meter.
              SCE proposes that service accounts with demand between 50 kW and
        199 kW be granted a temporary waiver from the DA interval meter requirement
        pending the scheduled installation of an Edison SmartConnect meter, unless the
        meter is required by the ESP. SCE proposes that if the customer’s ESP requires
        an interval meter, the ESP would be billed for the cost of such meter.
              SCE argues that a waiver should not apply to customers with service
        accounts having a demand of 200 kW or greater since under SCE’s tariffs, such
        accounts are required to have interval metering.

              7.2.   Discussion
              A temporary waiver of each utility’s DA interval meter installation
        requirement applicable to service accounts with demand between 50 kW and
        199 kW shall be granted, pending the scheduled installation of an AMI smart
        meter by the utility, unless an interval meter is specifically requested by the


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         customer’s ESP. If the customer’s ESP requests an interval meter, the ESP will be
         billed for the cost of such meter. If a DASR is submitted for a customer who does
         not have an interval meter in place, and an AMI smart meter is not installed
         before the next meter read cycle, load profiles will be used for settlement
         purposes, trued up by actual meter reads, as is done for customers with loads
         less than 50 kW, until an AMI smart meter is installed. All customers with
         service accounts having a demand of 200 kW or greater are required to have
         interval metering. Therefore, a waiver shall not apply to these accounts.
                  Utility Tariff Rule 22 requires that service accounts with demands greater
         than 50 kW have interval meters prior to being placed on DA service.17
         Therefore, a revision to the Utility Tariff Rule 22 will be necessary to authorize
         this waiver. The utilities shall incorporate this revision in their advice letter
         filings implementing the requirements of this order.

         8.       Compliance with Procurement and Resource
                  Planning Rules
                  SB 695 requires the Commission to ensure that other providers of
         electricity in California are subject to the same procurement-related requirements
         that apply to the IOUs, including resource adequacy requirements, renewables
         portfolio standards, and greenhouse gas emission reductions.
                  Pursuant to SB 695, once the Commission has authorized additional DA
         transactions, it is required to ensure that other providers are subject to the same
         requirements that apply to the three largest California electric utilities under:
                  1. Commission-adopted programs to implement the resource
                     adequacy provisions of Public Utilities Code Section 380;

         17   See Utility Tariff Rule 22, Section A.2.




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              2. Renewable portfolio standards of the Public Utilities Code,
                 Article 16; and
              3. Electricity sector requirements adopted by the California Air
                 Resources Board pursuant to the California Global Warming
                 Solutions Act of 2006.

              8.1.   Parties’ Positions
              Various parties affirm the importance of enforcing uniform procurement
        and resource planning rules on all load serving entities (LSEs). SCE, in its
        comments, identified a number of issues that remain to be addressed by the
        Commission to ensure that these requirements are imposed in a uniform manner
        among all LSEs. As noted in the Assigned Commissioner’s Ruling dated
        November 18, 2009, specific additional procurement-related requirements will be
        considered in the appropriate proceedings. SCE asks that in the final decision in
        this sub-phase we order the immediate opening of a separate sub-phase here, or
        in other existing proceedings, to address any and all remaining issues regarding
        procurement-related obligations of ESPs under SB 695.
              TURN identifies the potential problem with the allocation of RA resources
        in this regard. Under current rules, a customer’s new ESP is not required to
        obtain its proportionate share of Local RA resources until the 2011 RA
        compliance year, because Local RA is subject to only an annual compliance
        obligation, with no monthly true-up. At the same time, the IOU that loses the
        load will have no market for the Local RA resources that it had previously
        procured to serve that load. TURN argues that while a longer-term solution to
        this problem may be developed in Rulemaking (R.) 09-10-032, the new RA OIR,
        that proceeding cannot be expected to produce a resolution of the issue by
        April 11, 2010. As a result, TURN expresses concern that bundled service
        customers may be left with a disproportionate share of Local RA obligations and


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        costs for the remainder of 2010, including the critical summer peak period when
        RA is particularly valuable and costly.
              TURN initially proposed as an interim solution – pending longer-term
        resolution of the issue in R.09-10-032 – that ESPs obtaining additional load as a
        result of the DA reopening in April 2010 be required to purchase the
        proportional amount of Local RA capacity from the host IOU at an RA “waiver
        trigger” price of $40 per kW-year, pro rated as appropriate for the remainder of
        the current year. TURN argued that this interim measure will help to prevent
        inappropriate gaming and avoid creating a perverse incentive for customers to
        switch providers simply to avoid their fair share of Local RA costs.
              TURN argues that new ESPs entering the market should not be treated any
        differently from existing ESPs or IOUs with respect to RPS requirements. TURN
        notes that the rules require all LSEs to procure 20% of their energy from eligible
        renewable projects by 2010, subject to the applicable flexible compliance rules.
              PG&E also recommends that resolution is needed on how DA customers
        and ESPs could make IOUs whole for the local RA that has already been
        procured in 2010, thereby effectuating the transfer of local RA from the IOUs to
        ESPs at a price certain. PG&E believes that TURN’s January 11, 2010 filing in
        R.09-10-012 is simple and can be adapted for this purpose. PG&E states that this
        approach would not have precedence on the long-term proceeding under
        R.09-10-012, or the RA proceeding R. 09-10-032, but would only apply for 2010.
              A proposal for an interim solution to Local RA obligations was further
        developed in the comments of the Joint Parties. As noted by the Joint Parties, the
        reopening of DA in April 2010 comes in the middle of the RA program
        compliance year, which is administered on a calendar year basis. While system
        RA obligations are adjusted on a monthly basis to reflect migration of customers


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        between LSEs under current procedures, no similar adjustment exists for Local
        RA. Proposals to adopt a formal Local RA load migration adjustment are under
        consideration in R.09-10-032 for compliance year 2011. In view of the increase in
        load migration that may occur as early as April 2010, however, a more
        immediate temporary solution to deal with this issue is needed. This interim
        solution is described in Appendix 3 hereto.
              The proposed temporary solution, as set forth in the Joint Parties’
        comments, provides a means of establishing a value for a “Customer Local RA
        Obligation” when a customer seeks to migrate between LSEs after the effective
        date of DA reopening. This value will be based upon the customers’ actual 2009
        Coincident Peak Demand multiplied by a “Local-to-Peak Ratio” that will be
        calculated for each IOU service territory, as set forth in Appendix 3. The
        resulting figure (expressed in MW) will constitute the Local RA Obligation of
        that customer. The LSE gaining the additional load will have the option to
        obtain an allocation of RA “credits” from the LSE losing the load without the
        need for an actual sale of physical capacity to occur between the two LSEs. The
        LSE gaining the load would make a payment to the LSE losing the load equal to
        the customer’s Local RA Obligation multiplied by a default transfer price of $24
        per kW-year. This payment would be deemed to satisfy the acquiring LSE’s
        Local RA Obligation for the remainder of the 2010 compliance year.

              8.2.   Discussion
              We recognize the need for timely action on resolving any remaining issues
        relating to procurement-related obligations of ESPs under SB 695. We conclude,
        however, that as a general matter, the adoption of a specific timetable and the
        scope of the relevant issues is best addressed in the separate proceedings where
        the relevant specialized expertise already exists. As an exception to this general


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        approach, however, we conclude that the one specific issue relating to RA
        obligations, as discussed in the Joint Parties’ comments, requires an interim
        resolution in this proceeding. We agree that the Joint Proposal offers a
        reasonable short-term solution to deal with the issue of Local RA Obligations
        and we adopt it on that basis. The proposed temporary solution is set forth in
        Appendix 3 of this decision, based upon the Joint Proposal. This interim solution
        is adopted for implementation as part of the initial phase-in of new DA load in
        order to allow DA transactions to proceed in a timely manner while accounting
        for the impacts on RA obligations.
              The adopted solution will provide an expedient means of establishing a
        value for a Customer Local RA Obligation for use when a customer transfers
        from one LSE to another during the initial DA open enrollment period. The
        temporary solution will avoid the potential for cost shifting or undue
        competitive advantage associated with the Local RA Obligation. After 2010, this
        temporary solution would be superseded as a result of whatever solution (if any)
        is adopted in R.09-10-032 for the 2010 compliance year.
              This temporary solution shall explicitly apply only for calendar year 2010,
        and shall either continue or be replaced as a result of whatever solution (if any) is
        adopted in R.09-01-032 for the 2011 RA compliance year. To facilitate a smoother
        synchronization between the phased increase in DA load and the annual RA
        schedule, the next step in the DA phase-in schedule would occur on January 1,
        2011, rather than on April 11, 2011. The use of the January date would allow
        LSEs’ year-ahead Local RA showings for 2011 to reflect any load migration that
        is expected to occur at the start of the next DA reopening phase-in. The ESPs will
        remain subject to the previously adopted RA showing process which starts in
        July 2010 for 2011 showings.


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               We make certain revisions to Appendix 3 based upon comments on the
         proposed decision. For example, we revise the previous references in the
         proposed decision to Local RA obligations being “aggregated by NP-26 and
         SP-26,” and instead specify the local areas for which LSEs must procure Local
         RA. We also incorporate Joint Parties’ proposed modifications to the formulas
         for calculating the Local-to-Peak ratio and the Customer Local RA obligation, as
         set forth in Appendix 3.
               The Joint Parties propose that all LSEs that intend to serve load during
         2011 refile load forecasts for the 2011 RA compliance year on July 15, 2010
               We shall adopt the due date of May 26, 2010 (instead of July 15, 2010), for
         LSEs to provide Energy Division with revised load forecasts for the 2011 RA
         compliance year. Based on the timing for the IOUs to respond to NOIs, a
         suitable compromise is to have forecasts due from LSEs on May 26, 2010. This
         will be the only forecast due for 2011 year-ahead compliance.

         9.    Categorization and Assignment of Proceeding
               This proceeding is categorized as Ratesetting. The assigned Commissioner
         is Michael R. Peevey and the assigned ALJ is Thomas R. Pulsifer.

         10.   Comments on Proposed Decision
               The proposed decision of ALJ Pulsifer in this matter was mailed to the
         parties in accordance with Section 311 of the Public Utilities Code and comments
         were allowed under Rule 14.3 of the Commission’s Rules of Practice and
         Procedure. Comments were filed on March 1, 2010, and reply comments were
         filed on March 8, 2010. The proposed decision was also mailed to the service lists
         of R.08-01-025 and R.09-10-032 so that all affected LSEs could comment on the
         proposed decision. We have incorporated parties’ comments, as appropriate, in
         finalizing this decision.


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         Findings of Fact
           1. On October 11, 2009, SB 695 was signed into law as an urgency statute,
        adding Section 365.1 (b) to the Public Utilities Code.
           2. Public Utilities Code Section 365.1(b) requires the Commission to allow
        individual retail nonresidential end-use customers to acquire electric service
        from other providers in each electrical corporation’s distribution service
        territory, up to a maximum allowable total annual limit.
           3. The amounts of DA load as set forth in Appendix 1 of this decision
        constitute the incremental amount of transactions that are allowed in
        conformance with implementation of Public Utilities Code Section 365.1(b).
           4. The statute allows for a phase-in period for new DA of not less than three
        years and not more than five years, subject to Commission determination.
           5. A four-year phase-in period with annual caps as set forth in Appendix 2
        will reasonably accommodate the utilities’ long-term procurement and resource
        planning needs, while providing for timely implementation of new DA load
        consistent with the provisions of SB 695.
           6. Under current rules, former DA customers receiving bundled utility
        service must provide six-months’ notice in order to leave bundled utility service.
        The six-month notice requirement applies for customers that switch back to DA.
        A DA customer who returns to bundled service must commit to stay for at least a
        three-year period.
           7. Under current rules, any customer with a peak load that is greater than
        50 kW is required to install an approved interval meter. Interval meters allow
        customers better access and control to their load consumption, and are a step
        toward a smarter, more efficient electric grid.




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            8. Rule 22 requires that service accounts with demands greater than 50 kW
         have interval meters prior to being placed on DA service.
            9. SB 695 requires that other providers of electricity in California are to be
         subject to the same procurement-related requirements that apply to the IOUs,
         including resource adequacy requirements, renewable portfolio standards, and
         greenhouse gas emission reductions.
           10. The interim measures set forth in Appendix 3 for the treatment of Local
         RA obligations during the enrollment period for new DA will provide a
         reasonable way to satisfy an LSE’s RA obligations in connection with customer
         migration pursuant to SB 695, subject to any further disposition in R.09-10-032.
           11. The enrollment procedures for new Direct Access Load as set forth in
         Appendix 2 of this decision provides for an orderly process that will be
         manageable by the utilities while providing for timely processing of new
         enrollments.
           12. The Proposed Decision (PD) was served on parties in R.08-01-025 and
         R.09-10-032 so that all affected Load Serving Entities could comment on the PD.

          Conclusions of Law
            1. The Commission is required by the provisions of Public Utilities Code
         Section 365.1(b) to allow individual retail non-residential end-use customers to
         acquire electric service from other providers in each electrical corporation’s
         distribution service territory, up to a maximum allowable total annual limit.
            2. The authorizations for increased DA transactions, as set forth below in the
         ordering paragraphs of this decision, reasonably satisfy the requirements of
         Section 365.1(b) for increased limits in DA transactions.




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           3. The investor-owned utilities should proceed with implementation of the
        processing of new DA service requests in accordance with the revised limits
        adopted below.
           4. A temporary one-time waiver of the current three-year minimum bundled
        service commitment for customers now on BPS customers should be granted
        covering the initial open enrollment period, starting on the effective date of this
        decision and extending through June 30, 2010.
           5. Any commercial/industrial customers whose peak load is between 50 kW
        and 200 kW should have the choice of whether to install an interval meter.
           6. The procedures for enrollment of new DA load pursuant to SB 695, as set
        forth in Appendix 2 of this decision, are reasonable and should be adopted.
           7. The procedures for the treatment of Local Resource Adequacy Obligations
        pursuant to SB 695, as set forth in Appendix 3 of this decision are reasonable and
        should be adopted.
           8. The next phase of this proceeding should expeditiously address the
        remaining issues to be resolved relating to the phase-in of additional limits on
        direct access transactions.
           9. The provisions for new enrollments of DA customers under SB 695 should
        be based upon a first-come, first-served principle, without special set-asides for
        DA-eligible customers who have exercised the right to take DA previously.
          10. In order to establish an orderly process for enrolling new DA customers
        pursuant to SB 695, a Notice of Intent (NOI) to subscribe to DA should be
        submitted by customers. The NOI should be subject to utility review and
        notification of space availability to the customer and the ESP in accordance with
        the procedures set forth in Appendix 2 of this decision.




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          11. SB 695 contains no language granting any preference or special rights to
        DA-eligible customers who have exercised the right to take DA previously, and
        there is no basis for the Commission to impose special preferential treatment for
        such DA-eligible customers in implementing SB 695.
          12. For purposes of determining if the authorized cap has been reached in
        relation to the total requests for new DA service, a daily NOI batching process, as
        proposed by the Joint Parties, provides for a more streamlined implementation.
          13. The right to acquire new DA pursuant to SB 695 excludes residential
        customers who are not already taking DA service o otherwise eligible per
        D.05-03-034.



                                           O R D E R

              IT IS ORDERED that:
           1. Revised limits are hereby adopted in the cap on direct access transactions
        within the service territories of each of California’s three major investor-owned
        utilities, Pacific Gas and Electric Company, Southern California Edison
        Company, and San Diego Gas & Electric Company, as set forth in Appendix 1 of
        this decision. The authorized increases in direct access transactions shall be
        incorporated into the utilities’ tariffs pursuant to Ordering Paragraph 8.
        Adjustments to each utility’s baseline amount of direct access load as set forth in
        Appendix 1 shall be based on the same method used by the utilities to calculate
        direct access load in their Direct Access Implementation Activities Reports
        submitted to the Commission on a monthly basis. The Energy Division is
        authorized to post each utility’s monthly baseline amount of direct access load,




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        as reported in their Direct Access Implementation Activities Reports, on the
        Commission’s public website.
           2. The increased limits on direct access transactions set forth in Appendix 1
        hereof shall be phased in over a four-year period beginning on the effective date
        of April 11, 2010, in accordance with the enrollment procedures set forth in
        Appendix 2.
           3. A one-time waiver of the current three-year minimum bundled service
        commitment for customers now on bundled portfolio service is hereby granted
        for any bundled portfolio service commitments in existence as of April 11, 2010,
        the direct access reopening effective date. This one-time waiver will effectively
        eliminate those bundled portfolio service commitments in existence on the
        Effective Date of the direct access reopening, even if those customers do not elect
        to take direct access service during the Open Enrollment Window, to allow these
        customers to elect Direct Access service at any time with the required 6-month
        advance notice, assuming there is room under the annual limits or overall cap.
        The three-year bundled portfolio service commitment period will continue to
        apply anytime a Direct Access customer returns to bundled portfolio service
        after the Effective Date of the direct access reopening.
           4. The increased authorizations in the level of direct access transactions as set
        forth in Appendix 1 of this decision shall take effect beginning April 11, 2010,
        and continue for four calendar years, with annual limits as set forth in
        Appendix 2.
           5. The procedures for enrollment of new direct access load pursuant to
        SB 695, as set forth in Appendix 2 of this decision, are hereby adopted. The IOUs
        shall file advice letters within 20 days of the issuance of this decision proposing
        modifications to their direct access tariffs in compliance with this decision. The


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        advice filings shall be effective upon filing, and any modifications subsequently
        requested by the Energy Division based on its review of the advice filings shall
        not alter their effectiveness as of their filing dates. The advice letters shall
        include the form NOI to be used during the Open Enrollment Window
        authorized in this decision.
           6. A temporary waiver is hereby granted of Pacific Gas and Electric
        Company, Southern California Edison Company, and San Diego Gas & Electric
        Company’s direct access interval meter installation requirement applicable to
        service accounts with demand between 50 kilowatts (kW) and 199 kW, pending
        the scheduled installation of an Advanced Metering Infrastructure Smart Meter
        by the utility, unless an interval meter is specifically required by the customer’s
        electric service provider.
           7. A methodology for local Resource Adequacy obligations, based on the
        Joint Proposal and set forth in Appendix 3, is hereby adopted. The methodology
        shall be in effect for 2010 only, unless otherwise specified by a future ruling. We
        delegate authority to the Energy Division to make minor refinements or
        clarifications to the adopted methodology in the course of implementation.
           8. Investor-owned utilities subject to the provisions of this decision are
        directed to file advice letters to modify their tariff rules in compliance with this
        decision, due 20 days after the issuance of the decision, and effective upon filing.




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             9. This proceeding shall remain open to address the remaining
          implementation issues relating to the increased phase-in of direct access and
          other pending issues to be addressed in this rulemaking.
                This order is effective today.
                Dated March 11, 2010, in San Francisco, California




                                                            MICHAEL R. PEEVEY
                                                                       President
                                                            DIAN M. GRUENEICH
                                                            JOHN A. BOHN
                                                            TIMOTHY ALAN SIMON
                                                            NANCY E. RYAN
                                                                     Commissioners




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                                           Appendix 1
                 Authorized Increases in Caps on Direct Access Transactions
                                      By Service Territory


                        Authorized Direct Access Cap Increase (in GWh)
                        Within Service Territories of the Electric Utilities


                                         Southern
                                                          Pacific Gas and   San Diego Gas &
                                     California Edison
                                                         Electric Company   Electric Company
                                         Company
           Load Cap                       11,710             9,520               3,562
           Existing Base Line DA           7,764             5,574               3,100
           New DA Load Allowance           3,946             3,946                 462
           Peak Load




                                      (End of Appendix 1)




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                                                      APPENDIX 2

                            Adopted Enrollment Procedures for the Phase-In Period

        1. As described more fully below, the phase-in period will begin on April 11, 2010 (the
           “Effective Date”), and continue for four calendar years, with the annual limits on direct
           access (DA) load increases over the phase-in period as described in step 2 below, up to the
           maximum DA cap for each investor-owned utility’s (“IOU”) service territory (the DA cap).
           Any kilowatt-hours (kWh) not used in one year will be rolled over to the subsequent years as
           part of the cumulative increasing annual limits.
        2. The annual kWh limits are as follows:
                    Y1 (2010):       35% of the current room available under the DA cap.
                    Y2 (2011):       An additional 35% of the current room available under the cap
                                     (or70% of the available room under the DA cap).
                    Y3 (2012):       An additional 20% of the current room available under the cap
                                     (or 90% of the available room under the DA cap).
                    Y4 (2013):       An additional 10% of the current room available under the cap
                                     (or 100% of the available room under the DA cap).
        3. The same switching rules will apply to all customers eligible to switch to DA service under
           SB 695 (“DA-eligible customers”).
        4. To facilitate implementation as of the Effective Date, the IOU will notify all DA-eligible
           customers prior to the Effective Date of the terms and conditions for participation in the
           partial DA reopening under SB 695. Specifically, the IOU will use a bill insert or onsert1 to
           notify all DA-eligible customers as early as March 2010 to visit the IOU’s website for details
           on the partial DA reopening. The website will be updated to ensure accurate information
           based on the Commission’s final decision implementing the DA reopening.
        5. To facilitate implementation as of the Effective Date, an Open Enrollment Window (“OEW”)
           will be established as of the Effective Date, during which all DA-eligible customers will be
           allowed to submit a notice of intent (“NOI”)2 to transfer to DA service.


        1 A bill onsert is a message imprinted on the customer’s bill, as distinguished from a bill insert, which is

        a separate insertion included in the bill’s envelope. The bill onsert may be a more cost-effective way to
        provide customers notice of the partial DA reopening, because it can be included only on DA-eligible
        customers’ bills, and does not increase the weight of the bills (and thereby should not increase bill
        mailing costs).
        2 The parties will work together cooperatively in advance of the Open Enrollment Window to develop a

        uniform NOI in a timely fashion, which shall be filed as part of the IOUs’ advice letters implementing
        changes to their direct access tariffs in compliance with this decision. Customers wishing to authorize

                                                                                   Footnote continued on next page


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        6. The OEW will begin on the fifth business day after the Effective Date and end ninety (90)
           calendar days thereafter or on June 30, 2010, whichever comes first. The OEW will occur in
           Y1 of the phase-in period only.
        7. Enrollment during the OEW:
                a. A temporary, one-time waiver of the 6-month advance notice requirement for
                   all DA-eligible customers will be granted so that all DA-eligible customers
                   may begin to enroll in DA service as of the Effective Date if they wish to do
                   so, pursuant to the process described herein.
                b. A one-time waiver of the current Bundled Portfolio Service (“BPS”)
                   commitment periods (per Rule 25.1) will be granted so that all DA-eligible
                   customers may begin to enroll in DA service as of the Effective Date if they
                   wish to do so, pursuant to the process described herein.3
                c. All LSEs (those that currently serve load and those that do not) will file
                   forecasts of new customers that they expect to gain from via the OEW and
                   other periods for RA compliance years 2010 and 2011 according to the rule
                   set forth by Energy Division for the RA process. Energy Division will issue
                   an amended RA Guide and reporting template for 2010 compliance year as
                   well as an RA Guide and reporting template for 2011 compliance year.
                d. The IOU will begin accepting NOIs up to the Y1 limit as of 9:00 a.m. PST on
                   the fifth business day after the Effective Date. The methods for submitting
                   NOIs will be specified by each utility on its website, provided that all
                   methods shall allow for a time and date stamping to determine precedence.
                   The daily batch process for accepting NOIs during the OEW (described in
                   7.d below) will allow for up to a 10 percent (10%) threshold above the Y1
                   limit.
                e. The IOU will process NOIs in daily (12:00 a.m. to 11:59 p.m.) batches. Each
                   daily batch of NOIs will, within 20 days of its receipt, be accepted unless and
                   until the Y1 limit is reached. A daily batch that causes the Y1 limit to be
                   exceeded will nevertheless be accepted provided that such daily batch does
                   not exceed the Y1 limit by more than 10%. Should a daily batch cause the


        their ESP or other third party to submit the NOI on their behalf may do so by providing the IOU with a
        signed “Authorization to Receive Customer Information or Act on a Customer’s Behalf” (CISR) form,
        indicating that the ESP or other third party is authorized to “Request Rate Changes” for the customer.
        3
           The one-time waiver will apply to all non-residential customers under current BPS commitments, even
        if they do not elect to take DA service during the OEW. After the end of the OEW, these customers may
        elect DA service at any time with the required 6-month advance notice, assuming there is room under the
        annual limits or overall cap. However, the 3-year BPS commitment period will continue to apply anytime
        a DA customer returns to BPS.




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                    Y1 limit to be exceeded by more than 10%, NOIs in that particular daily
                    batch will be accepted on a first-come, first-served basis (based on the
                    date/time stamp of the NOI) up to the Y1 limit plus a threshold of no more
                    than 10%. All other NOIs in that particular daily batch will be rejected.44
                f. NOIs submitted during the OEW will be rejected only if the Y1 limit has
                   been reached. Any NOI that is found to have a deficiency (e.g., incorrect
                   service account number) will be accepted on the condition that it is corrected
                   by the customer within two business days after the IOU notifies the customer
                   of such deficiency. NOIs will be void in the event a Direct Access Service
                   Request (DASR) is not timely submitted, as described in 7.h below, or in the
                   event a deficiency in the NOI is not corrected by the customer within two
                   business days.
                g. For any NOI accepted during the OEW, the IOU will notify the customer of
                   NOI acceptance within 20 days of NOI receipt, and will instruct the customer
                   to notify its Electric Service Provider (ESP) that a DASR to switch
                   customer’s service account(s) to DA service must be submitted to the IOU
                   within 60 calendar days of the date the IOU’s notice of NOI acceptance is
                   sent to the customer.
                h. The customer will have 60 calendar days from the IOU’s notice of NOI
                   acceptance to cause its ESP to submit a DASR.5 DASRs will be processed
                   using existing processes and timelines in accordance with Rule 22 (or
                   equivalent rule),6 and eligible service accounts will be switched to DA
                   service on their next scheduled meter read date, or the date specified on the
                   DASR, if different from the next meter read date, depending on when the
                   IOU receives the DASR. Although Rule 22 (at Section E.18) allows the
                   IOU, the customer and the ESP to mutually agree to a different service
                   change date for the service changes requested in a DASR, the IOUs may be
                   unable to accommodate special service change dates during the OEW.


        4
          The threshold is only used for purposes of processing daily batches of NOIs. It is not intended as an
        increase in the annual limits.
        5
          In accordance with the IOUs’ current procedures, rejected DASRs must be corrected and resubmitted
        by the ESP and be acceptable to the IOU no later than 20 days following the conclusion of the 60-day
        period. DASRs not corrected by the ESP within this time period will be cancelled by the IOU.
        6
          The DA Rules for SDG&E are Rules 25 and 25.1. The IOUs’ DA Rules generally require that DASRs
        received by the OIU on or before the 15th of the month will be switched over no later than the next
        month’s scheduled meter reading date for that service account. Under SCE and SDG&E’s current DASR
        process, DASRs that are received by SCE or SDG&E five (5) business days before the customer service
        account’s next scheduled meter reading date will be switched over on its next scheduled meter reading
        date.




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                   Nothing in this Appendix 2 is intended to rescind Section E.18 of Rule 22;
                   however, it may not be operable during the OEW.
                i. If a DASR is not received by the IOU for an accepted NOI by the end of the
                   60-day period, the customer’s NOI will be void.
                j. Any NOIs voided for failure to submit a DASR within the 60-day period will
                   not be subject to a three-year minimum BPS commitment period as a result
                   such failure. This exception will apply only to NOIs accepted during the
                   OEW.
                k. If the Y1 limit is reached during the OEW, the IOU will stop accepting NOIs,
                   and will begin placing submitted NOIs on a wait-list on a first-come, first-
                   served basis. The wait-list shall have a maximum capacity equal to 25% of
                   the Y1 limit, and will be maintained until the last day of the OEW. Should
                   any room under the Y1 limit become available during the OEW as a result of
                   any voided NOIs, within one (1) business day of any room becoming
                   available, the IOU will notify eligible customers on the wait-list by email of
                   the acceptance of their NOIs. The IOU will continue to issue such email
                   notices, on a 1-business day basis as room becomes available during the
                   OEW, through the last day of the OEW. A customer coming off the OEW
                   wait-list will have 60 days after the IOU’s notice of the NOI acceptance to
                   cause its ESP to submit a DASR to the IOU. If a DASR is not received by
                   the IOU by the end of the 60-day period, the customer’s NOI will be void,
                   and the exception under Section 7.k for the three-year BPS commitment will
                   apply. The wait-list will end on the last day of the OEW. Any NOIs on the
                   wait-list that were not accepted during the OEW will be void, and customers
                   will be notified that they can begin submitting 6-month advance NOIs as
                   early as July 1, 2010 to switch to DA in 2011. No wait-list will be used after
                   the OEW.
                l. The OEW will close 90 calendar days after the Effective Date, or on June 30,
                   2010, whichever comes first. There will be no OEW in subsequent years of
                   the phase-in period.
                m. All LSEs that intend to serve load during 2011 will refile load forecasts for
                   2011 RA compliance year by May 26, 2010. This revised forecast shall
                   account both for customer migration up to that date, but also to forecast
                   expected customer migration during the second phase of DA access that
                   commences in January of 2011. The updated load forecasts due by May 26,
                   2010 will be used by the Energy Division and CEC to develop Local RA
                   obligations, inclusive of adjustments, as accurately as possible within the
                   constraints of the 2011 RA filing cycle.




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           8. Enrollment after the OEW closes:
                 a. In 2010:
                        Customers may submit 6-month advance NOIs starting July 1, 2010 to
                        switch to DA in 2011 (Y2). The IOU will accept 6-month advance NOIs
                        up to the Y2 limit. The daily batch process for accepting NOIs (described
                        in 7.d above) will allow for up to a 10 percent (10%) threshold above the
                        Y2 limit.
                        A customer with an accepted NOI will be switched to DA starting in
                        January 2011, provided the customer’s 6-month advance notice period has
                        been satisfied and a DASR has been timely received.
                        DASRs will be processed using existing processes and timelines in
                        accordance with Rules 22 and 22.1 (or equivalent rules), and eligible
                        service accounts will be switched to DA service on their next scheduled
                        meter read date, or the date specified on the DASR, if different from the
                        next meter read date, depending on when the IOU receives the DASR.
                        Customers who fail to meet the time limitations and DASR requirements
                        set forth in Rules 22 and 22.1 will be subject to a three-year minimum
                        BPS period as provided for in Rule 22.1 (or equivalent IOU rules).
                        Once the Y2 limit is reached, the IOU will stop accepting 6-month
                        advance notices.
                        If room under the Y2 limit subsequently becomes available, the IOU will
                        update its website to notify customers that it is accepting 6-month advance
                        notices. The IOU will use the same daily batch process described above
                        for accepting NOIs for any room under the Y2 limit.
                 b. In 2011:
                        Customers may continue to submit 6-month advance notices after January
                        1, 2011 to switch to DA in 2011 or 2012, depending on whether there is
                        room available under the Y2 limit. The IOU will accept 6-month advance
                        notices up to the Y3 limit. The daily batch process for accepting NOIs
                        (described in 7.d above) will allow for up to a 10 percent (10%) threshold
                        above the Y3 limit.
                        A customer with an accepted NOI will be switched to DA as soon as
                        possible (depending on whether there is room under the Y2 limit), but in
                        any event starting in January 2012, provided the customer’s 6-month
                        advance notice period has been satisfied and a DASR has been timely
                        received. If there is no room available under the Y2 limit, customers who
                        submit 6-month advance NOIs prior to July 2011 may need to remain on
                        bundled service for up to twelve months before being able to switch to
                        DA. In other words, they may have to wait for the Y3 allotment to open
                        up in January 2012 before they can switch to DA. If room under the Y2
                        limit subsequently becomes available in 2011, some customers may be

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                      able to switch to DA prior to 2012, provided the 6-month advance notice
                      period has been satisfied and a DASR has been timely received.
                      DASRs will be processed using existing processes and timelines in
                      accordance with Rules 22 and 22.1 (or equivalent rules), and eligible
                      service accounts will be switched to DA service on their next scheduled
                      meter read date, depending on when the IOU receives the DASR. A
                      customer failing to meet the time limitations and DASR requirements set
                      forth in Rules 22 and 22.1 will be subject to a three-year minimum BPS
                      period as provided for in Rules 22 and 22.1 (or equivalent rules).7
                      Once the Y3 limit is reached, the IOU will stop accepting 6-month
                      advance NOIs.
                      If room under the Y3 limit subsequently becomes available, the IOU will
                      update its website to notify customers that it is accepting 6-month advance
                      NOIs. The IOU will use the same daily batch process described above for
                      accepting NOIs for any room under the Y3 limit.
               c. In 2012 and 2013:
                      The IOU will use the same enrollment process as described above for
                      2011, using the applicable annual limits, except that a threshold for daily
                      batch processing will not apply to the Y4 limit (because it represents the
                      overall cap).
        9. During the phase-in period, the IOU will indicate on its public website whether NOIs (during
           OEW) or 6-month advance NOIs are being accepted, and update this information regularly,
           as reasonably necessary, but in no event less frequently than monthly. This information
           should be sufficient to inform customers and ESPs whether there is room available under the


        7 With the exception that customers who submit 6-month advance NOIs prior to July
        2011 may be required to remain on bundled service for longer than 6 months (but not
        more than 12 months) before switching to DA service, if there is no room under the Y2
        limit. In other words, they may have to wait for the Y3 allotment to open up in January
        2012 before they can switch to DA.




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            annual limits during the phase-in or the overall cap after the phase-in. The IOU will provide
            notice on its public website when the level of annualized sales for customers electing DA
            service approaches a certain percentage of the annual limit or overall cap (e.g., 95%).
        10. Changes in the 12-month usage of DA accounts will be reflected in order to determine the
            room available under the cap. No customer taking DA service while room was available
            under the cap will be removed from DA service as a result of growth in DA load.

                                              (End of Appendix 2)




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                                                 APPENDIX 3

                                    Adopted Temporary Treatment
                for Local Resource Adequacy Obligations During Direct Access Reopening


        We hereby adopt the methodology set forth below in order to fairly allocate local RA costs
        among LSEs during RA compliance year 2010:
        The first step in the methodology is to determine the size of the Local RA obligation associated
        with a migrating customer. The following calculation is suggested:
        Calculate a “Local to Peak Ratio” (LPR) for each IOU service territory. This ratio would be
        determined by taking the total Local RA obligation in the service area in MW, as adopted by the
        CPUC decision that established Local RA obligations for 2010, and then subtracting the Local
        MW that were allocated among all LSEs for Demand Response (DR), Cost Allocation
        Mechanism (CAM) resources, and RMR Condition 1 (RMR-1) resources. That number is then
        divided by the total forecasted 2010 coincident peak load in MW of that same IOU service
        territory (Service Area CPD) that was developed by the California Energy Commission for
        purposes of establishing 2010 RA obligations. This LPR would be expressed as a percentage.
        The LPR will be calculated by the CPUC Energy Division and posted to the CPUC website for
        each service territory alongside the amended 2010 RA Guide and Templates in April of 20101.
        When a customer seeks to migrate between LSEs after the date of DA reopening, a Customer
        Local (RA) Obligation (CLO) would be established for that customer, based on the customer's
        actual recorded Coincident Peak Demand (COPD) in MW at the time of the IOU service
        territory’s 2009 coincident system peak, grossed up by the appropriate Distribution Loss Factor
        (DLF) for the service area and multiplied by the LPR for the service territory in which the
        customer is located. The resulting figure would be the Local RA obligation of that customer in
        MW, the CLO. The LSE losing the load and the LSE receiving the load would stipulate to this
        figure, which would require only the data establishing the customer’s 2009 CPD at the time of
        the CAISO system peak.
        In mathematical terms:
               LPR = Total 2010 Service Area LCR in MW (less Local MW from DR, CAM, and
               RMR1 & 2)/ Forecasted Service Area 2010 CPD.
               CLO = LPR x Customer 2009 CPD.




        1
         RA compliance materials for 2008 through 2010 are posted to the CPUC website here:
        http://www.cpuc.ca.gov/PUC/energy/Procurement/RA/ra_guides_2008-09.htm




                                                        1




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        In order to simplify the process for this temporary and interim solution, the LSE gaining the
        additional load would have the option2 to obtain an allocation of Local RA “credits” from the
        LSE losing the load, without the need for any actual commercial sale of physical capacity to
        occur between the two LSEs. Rather, the LSE gaining the load would make a payment to the
        LSE losing the load, equal to the customer’s CLO times an administratively determined price in
        dollars per kilowatt-year (kW-yr) or kilowatt-month (kW-mo). This payment would be deemed
        to satisfy the acquiring LSE’s Local RA obligation for the remainder of the 2010 compliance
        year. LSE RA filings from both the LSE that lost the customer and the LSE that gained the
        customer would need to clearly indicate and highlight the exchange of customer MW and RA
        capacity if any transferred or sold directly to the other LSE. These rules and implementation
        procedures will be described in an amended RA Guide and Template for 2010 compliance year,
        and LSEs will be notified in April of 2010 of the new procedures and rules.
        No changes to the current RA compliance process would be required, except that both LSEs
        would report in their System RA monthly true-ups to Energy Division the amount of the Local
        RA obligation (the CLO) that was being transferred, and the acquiring LSE would also report the
        amount of the CLO being satisfied through the default transfer payment, as well as the amount of
        CLO that was being otherwise satisfied.3 The capacity that is transferred via the default
        mechanism would still be obligated by the RA Must-Offer Obligation (MOO) throughout the
        period in which it was originally shown in the year ahead filing, and the SC for the capacity
        would be required to demonstrate that in each monthly supply plan. Additionally, in the event
        that Local RA capacity is not sold to another LSE but is now in excess of the Local RA
        obligations of the original LSE, the original LSE would still be required to list the capacity to on
        its RA filing and that capacity would still be subject to the RA MOO via requirement to submit
        supply plans. LSEs are still under the obligation to demonstrate all Local RA capacity that they
        have under contract via RA Filings. The current process for monthly true-ups to LSEs’ System
        RA obligations would continue without change. All LSEs that expect to serve load during any
        month(s) are required to submit a monthly load forecast and System RA filing for each month
        that the LSE will serve load. Failure of an LSE to demonstrate that it has satisfied the CLO
        through a timely default transfer payment to the transferring LSE and/or through other means
        will result in a deficiency in the Local RA obligation of such LSE.
        Consistent with proposals in the current RA proceeding (R.09-10-032), in order to reduce
        administrative complexity, local true-ups shall be completed twice during 2010: once for August

        2
          If the LSE that was gaining the load (the acquiring LSE) can show that it already met some or all of its
        Local RA obligation with excess Local RA capacity or was able to obtain it from another source, the
        acquiring LSE would not be required to use this “default” option for some or all of its Local RA
        obligation. For purposes of these mid-year load migration adjustments only, LSEs gaining load may meet
        increased Local RA obligations in the PG&E service territory via procurement in either the Other PG&E
        Areas or in the Greater Bay Area, or any combination of the two. Similarly, the SCE service territory,
        procurement may be in either the LA Basin or in the Big Creek/Ventura area. Procurement adjustments
        in the SDG&E service territory must be in the San Diego Area.
        3
            See fn. 1, above.




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        and September, and a second time for October-December. For 2010 compliance year, the Local
        RA true-ups will be performed as follows: On May 31, LSEs (both LSEs that currently serve
        load and LSEs that assume load during the OEW) shall file their monthly load forecast
        adjustments for August compliance month pursuant to the current RA schedule. This filing for
        August will be used to establish adjusted Local RA obligations for LSEs for August and
        September, 2010. LSEs that do not currently serve load will be required to file with the CPUC
        and demonstrate RA capacity sufficient to meet their Local RA obligations gained from new
        customers. On August 2, LSEs will file load migration adjustments to establish Local RA
        obligations for the months of October, November, and December 2010.
        The default transfer payment would provide an administrative price for the transfer of Local RA
        credits of $24 per kW-year. This amount is intended to reflect only the “premium” value of
        Local RA capacity over System RA capacity, since the LSEs acquiring new load would still be
        purchasing any increased amount of System RA capacity required to be shown in its monthly
        System RA filing under the current RA load migration rules. Rather than a flat $2.00 per kW-
        month, the monthly prices would be “shaped” to reflect the fact that RA capacity is most
        valuable during the peak summer months. This shaping would spread the $24 over the months
        of the year based on the same factors (shown below) that were used to allocate capacity
        payments under the CAISO’s former Reliability Capacity Services Tariff program across the 12
        months of the year. In mathematical terms, the transfer payment would be determined as
        follows:
                       CLO x $24/kW-yr x Shaping Factor for remaining months of 2010.
        If, during the course of 2010, the new DA load subsequently switched to another LSE, the same
        process would be repeated again, and the new LSE would meet the CLO for the new DA load by
        either making a transfer payment to the prior LSE under the default mechanism or showing that
        it has obtained Local RA from another source.
        This temporary and interim solution shall explicitly apply only for calendar year 2010, and shall
        continue or be replaced as a result of whatever solution (if any) is adopted in R.09-10- 032 for
        the 2011 RA compliance year. If the LSE that was gaining the load already held excess Local
        RA capacity or was able to obtain it from another source, the acquiring LSE shall not be required
        to use this temporary and interim option, but shall still be required to make a true-up filing, even
        if there is no change. To facilitate a smoother synchronization between the phased reopening of
        DA and the annual RA schedule, the next step in the DA phase-in schedule shall occur on
        January 1, 2011 rather than April 11, 2011. The use of the January date would allow LSEs’
        year-ahead Local RA showings for 2011 to reflect any load migration that is expected to occur at
        the start of the next step of the DA reopening phase-in.
        In order to provide Energy Division and California Energy Commission with all necessary
        documentation for a transfer of local RA obligation, both the losing and gaining LSE shall
        provide the following information to the California Energy Commission and Energy Division at
        the time of the local true-ups: CLO for each customer gained and lost, documentation of
        customer transfer, default transfer payment amount (if a transfer payment has been made),
        identity (CAISO scheduling resource ID and MW amount) of any local RA capacity transferred,
        and any other information that may be required by Energy Division and California Energy


                                                         3




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           Commission to implement this methodology. Energy Division shall publish a template to
           facilitate this documentation.



                                             Monthly Shaping Factors

                                                 SP-15       NP-15/ZP-26
                                       Jan        6.7%            4.9%
                                       Feb        5.0%            4.9%
                                       Mar        5.0%            5.6%
                                       Apr        5.8%            4.6%
                                       May        6.3%            4.8%
                                       Jun        8.3%            5.1%
                                       Jul       15.8%           13.7%
                                       Aug       17.5%           15.3%
                                       Sep       11.7%           13.8%
                                       Oct        5.8%            8.7%
                                       Nov        6.3%            8.8%
                                       Dec        5.8%            9.8%




                                               (End of Appendix 3)




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       ALJ/MLC/jva                                                Mailed 11/21/2005



       Decision 05-11-009 November 18, 2005

           BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

           Order Instituting Rulemaking on policies and
           practices for advanced metering, demand                Rulemaking 02-06-001
           response, and dynamic pricing.                          (Filed June 6, 2002)



                            DECISION CLOSING THIS RULEMAKING
                            AND IDENTIFYING FUTURE ACTIVITIES
                              RELATED TO DEMAND RESPONSE

                This decision closes Rulemaking (R.) 02-06-001 as most of the activities
       identified in the proceeding have been completed. We identify additional
       activities necessary to ensure that our demand response programs provide full
       value to California ratepayers and establish a timetable for moving forward on
       those activities.

       1. Background
                We began this rulemaking1 in June 2002, as a policymaking forum to
       develop demand response as a resource to enhance electric system reliability,
       reduce power purchase and individual consumer costs, and protect the
       environment. The desired outcome of this effort was that a broad spectrum of
       demand response programs and tariff options would be available to customers
       who make their demand-responsive resources available to the electric system.


       1 The Commission’s rulemaking named as respondents the following investor owned
       utilities: Pacific Gas & Electric (PG&E), San Diego Gas & Electric (SDG&E), and
       Southern California Edison Company (SCE).



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              At the outset we recognized the need for a strategic approach to the
        orderly development of demand response capability in the California energy
        market. To that end, we coordinated this rulemaking with decision makers from
        the California Energy Commission (CEC), and previously, the California
        Consumer Power and Conservation Financing Authority (CPA), based on an
        interagency working model developed by the assigned Commissioner.2
              That model relied upon three working groups. The first, Working Group 1
        (WG1), comprised of agency decisionmakers (assigned Commissioner Michael
        Peevey, CEC Commissioner Arthur Rosenfeld, and CPA Director Sunne W.
        McPeak, also known as “the WG1 principals”), and supported by the assigned
        Administrative Law Judge (ALJ) and advisory staff from the CPUC and CEC,
        was responsible for shaping the rulemaking record by providing overall policy
        guidance to parties at key points in the proceeding. WG 1 focused its efforts on
        the development of a long-term vision for the development of demand
        responsiveness in California by setting a framework, developing goals, and
        focusing on how demand response can and should be integrated with the
        utilities’ overall procurement responsibilities.
              The second, Working Group 2 (WG2), is comprised of active parties who
        are interested in developing demand response programs for large customers
        (>200 kilowatt (kW)) in peak monthly demand). The meetings of this group are
        facilitated by agency staff supporting WG1 decision-making activities. The third,
        Working Group 3 (WG3), is comprised of active parties who are interested in
        developing demand response programs for small commercial/residential


        2See, Ruling Following Prehearing Conference, dated August 1, 2002; and Assigned
        Commissioner’s Ruling and Scoping Memo, dated August 16, 2002.




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        customers. Like WG2, the meetings of WG3 are facilitated by agency staff
        supporting WG1 decision-making activities.
              The first year of this proceeding resulted in adoption of two main
        decisions. The first (Decision (D.) 03-03-036) adopted the Statewide Pricing Pilot
        (SPP) which was designed to test the impact of time-of-use and critical peak
        pricing tariffs on residential and small commercial customer usage patterns on a
        pilot basis. The second (D.03-06-032) adopted demand response program plans
        for customers with load exceeding 200 kW and established annual megawatt
        (MW) targets to be met through demand response.
              On November 24, 2003, the Assigned Commissioner issued a scoping
        ruling for the second phase of this proceeding. The ruling set aside some issues
        for future proceedings and identified the following issues as the focus of Phase 2.

              • Analysis Framework for the Advanced Metering
                Infrastructure Business Case, Utilizing Utility, Customer
                and Societal Perspectives

              • AC Cycling as a Control Technology that Interfaces with
                AMI Elements

              • Real Time Pricing (RTP) Tariff Development

              • Ongoing Implementation Issues, specifically, resolution
                of:

                 (1) CPA/Demand Reserves Partnership (DRP)
                     program disputes between California Department
                     of Water Resources (DWR) and the utilities;

                 (2) delineated agricultural customer participation issues;
                     and

                 (3) delineated metering service “clean-up” issues.

              • A planning process for any near term adjustments in 2004
                goals as part of achieving 2007 demand response targets.

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               The rulemaking was also the forum for adoption of demand response
         budgets and program plans for 2004 and 2005.
               The various Working Groups assisted in developing program plans and
         budgets as well as evaluating the results of the programs. In particular, WG3’s
         Evaluation Subcommittee conducted numerous and extensive meetings
         concerning the proper methodology for analyzing the SPP results. The work of
         the evaluation subcommittee both contributed substantive to the final SPP
         Report issued by Charles River Associates as well as helped ensure broad
         support for the results of the consultant evaluation. This work is not reflected on
         the record as no reports were filed by the subcommittee or by WG3, but we note
         it here to recognize the efforts of all parties to assist in promoting demand
         response efforts outside of the formal Commission process.
         2. Other Proceedings Addressing Demand
            Response Efforts
               Over the course of approximately three years, we have made significant
         progress in advancing the agenda the initial rulemaking laid out on the program,
         pricing, and infrastructure fronts. The three utilities have filed applications for
         authorization of 2006-2008 demand response programs which are being handled
         in Application (A.) 05-06-006 et al. The Commission is considering adoption of
         critical peak pricing tariffs as a default for customers with demand exceeding
         200 kW (A.05-01-016 et al.). PG&E has requested authority to begin deployment
         of an advanced metering infrastructure in 2006 (A.05-06-028) and SDG&E seeks
         similar authority (A.05-03-015). SCE has proposed to develop an Advanced
         Integrated Meter to improve the cost-effectiveness of an advanced metering
         infrastructure for its ratepayers (A.05-03-026).




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                                             O R D E R

              IT IS ORDERED that:
           1. In the event that no Commission decision has been adopted in
        Application 05-06-006 et al by January 1, 2006, the utilities may carry over any
        2005 authorized funding to continue to offer 2005 programs until such time as a
        decision is adopted for 2006 programs.
           2. Southern California Edison Company’s October 6, 2005 motion is granted,
        Pacific Gas and Electric Company’s October 27, 2005 motion is granted, and
        transitional funding is extended to San Diego Gas & Electric Company.
           3. Each utility, as part of its next comprehensive rate design proceeding
        application following development and final implementation of an hourly day-
        ahead market price by the California Independent System Operator, shall submit
        a real time pricing tariff for its largest customers as part of its tariff offerings.
           4. Each utility, as part of its next comprehensive rate design proceeding
        application, shall also include proposals for critical peak pricing (CPP),
        time of use (TOU) and inverted rate tariffs (with an appropriate hedge) for small
        commercial and residential customers, as well as CPP and TOU tariffs for
        customers over 200 kilowatt in monthly demand.
           5. Non-experimental CPP tariff options for residential and small commercial
        customer classes shall be included by each utility in its next rate design
        application.
           6. The Executive Director shall explore opening a new rulemaking to develop
        more customer friendly billing formats for energy bills and report back to the
        Commission at the second business meeting in January 2006 on whether the
        Commission should open such a rulemaking, and if so, the schedule for
        presenting such a rulemaking to the Commission.


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           7. The Proposed Management Services Agreement between Pacific Gas and
        Electric Company and Conservation Financing Authority (CPA) that was filed on
        February 4, 2005, is not approved and CPA’s Fiscal Agent shall continue to
        manage the Demand Reserves Partnership program.
           8. By April 3, 2006, agency staff shall prepare a set of draft protocols for
        estimating load impacts for both price responsive and reliability demand
        response programs and a list of additional data that should be collected on
        program costs and incremental costs, including comfort changes or costs during
        curtailments.
           9. Agency staff shall serve the draft measurement and evaluation protocols
        on the service list to this proceeding, and any related or successor proceedings,
        and schedule a workshop for interested persons to provide peer review and
        feedback.
           10. Agency staff shall prepare a proposed rulemaking or recommend an
        alternative procedural approach for Commission consideration no later than
        six months after the draft measurement and evaluation protocols are circulated.
           11. Agency staff shall host a workshop by March 15, 2006, with the objective
        of designing a process to scope the issues that parties believe must be addressed
        in developing relevant cost-effectiveness tests for demand response programs
        and within two months after the workshop, shall recommend to the
        Commission’s Executive Director whether to open a new rulemaking to provide
        guidance on this topic, and if so, shall prepare a proposed rulemaking for
        consideration.
           12. The motion by USCL Corporation to add new minimum functionality
        criteria is denied.




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           13. The utilities should file a list of the completed research reports and one
        copy of any completed research reports that have not been filed within 10 days of
        the issuance of this decision.
           14. One copy of research reports on 2005 programs shall be filed in
        Rulemaking (R.) 02-06-001 within 10 days of completion. An electronic copy or
        notice of availability of each report shall be served on the service list to this
        proceeding, and any related or successor proceedings, like A.05-06-006 et al.
           15. One search reports on 2005 programs shall be filed in R.02-06-001 within
        10 days of their completion. An electronic copy or notice of availability of each
        report shall be served on the service list to this proceeding, and any related or
        successor proceedings.
           16. Docket Office shall not reopen R.02-06-001 as a result of the filing of the
        research reports referenced above.
           17. The utilities shall file a monthly report on interruptible load and demand
        response programs with the Director of the Energy Division.
           18. The utilities shall serve the monthly report on interruptible load and
        demand response programs on the service list to this proceeding, and any related
        or successor proceedings.
           19. The Energy Division Director shall cause the monthly report on
        interruptible load and demand response programs to be made available on the
        Commission’s website.




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         R.02-06-001 ALJ/MLC/jva


            20. To the extent that any motions remain outstanding, all such motions are
         denied.
            21. No hearing is necessary.
            22. Rulemaking 02-06-001 is closed.
               This order is effective today.
               Dated November 18, 2005, at San Francisco, California.


                                                         MICHAEL R. PEEVEY
                                                                   President
                                                         GEOFFREY F. BROWN
                                                         SUSAN P. KENNEDY
                                                         DIAN M. GRUENEICH
                                                         JOHN A. BOHN
                                                             Commissioners




                                                - 23 -




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       ALJ/DMG/hl2                                                      Mailed 4/16/2007




       Decision 07-04-043 April 12, 2007

        BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

       Application of San Diego Gas & Electric
       Company (U-902-E) for Adoption of an
       Advanced Metering Infrastructure Deployment            Application 05-03-015
       Scenario and Associated Cost Recovery and Rate         (Filed March 15, 2005)
       Design.




                          (See Appendix B for a list of appearances.)


          OPINION APPROVING SETTLEMENT ON SAN DIEGO GAS & ELECTRIC
           COMPANY’S ADVANCED METERING INFRASTRUCTURE PROJECT




       273744                                -1-




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        A.05-03-015 ALJ/DMG/hl2


                                                      TABLE OF CONTENTS

                                 Title                                                                                               Page

        OPINION APPROVING SETTLEMENT ON SAN DIEGO GAS &
        ELECTRIC COMPANY’S ADVANCED METERING INFRASTRUCTURE
        PROJECT ............................................................................................................................ 2
        1.   Summary................................................................................................................. 2
        2.   Background............................................................................................................. 3
             2.1    Commission Guidance............................................................................... 3
             2.2    Procedural History ..................................................................................... 6
        3.   Litigation Positions of Parties .............................................................................. 9
             3.1    SDG&E ......................................................................................................... 9
             3.2    DRA’s Position.......................................................................................... 11
             3.3    UCAN’s Position ...................................................................................... 12
        4.   Settlement Agreement ........................................................................................ 13
        5.   Burden of Proof.................................................................................................... 16
        6.   Functionality and Implementability ................................................................. 16
             6.1    Functionality ............................................................................................. 16
                     6.1.1 SDG&E’s Application ................................................................ 16
                     6.1.2 Functionality and the Settlement ............................................. 19
             6.2    Implementability ...................................................................................... 20
        7.   Cost Effectiveness – SDG&E’s Application ..................................................... 21
             7.1    Comparison Exhibit ................................................................................. 22
             7.2    Financial Modeling Methodology.......................................................... 25
                     7.2.1 Discount Rate and Present Value Method.............................. 25
                     7.2.2 Timeframe of Analysis: 17 Years.............................................. 25
             7.3    Project Costs .............................................................................................. 32
                     7.3.1 RFP Specifications ...................................................................... 32
                     7.3.2 Meter and Communications Systems...................................... 35
                     7.3.3 Risk Sharing................................................................................. 38
                     7.3.4 Adopted Cost Estimate.............................................................. 38
             7.4    Operational Benefits................................................................................. 39
                     7.4.1 Meter Reading Benefits.............................................................. 40
                     7.4.2 Other Operational Benefits ....................................................... 41
             7.5    DR Impacts and Benefits ......................................................................... 43
                      7.5.1 Residential Customers ............................................................... 44
                      7.5.2 Small and Medium Commercial and Industrial
                                  Customers .................................................................................... 54


                                                                        -i-




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         A.05-03-015 ALJ/DMG/hl2


                        7.5.3 Large Commercial and Industrial Customers........................ 56
                   7.6Avoided Capacity Cost............................................................................ 57
                   7.7Benefits from Avoided DR Program Costs........................................... 64
                   7.8Information Feedback Systems Benefits ............................................... 70
                   7.9Non-Quantifiable and Newly Quantifiable Benefits .......................... 70
                       7.9.1 Implementation of Time Differentiated Rates........................ 71
                       7.9.2 Improved Public Safety ............................................................. 72
                       7.9.3 Environmental............................................................................. 72
                       7.9.4 Enabling Technologies Advancements/Deployments.............. 73
                       7.9.5 Smart Grid ................................................................................... 74
         8.    SDG&E’s AMI Application is Not Cost-Effective........................................... 74
         9.    Alternative AMI Program Options ................................................................... 76
               9.1    December 15, 2006 ALJ Ruling and Comments................................... 76
               9.2    SDG&E AMI Alternative Proposal ........................................................ 78
               9.3    UCAN Alternative.................................................................................... 79
               9.4    Technological Improvements ................................................................. 82
         10.   Analysis of the Settlement Agreement............................................................. 84
               10.1 Cost-Effectiveness of the Settlement Agreement................................. 84
               10.2 Reasonableness of the Settlement Agreement ..................................... 86
                      10.2.1 Does the Settlement Agreement Include Sufficient
                                    Information to Determine its Overall Reasonableness? ....... 86
                      10.2.2 Is the Settlement Agreement Reasonable in Light of the
                                    Whole Record? ............................................................................ 87
                      10.2.3 Is the Settlement Agreement Consistent With the Law? ......... 88
                      10.2.4 Is the Settlement Agreement in the Public Interest?................. 88
         11.   Comments on Proposed Decision ..................................................................... 89
         12.   Assignment of Proceeding ................................................................................. 89
         Findings of Fact............................................................................................................... 89
         Conclusions of Law ........................................................................................................ 93
         ORDER ............................................................................................................................. 95

         APPENDIX A – Settlement Agreement
         APPENDIX B – List of Appearances




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         A.05-03-015 ALJ/DMG/hl2


           OPINION APPROVING SETTLEMENT ON SAN DIEGO GAS & ELECTRIC
            COMPANY’S ADVANCED METERING INFRASTRUCTURE PROJECT

         1. Summary
               This decision approves a settlement among San Diego Gas & Electric
         Company (SDG&E), the Division of Ratepayer Advocates (DRA) and Utility
         Consumers’ Action Network (UCAN) to allow $572 million for SDG&E’s
         proposed Advanced Metering Infrastructure (AMI) Project from 2007 through
         2011. We find that there are between $40 million and $51 million in net benefits
         for the Settlement Agreement.
               In this decision, we analyze the Settlement Agreement in light of the
         litigation positions of the parties in order to consider its reasonableness. We find
         the Settlement Agreement to be reasonable in light of the whole record,
         consistent with the law, and in the public interest.
               This decision is part of our effort to transform California’s investor-owned
         utility distribution network into an intelligent, integrated network enabled by
         modern information and control system technologies. SDG&E’s deployment is
         scheduled to begin in mid-2008. From 2008 through 2010, SDG&E will install
         approximately 1.4 million new, AMI-enabled, solid state electric meters and
         900,000 AMI enabled gas modules that can, among other things, measure energy
         usage on a time-differentiated basis. The deployment will improve customer
         service by providing customer premise endpoint information, assist in gas leak
         and electric systems outage detection, transform the meter reading process and
         provide real near-term usage information to customers. AMI will also support
         such technological advances as in-house messaging displays and smart
         thermostat controls.




                                                 -2-




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         A.05-03-015 ALJ/DMG/hl2




                                            O R D E R

               IT IS ORDERED that:
            1. The February 9, 2007 Settlement Agreement Regarding San Diego Gas &
         Electric Company’s (SDG&E) Advanced Metering Infrastructure (AMI)
         Application (A.), A.05-03-015 (Appendix A herein), among SDG&E, the Division
         of Ratepayer Advocates and Utility Consumers’ Action Network is adopted,
         subject to Commission review of contracts executed with vendors, as set forth in
         Ordering Paragraph 2.
            2. SDG&E shall file one or more Advice Letters with the executed contracts
         with vendors for its AMI Project, as adopted herein. These contracts are
         contingent upon Commission approval that they meet the functionality criteria
         set forth in the Joint Assigned Commissioner and Administrative Law Judge’s
         Ruling Providing Guidance for the AMI Business Case Analysis issued
         February 19, 2004 in Rulemaking 02-06-001.
            3. SDG&E shall consult with the Commission’s Energy Division to determine
         what information SDG&E shall provide in its quarterly reports to the Energy
         Division on AMI implementation progress, which reports are the subject of
         paragraph 9 of the Settlement Agreement.
            4. SDG&E shall work with the other major California utilities to strive for
         statewide, clearly defined and commercially available open standards for Home
         Area Network (HAN) communications systems.
            5. SDG&E shall establish the Advanced Metering Infrastructure Balancing
         Account (AMIBA) by an advice letter no later than 30 days from the effective
         date of this decision, and record costs up to $617 million.



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         A.05-03-015 ALJ/DMG/hl2


            6. SDG&E is authorized to book shareholder rewards or costs in its Reward
         and Penalties Balancing Account (RPBA) up to a maximum of $5 million.
            7. A.05-03-015 is closed.
               This order is effective today.
               Dated April 12, 2007, at San Francisco, California.


                                                         MICHAEL R. PEEVEY
                                                                    President
                                                         DIAN M. GRUENEICH
                                                         JOHN A. BOHN
                                                         RACHELLE B. CHONG
                                                         TIMOTHY ALAN SIMON
                                                                  Commissioners




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                                                            Original   Cal. P.U.C. Sheet No.                   21848-E
          San Diego Gas & Electric Company
                San Diego, California          Canceling               Cal. P.U.C. Sheet No.

                                                 SCHEDULE RES-BCT                                              Sheet 1        N
              LOCAL GOVERNMENT RENEWABLE ENERGY SELF-GENERATION BILL CREDIT TRANSFER                                          N

        APPLICABILITY                                                                                                         N
                                                                                                                              |
        Pursuant to California Public Utilities Code (PU Code) Section 2830, this schedule is optionally available to         |
        bundled service Local Government (as defined in Special Condition (SC 2) customers using an Eligible                  |
        Renewable Generating Facility (as defined in the SC 3) who have timely submitted a completed Generation               |
        Bill Credit Transfer Allocation Request Form to the Utility.                                                          |
                                                                                                                              |
        This schedule will be available to eligible customers, upon request, on a first-come-first-served basis, until        |
                                                                                                                              |
        the combined rated generating capacity of Eligible Renewable Generating Facilities within SDG&E’s service             |
        territory reaches SDG&E’s share of 8.1% of the statewide 250 megawatts (MW) limitation, based on the ratio            |
        of SDG&E’s peak demand to the total peak demand of all electrical corporations within the State of                    |
        California.                                                                                                           |
                                                                                                                              |
        This schedule will become effective no sooner than 120 days from the date the first request for service under         |
        this schedule has been received by the Utility.                                                                       |
                                                                                                                              |
        Service under this schedule shall not be provided in combination with the Level Pay Plan option set forth in          |
        Rule 9.                                                                                                               |
                                                                                                                              |
                                                                                                                              |
        TERRITORY                                                                                                             |
                                                                                                                              |
        Within the entire territory served by SDG&E.                                                                          |
                                                                                                                              |
                                                                                                                              |
        RATES                                                                                                                 |
                                                                                                                              |
                                                                                                                              |
        Only the energy charge rate component of the Generating Account’s (as defined in SC 4) electric energy
                                                                                                                              |
        commodity rate schedule shall be used in the calculation of credits to be applied under this schedule.                |
                                                                                                                              |
        Costs associated with billing system modifications required for the development and implementation of                 |
        Schedule RES-BCT will be recovered from participating customers through a fixed monthly charge of $30                 |
        per month and a one-time set-up fee of $500 per Generating Account.                                                   |
                                                                                                                              |
        SPECIAL CONDITIONS                                                                                                    |
                                                                                                                              |
                                                                                                                              |
        1. Definitions: The Definitions of terms used in this schedule are found either herein or in Rule 1.                  |
                                                                                                                              |
        2. Local Government: Per PU Code § 2830, means a city, county, (whether general law or chartered, city                |
           and county), special district, school district, political subdivision, or other local public agency, if            |
           authorized by law to generate electricity, but shall not mean a joint powers authority, the state or any           |
           agency or department of the state, other than an individual campus of the University of California or the          |
           California State University.                                                                                       |
                                                                                                                              |
                                                                                                                              N




                                                             (Continued)
        1C9                                                   Issued by                   Date Filed           May 3, 2010
        Advice Ltr. No.    2092-E-A                        Lee Schavrien                  Effective            Apr 22, 2010
                                                        Senior Vice President
        Decision No.                                     Regulatory Affairs               Resolution No.            E-4283




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                                                               Original   Cal. P.U.C. Sheet No.                     21849-E
          San Diego Gas & Electric Company
                San Diego, California             Canceling               Cal. P.U.C. Sheet No.

                                                    SCHEDULE RES-BCT                                                Sheet 2        N
               LOCAL GOVERNMENT RENEWABLE ENERGY SELF-GENERATION BILL CREDIT TRANSFER                                              N

        SPECIAL CONDITIONS (Continued)                                                                                             N
                                                                                                                                   |
        3. Eligible Renewable Generation Facility: An electric generation facility that meets all of the following                 |
           criteria:                                                                                                               |
                                                                                                                                   |
              a) is a generation facility with a generating capacity of not more than one megawatt;                                |
                                                                                                                                   |
              b) is located within the geographical boundaries of the Local Government customer;                                   |
                                                                                                                                   |
                                                                                                                                   |
              c) is owned, operated, or located on property under the control of the Local Government customer.
                                                                                                                                   |
                 Under circumstances when a Local Government customer is a lessee in a lease agreement, leased                     |
                 property within the geographical boundaries of the Local Government customer shall be considered                  |
                 under the control of the Local Government customer;                                                               |
                                                                                                                                   |
              d) is sized to offset all or part of the electrical load of the Generating Account(s); and                           |
                                                                                                                                   |
              e) is interconnected and operates in parallel with Utility’s transmission and distribution systems.                  |
                                                                                                                                   |
              Eligible generators utilized to receive service under the terms of this rate schedule shall be in compliance         |
              with SDG&E’s Electric Rule 21, Interconnection Standards for Non-Utility Owned Generation. Eligible                  |
              generators participating on this schedule are not eligible for service under Schedule NEM, Net Energy                |
              Metering.                                                                                                            |
                                                                                                                                   |
        4. Generating Account: The SDG&E electricity billing account at the location of the Eligible Renewable                     |
           Generation Facility served under a time-of-use (TOU) rate schedule with bills rendered in the name of                   |
           the Local Government customer. Generating accounts will be allowed to take service under Schedule                       |
           DG-R and would be eligible to participate in a Critical Peak Pricing service                                            |
                                                                                                                                   |
        5. Benefiting Account: Per PU Code 2830, means an SDG&E electric billing account, or more than one                         |
           account, located within the Local Government customer’s geographical boundaries that is mutually                        |
                                                                                                                                   |
           agreed upon by the Local Government customer and the Utility and served under a TOU rate schedule
                                                                                                                                   |
           with bills rendered in the name of Local Government customer, or for a campus, within the geographical
                                                                                                                                   |
           boundary of the city, county, or city and county in which the campus is located. The number of                          |
           Benefiting Accounts is limited to 50 and they will be allowed to participate in a Critical Peak Pricing                 |
           service. Benefiting accounts will not automatically be eligible to receive service under Schedule DG-R,                 |
           unless the Benefiting Account is already a host facility to a distributed generation project.                           |
                                                                                                                                   |
        6. Local Government Customer Responsibility: In order to commence service under this schedule, the                         |
           Utility must be in receipt of a Generation Credit Allocation Request Form (form 142-0546) at least 60                   |
           days prior to the Eligible Renewable Generation Facility becoming operational. In addition, the Local                   |
           Government customer shall have paid all costs associated with the Utility installing a meter capable of                 |
           recording net generation output in 15-minute intervals, any wiring, trenching, conduit, or other facility               l
           costs incurred by the Utility to interconnect with the customer’s generator, adjusted based on Rule 2                   l
           factors for a one-time payment. The location(s) of the customer’s generator output metering equipment                   |
           shall be approved by the Utility.                                                                                       N




                                                                (Continued)
        2C8                                                      Issued by                   Date Filed             May 3, 2010
        Advice Ltr. No.     2092-E-A                          Lee Schavrien                  Effective              Apr 22, 2010
                                                           Senior Vice President
        Decision No.                                        Regulatory Affairs               Resolution No.              E-4283




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                                                              Original   Cal. P.U.C. Sheet No.                    21850-E
          San Diego Gas & Electric Company
                San Diego, California            Canceling               Cal. P.U.C. Sheet No.

                                                   SCHEDULE RES-BCT                                               Sheet 3       N
               LOCAL GOVERNMENT RENEWABLE ENERGY SELF-GENERATION BILL CREDIT TRANSFER                                           N

                                                                                                                                N
        SPECIAL CONDITIONS (Continued)                                                                                          |
                                                                                                                                |
        7. Local Government - Generation Bill Credit Transfer Allocation Request Form: Form 142-0546, completed                 |
           by the Local Government customer, designates how the Power Delivered (as defined in SC 8.a.) will be                 |
           allocated amongst the customer’s Benefiting Accounts, up to a maximum of 50 accounts. The form must                  |
           be received by the Utility at least 60 days prior to the regularly scheduled meter reading date of the               |
           Generating Account that the customer elects to begin receiving service under this schedule. The                      |
           customer-designated allocation will become effective on the designated Generating Account’s scheduled                |
                                                                                                                                |
           meter reading date and shall remain in effect for a minimum of twelve monthly billing periods. The
                                                                                                                                |
           customer may submit an updated form any time thereafter. Modified forms must be received by the Utility
                                                                                                                                |
           at least 60 days prior to when a reallocation of Power Delivered becomes effective and shall remain                  |
           effective for at least twelve billing periods from the effective date. Local Government customers                    |
           requesting to terminate service under this rate schedule shall provide written notice to the Utility, which          |
           must be received by the Utility at least 60 days in advance of such termination.                                     |
                                                                                                                                |
        8. Billing Process: The following billing process shall be used.                                                        |
                                                                                                                                |
              a) Power Delivered: The Power Delivered is the metered output measured in kilowatt-hours, exported                |
                 to the grid, as recorded by the net generator output meter and validated by the appropriate Utility            |
                 billing processes during the specific billing period.                                                          |
                                                                                                                                |
              b) Credits: The monetary value of credits provided under this schedule will be calculated by multiplying          |
                 the Power Delivered by the appropriate TOU energy charge component of the Generating Account’s                 |
                 electric energy commodity rate schedule, as determined by the discrete TOU period during which the             |
                 Power Delivered was produced and exported to the grid.                                                         |
                                                                                                                                |
              c) Allocation of Credits: A Benefiting Account Relevant Period is a twelve-month period, or portion               |
                 thereof, corresponding to that of the Generating Account Relevant Period. However, due to possible             |
                 differences in billing (and meter read) cycles, the Generating Account Relevant Period may lag in              |
                 time behind the Generating Account Relevant Period by any number of days up to one full billing                |
                                                                                                                                |
                 cycle.
                                                                                                                                |
                                                                                                                                |
                  For the purpose of applying Bill Credit, the Bill Credit Relevant Period ends at the same time as the         |
                  Benefiting Account Relevant Period (noted in the Generation Bill Credit Transfer Allocation Request           |
                  Form (142-0546)), that is lagging the most behind the Generating Account Relevant Period, up to               |
                  one Billing Cycle.                                                                                            |
                                                                                                                                |
                  For a new Benefiting Account Credit arrangement, the initial Benefiting Account Relevant Period for           |
                  a Benefiting account that does not have the same Billing Cycle as the Generating Account, will start          |
                  its Relevant period at the start of its first full billing cycle that falls after that of the Generating      |
                  Account. During the less-than-one-full billing-cycle period between the start of the Generating               |
                  Account’s Relevant Period and that of the Benefiting account, no bill credit will be applied to that          |
                  Benefiting Account’s usage. (The Benefiting Account’s normal Relevant period will still consist of a          |
                  twelve-month period, it just starts with the first full bill cycle.)                                          N




                                                               (Continued)
        3C8                                                     Issued by                   Date Filed            May 3, 2010
        Advice Ltr. No.    2092-E-A                          Lee Schavrien                  Effective            Apr 22, 2010
                                                          Senior Vice President
        Decision No.                                       Regulatory Affairs               Resolution No.             E-4283




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                                                               Original   Cal. P.U.C. Sheet No.                   21851-E
             San Diego Gas & Electric Company
                   San Diego, California          Canceling               Cal. P.U.C. Sheet No.

                                                    SCHEDULE RES-BCT                                              Sheet 4       N
                LOCAL GOVERNMENT RENEWABLE ENERGY SELF-GENERATION BILL CREDIT TRANSFER                                          N

        SPECIAL CONDITIONS (Continued)                                                                                          N
                                                                                                                                |
        8. Billing Process:                                                                                                     |
                                                                                                                                |
                   Credits will first be applied to the Generating Account up to the amount of the current electric energy      |
                   commodity charges. The remaining credits shall then be allocated to the Benefitting Account(s)               |
                                                                                                                                |
                   based on whole percentages provided by the Local Government – Generation Bill Credit Transfer
                                                                                                                                |
                   Allocation Request Form on file with the Utility up to a maximum of 50 Benefiting Accounts. The
                                                                                                                                |
                   process of allocating credits shall commence on the effective date of the Generation Bill Credit             |
                   Transfer Allocation Request Form (form 142-0546) and shall continue for 12 consecutive billing               |
                   periods (Relevant Period). Credits remaining at the end of the Relevant Period will be applied               |
                   toward remaining eligible commodity charges on the Benefiting Account(s) or to offset customer               |
                   payments applied toward commodity charges during the Relevant Period. Any remaining credit shall             |
                   be reset to zero. Each subsequent 12-month period of service under this schedule shall be                    |
                   considered a new Relevant Period.                                                                            |
                                                                                                                                |
               d) Benefiting Account Bill: A Benefiting Account served under this schedule is responsible for all               |
                  charges billed under its OAS including monthly billed minimum charges, customer charges, meter                |
                  chargers, facilities charges, and energy and demand charges. Applicable demand charges are                    |
                  defined in the OAS. Credits applied on a monthly basis to a Benefiting Account shall not exceed the           |
                  electric energy commodity charges incurred during the specific billing period.                                |
                                                                                                                                |
               e) Generating Account Bill: A Generating Account served under this schedule is responsible for all               |
                  charges billed under its OAS including monthly billed minimum charges, customer charges, meter                |
                  chargers, facilities charges, energy and demand charges. Applicable demand charges are defined in             |
                  the OAS. Credits applied on a monthly basis to a Generating Account shall not exceed the electric             |
                  energy commodity charges incurred during the specific billing period.                                         |
                                                                                                                                |
                                                                                                                                |
        9.     Interconnection: Prior to Parallel Operation, the Local Government customer must execute and comply
                                                                                                                                |
               with the applicable Utility Interconnection Agreement. The Eligible Renewable Generation Facility shall
                                                                                                                                |
               comply with all of SDG&E’s tariffs, including but not limited to SDG&E’s Rule 21, and any other                  |
               regulations and laws governing the interconnection of the Eligible Renewable Generating Facility.                |
                                                                                                                                |
        10. Generator Limitation: No generator shall be included behind a Net Generator Output Meter recognized                 |
            by this rate schedule other than an RPS eligible generator.                                                         |
                                                                                                                                |
        11. Renewable Energy Credits (RECs): Any RECs would remain with the owner pursuant to Section 2827 of                   |
            the Public Utilities Code.                                                                                          N




        4C8                                                      Issued by                   Date Filed           May 3, 2010
        Advice Ltr. No.       2092-E-A                        Lee Schavrien                  Effective           Apr 22, 2010
                                                          Senior Vice President
        Decision No.                                       Regulatory Affairs                Resolution No.            E-4283




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                                                             Revised    Cal. P.U.C. Sheet No.                       21362-E
         San Diego Gas & Electric Company
               San Diego, California            Canceling    Revised    Cal. P.U.C. Sheet No.                       21142-E

                                                      SCHEDULE NEM                                                 Sheet 1
                                                   NET ENERGY METERING


       APPLICABILITY

       Pursuant to California Public Utilities Code (PU Code) Section 2827, this schedule is applicable to a
       residential, small commercial (as defined in subdivision (h) of Section 331 of the PU Code), commercial,
       industrial, or agricultural customer who uses a solar or wind turbine electrical generating facility, or a hybrid
       system of both, with a capacity of not more than 1,000 kilowatts (kW) that is located on the customer’s
       owned, leased, or rented premises, is interconnected and operates in parallel with the Utility’s transmission
       and distribution systems, and is intended primarily to offset part or all of the customer’s own electrical
       requirements (hereinafter “eligible customer-generator” or “customer”). Certain incremental billing and
       metering costs set forth in this schedule that are related to net energy metering are applicable to Energy
       Service Providers (ESPs) serving eligible customer-generators.

       This service is not applicable to a Direct Access (DA) customer where the customer’s ESP does not offer a
       net energy metering tariff. In addition, if an eligible customer-generator participates in direct transactions
       with an electric provider that does not provide distribution service for the direct transactions, the electric
       provider, and not the Utility, is obligated to provide net energy metering to the customer (also see Special
       Condition 3.e).

       Pursuant to Decision 08-02-002 and notwithstanding all applicable terms and conditions contained herein, to
       the extent a Community Choice Aggregator offers a net energy metering tariff, Utility shall provide applicable
       NEM services under this schedule to an eligible CCA customer-generator consistent with services provided
       to its bundled service eligible customer-generators. As a condition of receiving service under this schedule,
       the CCA shall be responsible for timely providing the applicable generation-related bill charges or credits for
       each CCA customer-generator to the utility. Each eligible CCA customer-generator shall look to its CCA for
       NEM services related to the electric generation charges and credits that result from receiving services under
       this schedule. The CCA shall also be responsible for the applicable generation-related bill credit structure
       associated with this service option and providing the CCA customer-generator with the applicable
       generation-related bill credit.

       This schedule shall be available to eligible customer-generators, upon request, on a first-come-first-served
       basis until the time that the total rated generating capacity used by both NEM and VNM-A eligible customer-
       generators exceeds 2.5% of SDG&E’s aggregate customer peak demand.

       Schedule NEM applies also to specified Net Energy Metering eligible (NEM-eligible) generators in a
       Generating Facility comprised of multiple NEM- and non-NEM-eligible generators, served through the same
       Point of Common Coupling (PCC), where the NEM-eligible generating capacity is not more than 1 MW. Such
       facilities will be referred to as Multiple Tariff Facilities, and any group of generators within such a facility that
       are subject to the same tariff provisions for billing and metering purposes will be referred to as a Constituent
       Generator Group. In order to be eligible for this rate schedule in a Multiple Tariff Facility, the customer-
       generator must meet all the requirements of Special Condition 7 for the schedule NEM-eligible generator,
       and must also meet any other applicable tariffs. Customer-generator must also complete a Generating
       Facility Interconnection Agreement (Multiple Tariff) (Form 117-2160).

       Due to the complexity of Multiple Tariff Facilities NEM-eligible generators interconnecting under the
       provisions of Special Condition 7 may require additional review and/or interconnection facilities and other
       equipment, and may incur interconnection costs, as provided for in electric Rule 21.

       As of January 1, 2010, a Customer who owns, rents or leases a premises that includes solar and/or wind                     N
       turbine electrical generating facilities, or a hybrid of both with a capacity of 30kW or less, that were previously
       approved by SDG&E for NEM interconnection prior to the Customer moving in and/or taking electric service
       with SDG&E (Change of party Customer) will take service on this tariff as long as the requirements of this
       section are met.                                                                                                           N

                                                              (Continued)
       1C19                                                    Issued by                    Date Filed            Sep 25, 2009
       Advice Ltr. No.    2111-E                            Lee Schavrien                   Effective              Oct 25, 2009
                                                         Senior Vice President
       Decision No.                                       Regulatory Affairs                Resolution No.




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                                   Pages 87 of 375
                                              San Diego Gas & Electric Company
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                                                               Revised    Cal. P.U.C. Sheet No.                   21363-E       *
         San Diego Gas & Electric Company
               San Diego, California             Canceling     Revised    Cal. P.U.C. Sheet No.                   20442-E

                                                       SCHEDULE NEM                                               Sheet 2
                                                    NET ENERGY METERING


       APPLICABILITY (Continued)

       To be eligible, the Change of party Customer must: 1) ensure that the generating facility is compliant with all          N
       applicable safety and performance standards as delineated in SDG&E’s Electric Rule 21 and other
       applicable tariffs; 2) keep in force the amount of property, commercial general liability and/or personal liability
       insurance the Change of party Customer has in place at the time they initiate service on this tariff; 3)
       understand that SDG&E may from time to time release to the California Energy Commission and/or the
       California Public Utilities Commission, information regarding the Change of party Customer’s facility,
       including Change of party Customer’s name and Generating Facility location, capacity and operational
       characteristics.

       Change of party Customers making any modification to previously approved SDG&E NEM solar and/or wind
       turbine electrical generating facilities are not eligible for this provision and must complete the interconnection
       process in Special Condition 4 of this tariff.

       Change of party Customers also must agree to comply with all rules and requirements of SDG&E’s Net
       Energy Metering tariffs.

       When the builder/developer of a subdivision sells a new home during the NEM application process, after the
       builder/developer completes the Net Energy Metering Application and Interconnection Agreement for
       Customers with Solar and/or Wind Generating Facilities of 30kW or Less (Form 142-02765) and otherwise
       meets all of SDG&E’s requirements for the NEM interconnection, but prior to SDG&E providing final written
       approval for Parallel Operation on Schedule NEM, SDG&E may treat the new home owner/Customer as a
       Change of party Customer, as defined above.

       TERRITORY                                                                                                                N

       Within the entire territory served by the Utility.                                                                       L

       RATES

       All rates charged on this schedule will be in accordance with the eligible customer-generator’s otherwise
       applicable metered rate schedule (OAS). An eligible customer-generator served under this schedule is
       responsible for all charges from its OAS including monthly billed minimum charges, customer charges, meter
       charges, facilities charges, energy and demand charges, and excluding any adjustments due to power factor
       provisions. Applicable demand charges are defined in the OAS.

       Customers eligible for service under this schedule are not required to take service under Schedule S,
       Standby Service, or Schedule S-I, Standby Service-Interruptible, for the qualifying generators. Multiple Tariff
       Facilities that are interconnected under the terms of Special Condition 7 may be subject to the requirements
       of Schedule S or S-I. To the extent that charges for transmission and distribution services are recovered
       through demand charges in any billing period, no standby charges shall apply in that monthly billing cycle,
       except Multiple Tariff Facilities interconnected under the terms of Special Condition 7 may be subject to the
       requirements of Schedules S or S-I.

       The charges and credits for Multiple Tariff Facilities taking service on this rate schedule under the provisions
       of Special Condition 7 will be calculated using the OAS identified by the eligible NEM customer-generator in
       its application for interconnection and its interconnection agreement with SDG&E or as subsequently
       changed by the eligible NEM customer-generator in accordance with SDG&E’s Electric Rule 12.
                                                                                                                                L


                                                                (Continued)
       2C20                                                      Issued by                   Date Filed          Sep 25, 2009
       Advice Ltr. No.    2111-E                             Lee Schavrien                   Effective           Oct 25, 2009
                                                            Senior Vice President
       Decision No.                                          Regulatory Affairs              Resolution No.




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                                   Pages 88 of 375
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                                                 Non-Shared Service Workpapers




                                                                Revised     Cal. P.U.C. Sheet No.                      21364-E
             San Diego Gas & Electric Company
                   San Diego, California           Canceling    Revised     Cal. P.U.C. Sheet No.                    20172-E **

                                                         SCHEDULE NEM                                                  Sheet 3
                                                      NET ENERGY METERING


        RATES (Continued)
                                                                                                                                     L
        Customer-generators with Multiple Tariff Facilities with existing NEM, NEM-BIO and/or NEM-FC eligible
        generators interconnecting additional generators, will receive a bill true-up prior to taking service under
        Special Condition 7. This ensures that all NEM accounts have the same Relevant Period, as defined in
        Special Condition 3, going forward.

        All NEM-eligible customer-generators are responsible for Public Purpose Program (PPP) charges based on
        the net energy delivered by the Utility.

        SPECIAL CONDITIONS

        1.      Definitions: The definitions of terms used in this schedule are either found herein or in Rule 1, Rule
                21, or the customer’s OAS.

                a.   Wind Energy Co-Metering Facility: Any wind energy generating facility greater than 50 kW, but
                     not exceeding 1,000 kW, where, as determined by the rates set forth in the customer’s OAS, only
                     the monthly value of the generation component of the electric energy supplied through the
                     electric grid may be offset by the monthly value of the generation component of the electric
                     energy generated by an eligible customer-generator and fed back to the electric grid over a 12-
                     month period.

                b.   Otherwise Applicable Schedule: The NEM-eligible customer-generator’s regularly filed rate
                     schedule under which service is rendered.                                                                       L

        2.      Metering Equipment: Eligible Wind Energy Co-Metering customer-generators, see Special Condition
                6. Multiple Tariff Facilities will be metered under one of the options in Special Condition 7. All other
                Net Energy Metering shall be accomplished using a single meter capable of registering the flow of
                electricity in two directions. If the eligible customer-generator’s existing electrical meter is not capable
                of registering the flow of electricity in two directions, the eligible customer-generator shall be
                responsible for all expenses involved in purchasing and installing a meter that is able to register
                electricity flow in two directions. An additional meter or meters, installed in a dual meter socket (“dual
                metering”), to monitor the flow of electricity in each direction, may be installed with the consent of the
                eligible customer-generator, at the expense of the Utility, and the dual metering shall be used only to
                provide the information necessary to accurately bill or credit the customer according to the Utility’s
                OAS or to collect solar or wind, or a hybrid system of both, electric generating system performance
                information for research purposes. The Utility shall determine whether dual metering is required under
                this provision. If dual metering is installed, the net energy metering calculation (see below) shall yield
                a result identical to that of a single meter capable of registering the flow of electricity in two directions.
                The Utility shall not require dual metering except where necessary for billing accuracy. If none of the
                normal metering options available at the Utility’s disposal, which are necessary to render accurate
                billing, are acceptable to the eligible customer-generator, the Utility shall have the right to refuse
                interconnection.




                                                                 (Continued)
        3C18                                                      Issued by                    Date Filed             Sep 25, 2009
        Advice Ltr. No.       2111-E                           Lee Schavrien                   Effective              Oct 25, 2009
                                                             Senior Vice President
        Decision No.                                          Regulatory Affairs               Resolution No.




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                                                               Revised    Cal. P.U.C. Sheet No.                      21613-E
            San Diego Gas & Electric Company
                  San Diego, California           Canceling    Revised    Cal. P.U.C. Sheet No.                      21365-E

                                                        SCHEDULE NEM                                                Sheet 4
                                                    NET ENERGY METERING


       SPECIAL CONDITIONS (Continued)

       3.       Net Energy Metering and Billing: Eligible Wind Energy Co-Metering customer-generators, see also
                Special Condition 6 and facilities qualifying under multiple tariffs, see also Special Condition 7. Net
                energy is defined as measuring the difference between the electric energy supplied by the Utility
                through the electric grid to the eligible customer-generator and the electric energy generated by an
                eligible customer generator and fed back into the electric grid over a 12-month period (Relevant
                Period). At the end of each Relevant Period following the date the eligible customer-generator was
                first eligible for Schedule NEM, or the date of written authorization for Parallel Operation, whichever
                is later, and at each anniversary date thereafter, the eligible customer-generator shall be billed for
                net electric energy used during that period. If an eligible customer-generator terminates service
                under this rate schedule, or experiences a change in electric service provider prior to the end of any
                Relevant Period, the Utility shall reconcile the customer’s consumption and production of electric
                energy and bill the customer as described below, as if it were the end of the normal Relevant
                Period.

               In the event the monthly valued energy exported by the eligible customer-generator exceeds the
               monthly valued energy consumed by eligible customer-generator during the Relevant Period, based
               on the eligible customer-generator’s OAS as set forth below, no payment shall be made for the
               excess energy delivered to the grid. If the Utility is the electric service provider, this condition may be
               modified where the customer has signed a contract to sell electric energy to the Utility.

               In the event that the monthly valued energy supplied by the Utility during the Relevant Period
               exceeds the monthly valued energy exported by the eligible customer-generator during the Relevant
               Period, the eligible customer-generator is a net consumer and the Utility shall bill the eligible
               customer-generator for the net consumption during the Relevant Period based on the eligible
               customer-generator’s OAS, as set forth below.

               Except as provided for in Special Condition 3(h), Pursuant to PU Code Section 2827(h)(3), once the                  N
               true-up is completed at the end of the Relevant Period, any credit for excess energy (kWh) will be
               retained by the Utility and the net producer will not be owed any compensation for this excess
               energy. Production and consumption during the twelfth month is already considered in the true-up.

               Except as provided in Special Condition 6, the eligible customer-generator’s OAS shall apply to the
               value of any net monthly consumption or production as follows:

              a) Baseline Rates: If the customer is a net consumer over a billing period, the net kWh consumed
                 shall be billed at the applicable baseline rates up to the billing period’s baseline allowance, with
                 any excess kWh consumed billed at the applicable non-baseline rates charged other customers in
                 the rate class.

                  If the customer is a net generator over a billing period, the net kWh generated shall be valued at
                  the applicable baseline rates up to the billing period’s baseline allowance, with any excess kWh
                  generated valued at the applicable non-baseline rates charged other customers in the rate class.




                                                                (Continued)
       4C8                                                       Issued by                   Date Filed              Feb 1, 2010
       Advice Ltr. No.       2145-E                           Lee Schavrien                  Effective               Feb 1, 2010
                                                           Senior Vice President
       Decision No.                                         Regulatory Affairs               Resolution No.




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                                            San Diego Gas & Electric Company
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                                             Non-Shared Service Workpapers




                                                           Revised   Cal. P.U.C. Sheet No.                    21366-E
         San Diego Gas & Electric Company
               San Diego, California          Canceling    Revised   Cal. P.U.C. Sheet No.                    20444-E

                                                    SCHEDULE NEM                                              Sheet 5
                                                 NET ENERGY METERING


       SPECIAL CONDITIONS (Continued)

           b) Time-of-Use: If the customer is a net generator during any discrete time-of-use (TOU) period, the             L
              net kWh produced shall be valued at the appropriate TOU rates charged other customers under
              the same OAS. If the customer is a net consumer during any discrete TOU period, the net kWh
              consumed shall be billed at the appropriate TOU rates charged other customers under the same
              OAS.

           c) Annual and Monthly Billing: If the Utility supplies the eligible customer-generator with electric
              energy, the Utility shall provide the eligible customer-generator with net energy consumption
              information with each regular bill. That information shall include the current monetary balance
              owed to the Utility for the net energy consumed since the last Relevant period ended. Eligible
              residential and small commercial customer-generators may pay monthly or annually for the net
              energy consumed. For all other commercial, industrial, and agricultural customers, the net
              balance of all moneys owed must be paid monthly. The net value of energy exported over a
              monthly billing cycle shall be carried over to the following billing period and appear as a credit on
              the eligible customer-generator’s account, until the end of the Relevant Period.

                For CCA, at the end of each relevant period, the Utility and CCA shall complete an annual true up
                of all charges and credits calculated monthly, consistent with the provisions set forth under this
                schedule. Credits and charges related to the CCA’s generation services shall be based on the
                information provided by the CCA to the Utility. Credits and charges related to services provided
                by the Utility shall be based on the Utility’s rates. Any net balance related to generation charges
                that are collected from an eligible NEM CCA customer-generator will be paid annually by the
                Utility to the CCA as set forth in Rule 27, Section Q, which describes the payment and collection
                terms between the Utility and a CCA customer. The charges or credits resulting from a CCA’s
                generation services shall not be co-mingled with charges or credits resulting from services
                provided by the Utility.

                A customer receiving service on this rate schedule shall not be eligible for the Level Pay Plan
                option set forth in Rule 9.

           d) Cost Responsibility Surcharge (CRS): Pursuant to D.03-04-030, eligible customer-generators
              shall pay the DWR charges and CTC (collectively CRS) on the net energy delivered by the Utility,
              as set forth in Schedule CGDL-CRS.

           e) ESP Charges: The charges for all energy components for eligible customer-generators shall be
              based exclusively on the eligible customer-generator’s net energy consumption over a Relevant
              Period, without regard to the eligible customer-generator’s choice of ESP. If the eligible
              customer-generator switches its ESP during a Relevant Period, the prior ESP shall reconcile the
              customer generator’s consumption and export of electricity for the applicable part of the current
              Relevant Period and the new Relevant Period will begin with respect to service provided by the
              eligible customer-generator’s new ESP. The Utility will recover the incremental metering and                  L
              billing service costs associated with Net Energy Metering from the customer’s ESP.

           f)   CCA Charges: If the eligible customer-generator switches its commodity provider during the
                Relevant Period, the previous commodity provider shall reconcile the customer generator’s
                consumption and a new relevant period will begin with respect to service provided by the eligible
                customer-generator’s new commodity provider, if applicable.



                                                            (Continued)
       5C21                                                  Issued by                  Date Filed           Sep 25, 2009
       Advice Ltr. No.    2111-E                          Lee Schavrien                 Effective            Oct 25, 2009
                                                       Senior Vice President
       Decision No.                                     Regulatory Affairs              Resolution No.




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                                                                Revised     Cal. P.U.C. Sheet No.                         21614-E
             San Diego Gas & Electric Company
                   San Diego, California           Canceling    Revised     Cal. P.U.C. Sheet No.                         21367-E

                                                         SCHEDULE NEM                                                     Sheet 6
                                                      NET ENERGY METERING


        SPECIAL CONDITIONS (Continued)

               g) Commencement of Service: The Utility shall start a customer on Schedule NEM effective with the
                  first meter read date prior to the later of (1) customer notice to the Utility of a request for service on
                  Schedule NEM or (2) SDG&E’s written authorization for parallel operation of the customer’s eligible
                  generating facility.

               h) Assembly Bill 920: Pursuant to Assembly Bill 920, starting January 1, 2011, a NEM customer with                       N
                  "net surplus electricity" (all electricity generated by an eligible customer measured in kilowatt-hours
                  that exceeds the amount of electricity consumed by that eligible customer over a 12-month period),
                  will be provided with options regarding net surplus compensation, which valuation remains subject
                  to further Commission action. Until then, NEM customers may choose to:
                        (i) Begin the tracking of surplus energy at the end of the customer’s current 12-month relevant
                            period; or
                        (ii) Begin the tracking of surplus energy immediately, thereby establishing a new 12-month
                             relevant period. Under this option, SDG&E will perform the normal reconciliation of the
                             customer’s account and the new 12-month relevant period will begin on the next regularly-
                             scheduled meter read date; or
                        (iii) Not receive any true-up net surplus electricity compensation by notifying SDG&E in writing
                              that they do not wish to participate                                                                      N

        4.      Interconnection: Prior to Parallel Operation, the eligible customer-generator must execute and comply
                with the applicable Utility Interconnection Agreement For Net Energy Metering Solar Or Wind Electric
                Generating Facilities (Form 142-02760) or the Net Energy Metering Application and Interconnection
                Agreement for Customers with Solar and/or Wind Generating Facilities of 30 kW or Less (Form 142-
                02765) or for NEM / non-NEM Generating Facility export, Form 117-2160. The eligible customer-
                generator shall meet all applicable safety and performance standards established by the National
                Electric Code, the Institute of Electrical and Electronics Engineers, and accredited testing laboratories
                such as Underwriters Laboratories and, where applicable, rules of the CPUC regarding safety and
                reliability
        5.      Customer-Generators Installed on or Before September 30, 2003: Pursuant to Section 2827.7 of the
                PU Code, eligible customer-generators who have all local and state permits required to commence
                construction of their generating facilities on or before December 31, 2002, and have completed
                construction on or before September 30, 2003, are entitled to the Net Energy Metering terms in effect
                on the date the local and state permits were acquired, for the life of the generating facility, regardless of
                any change in customer or ownership of the generating facility.

        6.      Wind-Energy Co-Metering: In accordance with Section 2827.8 of the PU Code, any generating facility
                comprising eligible wind energy generators greater than 50 kW capacity but not exceeding 1,000 kW
                taking service under this tariff is required to comply with this section.       A generating facility that
                includes both non-NEM-eligible generators and a wind generator eligible under this schedule is
                considered a Multiple Tariff Facility and will be interconnected subject to Special Condition 7.

        Wind Energy Co-Metering customer-generators are required to take service on a TOU OAS and utilize a TOU meter, or
        multiple TOU meters, capable of separately measuring the electric energy flowing in both directions, that is the electric
        energy supplied by the Utility to the customer and the electric energy generated by the customer and fed back to the
        electric grid. If the customer’s existing meter is not a TOU meter or is not capable of separately measuring the flow of
        electric energy in both directions, the eligible customer-generator is responsible for all expenses involved in purchasing
        and installing a meter that is both TOU and able to separately measure electric energy flow in both directions.


                                                                  (Continued)
        6C9                                                        Issued by                     Date Filed               Feb 1, 2010
        Advice Ltr. No.       2145-E                           Lee Schavrien                     Effective                Feb 1, 2010
                                                             Senior Vice President
        Decision No.                                          Regulatory Affairs                 Resolution No.




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                                                                Revised     Cal. P.U.C. Sheet No.                   21615-E
             San Diego Gas & Electric Company
                   San Diego, California           Canceling    Revised     Cal. P.U.C. Sheet No.                   21368-E

                                                         SCHEDULE NEM                                               Sheet 7
                                                      NET ENERGY METERING


        SPECIAL CONDITIONS (Continued)

        At the end of each Relevant Period (as described in Special Condition 3), if the value of the generation                   L
        component of the electric energy fed back to the electric grid by the eligible customer-generator exceeds the
        value of the generation component of the electric energy supplied to the eligible customer-generator by the
        Utility, the eligible customer-generator is a Wind Energy Co-Metering producer; (otherwise the eligible
        customer-generator is a Wind Energy Co-Metering consumer.)
                                                                                                                                   L
        7.      Multiple Tariff Facilities:

                Multiple Tariff Facilities have the following additional provisions:

                a)   When Net Generation Output Metering (NGOM) is required, such NGOM must conform to the
                     requirements set forth in Electric Rule 21, Section F.

                b)   An NEM-eligible Constituent Generator Group is defined as a constituent generator group that is
                     eligible for service under the provisions of either schedule NEM, NEM-BIO or NEM-FC.

                c)   A non-NEM-eligible Constituent Generator Group is defined as a constituent generator group that
                     does not take service under the provisions of schedules NEM, NEM-BIO or NEM-FC, but
                     interconnects under the provisions of Electric Rule 21.

                d)   All metering for Multiple Tariff Facilities called for in this Special Condition must meet the
                     requirements needed to bill under the customer-generator’s OAS. All metering, equipment and
                     nonexport relays necessary to implement the provisions in this section will be provided at the
                     customer-generator’s expense.

                e)   Any generator(s) eligible for service under Schedule NEM-BIO with aggregated load accounts and
                     any generator(s) eligible for service under Schedule NEM for large wind generators (over 50 kW
                     up to 1000 kW/Energy Co-metering) will be treated as a separate Constituent Generator Group.

                f)   Billing Credits:

                     1)    For customer-generators with one NEM-eligible Constituent Generator Group and one or
                           more non-NEM-Eligible Generators without non-export relay, and energy (kWh) is exported
                           to the grid at the PCC, the billing credit will be calculated for each billing period as follows:

                           a) NEM-eligible Export is the lesser of either all exported energy (kWh) as measured at the
                              PCC or the NEM-eligible Constituent Generator Group’s production as measured at the
                              NGOM(s)

                           b) Multiply the NEM-eligible export determined in (a) above with the customer-generator’s
                              rate per OAS and applicable NEM schedule.




                                                                 (Continued)
        7C6                                                       Issued by                    Date Filed            Feb 1, 2010
        Advice Ltr. No.       2145-E                           Lee Schavrien                   Effective             Feb 1, 2010
                                                             Senior Vice President
        Decision No.                                          Regulatory Affairs               Resolution No.




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                                   Pages 93 of 375
                                             San Diego Gas & Electric Company
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                                                               Revised    Cal. P.U.C. Sheet No.                    21616-E
          San Diego Gas & Electric Company
                San Diego, California             Canceling    Revised    Cal. P.U.C. Sheet No.                    21369-E

                                                        SCHEDULE NEM                                              Sheet 8
                                                     NET ENERGY METERING


        SPECIAL CONDITIONS (Continued)

                    2) For customer-generators with multiple NEM-eligible Constituent Generator Groups and with                  L
                       or without one or more non-Eligible Generator’s without non-export relay, and energy (kWh)
                       is exported to the grid at the PCC, the billing credit for each NEM-eligible Constituent
                       Generator Group will be calculated for each billing period as follows:

                          a) Sum all NEM-eligible Constituent Generator Groups’ production (kWh) as measured at
                             the NGOMs.

                          b) Determine the proportion of energy production (kWh) attributable to each NEM-eligible
                             Constitute Generator Group by dividing the NGOM reading of each by the sum from (a)
                             above.                                                                                              L

                          c) NEM-eligible Export for each NEM-eligible Constituent Generator Group is the lesser of
                             either its proportion of attributable energy production determined in (b) above multiplied
                             by the total exported energy (kWh) as measured at the PCC or its energy production
                             (kWh) measured at its NGOM.

                          d) Multiply each NEM-eligible Constituent Generator Group’s Export determined in (c)
                             above by the customer-generator’s rate per OAS and applicable NEM schedule.

                          If interval meters are used, this allocation of bill credit will be done on the aggregated
                          intervals over a billing period. If the OAS is a time-of-use (TOU) rate schedule, the allocation
                          will be performed for each aggregated TOU period separately.

                          Generating facilities including only small wind (50 kW or less) and solar generators are not
                          Multiple Tariff Facilities and the customer will be billed as provided in Special Condition 2 of
                          this tariff.

                   3)     Billing credit will be applied consistent with the appropriate NEM tariff as follows:

                          a) First, apply NEM-BIO Generation Rate Component credits (if any) to Generation Rate
                             Component charges on any aggregated accounts served by the Generating Facility.

                          b) Second, apply remaining NEM-BIO credits from (a) above and Generation Rate
                             Component credits from NEM-FC, and NEM of large wind (>50 kW) generators (if any)
                             as appropriate, to the remainder of generation component charges on the account
                             served by the generating facility (Host Account).

                          c) Third, apply NEM solar and small wind (<50 kW) energy (generation and non-generation
                             rate component) credits to energy charges of the accounts served by the generating
                             facility.




                                                                (Continued)
        8C6                                                      Issued by                    Date Filed           Feb 1, 2010
        Advice Ltr. No.     2145-E                            Lee Schavrien                   Effective            Feb 1, 2010
                                                           Senior Vice President
        Decision No.                                        Regulatory Affairs                Resolution No.




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                                   Pages 94 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                              Non-Shared Service Workpapers




                                                             Revised      Cal. P.U.C. Sheet No.                  21617-E
         San Diego Gas & Electric Company
               San Diego, California            Canceling    Original     Cal. P.U.C. Sheet No.                  21370-E

                                                      SCHEDULE NEM                                               Sheet 9
                                                   NET ENERGY METERING


       SPECIAL CONDITIONS (Continued)

             g)   Multiple Tariff Facility Configurations and Metering.
                                                                                                                               L
                  1)     For two or more of NEM-eligible Constituent Generator Groups and no non-NEM eligible
                         Constituent Generator Groups, the customer-generator must install NGOM on each
                         Constituent Generator Group. In addition, metering is required at the PCC.

                  2)     For both NEM-eligible and non-NEM-eligible Constituent Generator Groups, the customer
                         must select one of the following options:

                         a) Non Export Relay Option: A customer-generator must install a Non-Export relay on their
                         non-NEM Constituent Generator Groups and install metering as follows: 1) If there is only
                         one type of NEM-eligible Constituent Generator Group then metering at the PCC is all that is
                         required and the terms of the appropriate NEM tariff for that group shall apply; 2) If there are
                         two or more types of NEM-eligible Constituent Generator Groups, then metering at the PCC
                         and NGOM metering of each NEM-eligible Constituent Generator Group is required.

                         b) NGOM Option: The customer-generator must install NGOM on each NEM-eligible
                         Constituent Generator Group and metering at the PCC.
                                                                                                                               L
                  For any of the above configurations, if the customer-generator has no Constituent Generator
                  Group eligible for Schedule NEM-BIO with aggregated accounts, but has a Constituent Generator
                  Group eligible for Schedule NEM for small wind (50 kW or less) and/or solar generators, the
                  customer-generator may elect to take service for such under either Schedule NEM for large wind
                  generators or Schedule NEM-BIO or NEM-FC as appropriate to one of the other Constituent
                  Generator Groups.

                  For the purpose of tariff administration, other metering configurations may be allowed at SDG&E’s
                  discretion.




       9C6                                                     Issued by                     Date Filed          Feb 1, 2010
       Advice Ltr. No.     2145-E                           Lee Schavrien                    Effective           Feb 1, 2010
                                                         Senior Vice President
       Decision No.                                       Regulatory Affairs                 Resolution No.




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                                   Pages 95 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                              Non-Shared Service Workpapers




                                                              Revised    Cal. P.U.C. Sheet No.                       20448-E
          San Diego Gas & Electric Company
                San Diego, California            Canceling    Revised    Cal. P.U.C. Sheet No.                       20178-E

                                                    SCHEDULE NEM-BIO                                                Sheet 1
                            NET ENERGY METERING FOR BIOGAS CUSTOMER-GENERATORS
                                               (Closed Schedule)
        APPLICABILITY
        Except as otherwise provided herein, this schedule is applicable to bundled service customers who are
        served under a Time-of-Use (TOU) rate schedule, and who by December 31, 2009 (1) interconnect and                          T
        operate in parallel with the Utility’s electrical system using an Eligible Biogas Digester Electrical Generating
        Facility, as defined below pursuant to California Public Utilities Code (PU Code) Section 2827.9, with a
        generating capacity no greater than 1,000 kW, located on or adjacent to the customer’s premises as a
        source of customer’s generation, intended to offset part or all of the customer’s electrical requirements, and
        (2) are the recipient of local, state, or federal funds, or who self-finance projects designed to encourage the
        development of Biogas Digester Electrical Generating Facilities (hereinafter “eligible biogas customer-
        generator” or “customer”). This schedule is also applicable up to a total of three biogas generators, in the
        territories of the three largest Investor Owned Utilities, with a capacity of more than one megawatt and not
        more than 10 megawatts that otherwise meet the criteria of this schedule.

        Customers eligible for service under this schedule are exempt from any new or additional charges not
        included in their Otherwise Applicable Schedules (OAS).

        Pursuant to PU Code Section 2827.9, this Schedule is available on a first-come, first-served basis for the
        operating life of the Eligible Biogas Digester Electrical Generating Facility. This schedule is closed to new
        customers once the combined statewide cumulative rated generating capacity used by eligible biogas
        customer-generators in the service territories of the three largest electric Investor Owned Utilities reaches 50
        megawatts.

        An eligible biogas customer-generator that is subject to the best available control technology (BACT)
        requirements shall be eligible for this schedule if the eligible biogas customer-generator has installed the
        BACT as required by the regional Air Pollution Control District at the time of installation as required by PU
        Code Section 2827.9.

        Pursuant to Decision 08-02-002 and notwithstanding all applicable terms and conditions contained herein, to
        the extent a Community Choice Aggregator offers a net energy metering tariff for biogas customer-                          N
        generators, the Utility shall provide applicable NEM services under this schedule to an eligible CCA
        customer-generator consistent with services provided to its bundled service eligible customer-generators. As
        a condition of receiving service under this schedule, the CAA shall be responsible for timely providing the
        applicable generation-related bill charges or credits for each CCA customer-generator to the Utility. Each
        eligible CCA customer-generator shall look to its CCA for NEM services related to the electric generation
        charges and credits that result from receiving services under this schedule. The CCA shall also be
        responsible for the applicable generation-related bill credit structure associated with this service option and
        providing the CCA customer-generator with the applicable generation-related bill credit.
                                                                                                                                   N
        Schedule NEM-BIO applies also to specified Net Energy Metering-eligible (NEM-Eligible) generators in a
        generating facility comprised of multiple NEM- and non-NEM-eligible generators, served through the same
        Point of Common Coupling (PCC), where the NEM-eligible generating capacity is not more than 1 megawatt.
        Such facilities will be referred to as Multiple Tariff Facilities, and any group of generators within such a facility
        that is subject to the same tariff provisions for billing and metering purposes will be referred to as a
        Constituent Generator Group. In order to be eligible for this rate schedule in a Multiple Tariff Facility, the
        customer must meet all the requirements of Special Condition 8 for the Schedule NEM-BIO, and must also
        meet all other applicable tariffs. Customer must also complete a Generating Facility Interconnection
        Agreement (Multiple Tariff) (Form 117-2160).

        Due to the complexity of Multiple Tariff Facilities, NEM-BIO generators interconnecting under the provisions
        of Special Condition 8 may require additional review and/or interconnection facilities and other equipment,
        and may incur interconnection costs, as provided for in electric Rule 21.

                                                               (Continued)
        1C26                                                    Issued by                    Date Filed              Mar 5, 2008
        Advice Ltr. No.    1971-E                            Lee Schavrien                   Effective               Apr 4, 2008
                                                          Senior Vice President
        Decision No.       08-02-002                       Regulatory Affairs                Resolution No.




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp6.pdf
                                   Pages 96 of 375
                                               San Diego Gas & Electric Company
                                                  Test Year 2012 GRC - APP
                                                Non-Shared Service Workpapers




                                                               Revised    Cal. P.U.C. Sheet No.                  20449-E
            San Diego Gas & Electric Company
                  San Diego, California          Canceling     Revised    Cal. P.U.C. Sheet No.                 20179-E *

                                                    SCHEDULE NEM-BIO                                             Sheet 2
                              NET ENERGY METERING FOR BIOGAS CUSTOMER-GENERATORS


       TERRITORY                                                                                                                L

       Within the entire territory served by the Utility.

       RATES

       Only the Generation Rate Component of the energy charge of the eligible biogas customer-generator’s
       OAS, less generation surcharges (such as the DWR Bond Charge shown on Schedule DWR-BC) or any
       successor rate schedule, if any, shall be used in the calculation of credits when the eligible biogas                    L
       customer-generator is a net energy producer, on a monthly basis, for any TOU period. Only the
       Generation Rate Component of the eligible biogas customer-generator’s OAS, including all generation
       surcharges, shall be used to calculate the charge for generation when the eligible biogas customer-
       generator is a net energy consumer on a monthly basis, for any TOU period. All other charges, including
       but not limited to, Transmission Charges, Distribution Charges, Public Goods Charges, Nuclear
       Decommissioning Charges, Monthly Basic Service Fees, Minimum Charges, Demand Charges, and
       non-energy related charges, shall be calculated according to the eligible biogas customer-generator’s OAS
       prior to the netting of energy consumed and exported.

       Pursuant to CPUC D.03-04-030, eligible biogas customer-generator shall not pay the departing load cost
       responsibility surcharge shown on Schedule DL-CRS.

       Customers eligible for service under this schedule are not required to take service under Schedule S
       (Standby Service) or Schedule S-I (Standby Service - Interruptible) for the qualifying generation. Eligible
       customers shall be permitted to take standby service for non-eligible generation on the same meter as the
       eligible generation.

       The charges and credits for Multiple Tariff Facilities taking service on this rate schedule under the
       provisions of Special Condition 8 will be calculated using the OAS identified by the eligible biogas
       customer-generator in its application for interconnection and its interconnection agreement with SDG&E or
       as subsequently changed by the eligible biogas customer-generator in accordance with SDG&E’s Electric
       Rule 12.

       Customers with Multiple Tariff Facilities with existing NEM, NEM-BIO and/or NEM-FC eligible generators
       interconnecting additional generators, will receive a bill trueup, prior to taking service under Special
       Condition 8. This ensures that all NEM accounts have the same Relevant Period, as defined in Special
       Condition 1.d, going forward.

       SPECIAL CONDITIONS

       1.      Definitions: The definition of terms used in this schedule are either found herein or in Rule 1, Rule 21
               or the customer’s OAS.

               a. Eligible Biogas Digester Electrical Generating Facility: A Generating Facility used to produce
                    electricity by a manure methane production project or as a byproduct of the anaerobic digestion
                    of bio-solids and animal waste, that meets all applicable safety and performance standards
                    established by the National Electrical Code, the Institute of Electrical and Electronics Engineers,
                    and accredited testing laboratories such as Underwriters Laboratories and, where applicable,
                    rules of the Public Utilities Commission regarding safety and reliability.




                                                                (Continued)
       2C21                                                      Issued by                   Date Filed          Mar 5, 2008
       Advice Ltr. No.       1971-E                          Lee Schavrien                   Effective            Apr 4, 2008
                                                            Senior Vice President
       Decision No.          08-02-002                       Regulatory Affairs              Resolution No.




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp6.pdf
                                   Pages 97 of 375
                                                San Diego Gas & Electric Company
                                                   Test Year 2012 GRC - APP
                                                 Non-Shared Service Workpapers




                                                                Revised   Cal. P.U.C. Sheet No.                   20450-E
             San Diego Gas & Electric Company
                   San Diego, California           Canceling    Revised   Cal. P.U.C. Sheet No.                20180-E **

                                                     SCHEDULE NEM-BIO                                            Sheet 3
                               NET ENERGY METERING FOR BIOGAS CUSTOMER-GENERATORS


        SPECIAL CONDITIONS (Continued)

        1.      Definitions (Continued):

                b    Date of Final Interconnection: The date the Utility provides the eligible biogas customer-generator        L
                     with the Utility’s written approval to commence parallel operation of the Eligible Biogas Digester
                     Electrical Generating Facility for purposes of participating in Schedule NEM-BIO.

                c.   Otherwise Applicable Schedule (OAS): The eligible biogas customer-generator’s regular rate
                     schedule under which service is rendered.

                d.   Relevant Period: Twelve monthly billing cycles commencing on the anniversary Date of Final
                     Interconnection or pursuant to Special Condition 5.b, or a portion thereof in the event service under
                     this tariff terminates.                                                                                    L

                e.   Eligible Metered Service Account: A TOU metered service account serving an Eligible Biogas
                     Digester Electrical Generating Facility and all TOU metered service account(s) serving dairy
                     operations that are located on property adjacent, or contiguous, to the Eligible Biogas Digester
                     Electrical Generating Facility, including but not limited to accounts associated with the milking
                     operations, milk refrigeration, or water pumping. If a dairy operation has more than one Eligible
                     Metered Service Account, all such metered service accounts must be under the same ownership
                     and have the eligible biogas customer-generator’s name as the account serving the Eligible Biogas
                     Digester Electrical Generating Facility to qualify for the provisions of Special Condition 3.

                f.   Annual Reconciliation: The Utility will total the monthly valued generation rate component of the
                     energy (kWh) supplied by the Utility to the eligible biogas customer-generator and the monthly
                     valued generation rate component of the energy (kWh) fed back to the Utility’s Distribution
                     System by the eligible biogas customer-generator during the Relevant Period. If the total
                     generation rate component value of the energy supplied by the Utility is greater than the total
                     generation rate component value of energy fed back to the Utility Distribution System, then the
                     eligible biogas customer-generator is a net consumer. Otherwise, the eligible biogas customer-
                     generator is a net producer.

                     For non-dairy operations, only the account serving the Eligible Biogas Digester Generating Facility
                     is used to determine if the eligible biogas customer-generator is a net producer or a net consumer.

                     In the case of a dairy operation, an aggregate of usage from all the Eligible Metered Service
                     Accounts is used to determine if the eligible biogas customer-generator is a net producer or net
                     consumer.

                     For dairy operations with Load Aggregation as defined in Special Condition 3, each eligible Service
                     Account will be billed for Generation Rate Component charges, based on the rate schedule for the
                     particular service account, at the end of the Relevant Period, or sooner if the account closes or is
                     no longer eligible for Load Aggregation.

                     As part of the Annual Reconciliation, net consumers and net producers will receive a bill for energy
                     usage that totals 1) all generation charges; 2) all Eligible Generation Credits; and 3) all other
                     charges incurred during that billing cycle.

                     The balance of all monies owed by net consumers and net producers shall be paid in accordance
                     with the eligible customer-generator’s OAS. Production and consumption during the twelfth month
                     is already considered in the true-up.

                                                                 (Continued)
        3C21                                                      Issued by                  Date Filed           Mar 5, 2008
        Advice Ltr. No.       1971-E                           Lee Schavrien                 Effective            Apr 4, 2008
                                                           Senior Vice President
        Decision No.          08-02-002                     Regulatory Affairs               Resolution No.




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp6.pdf
                                   Pages 98 of 375
                                                San Diego Gas & Electric Company
                                                   Test Year 2012 GRC - APP
                                                 Non-Shared Service Workpapers




                                                                    Revised     Cal. P.U.C. Sheet No.                         20451-E
             San Diego Gas & Electric Company
                   San Diego, California              Canceling     Revised     Cal. P.U.C. Sheet No.                        20181-E *

                                                         SCHEDULE NEM-BIO                                                     Sheet 4
                                NET ENERGY METERING FOR BIOGAS CUSTOMER-GENERATORS


        SPECIAL CONDITIONS (Continued)
        1. Definitions (Continued):

                     For CCA, at the end of each relevant period, the CCA shall complete an annual true up of all                        N
                     charges and credits calculated monthly, consistent with the provisions set forth under this
                     schedule. Credits and charges related to the CCA’s generation services shall be based on the
                     information provided by the CCA to the Utility. Any net balance related to generation charges that
                     are collected from an eligible NEM CCA customer-generator will be paid annually by the Utility to
                     the CCA as set forth in Rule 27, Section Q, which describes the payment and collection terms
                     between the Utility and a CCA customer. Charges or credits resulting from a CCA’s generation
                     services shall not be co-mingled with charges or credits resulting from services provided by the                    N
                     Utility.

              g. Eligible Generation Credit: The Eligible Generation Credit for net consumers equals the lesser of 1)                    L
                 all net generation charges for the Relevant Period, including in the case of a dairy operation the                      L
                 generation charges associated with accounts eligible for Special Condition 3; or 2) the absolute                        L
                 value of all net generation credits for the Relevant Period.                                                            L

                h. Net Energy: The difference between the energy (kWh) supplied by the Utility to the eligible biogas
                   customer-generator, and the energy (kWh) generated by the eligible biogas customer-generator
                   and fed back into the Utility’s Distribution System, measured over a given period.

                i. Generation Charges: The generation rate component (under Schedule EECC or any other
                   applicable generation related charge, which includes, but is not limited to optional commodity
                   pricing that may be available) of the energy charge of the eligible biogas customer-generator’s
                   OAS for the accounts(s).

        2.      Required Contract: An Interconnection Agreement is required for service under this Schedule.

        3.      Load Aggregation: For purposes of determining whether the eligible biogas customer-generator was a
                net consumer or a net producer, as defined in Special Condition 1.f above, the Utility shall aggregate
                the load of residential and non-residential metered TOU service accounts that meet the requirements
                of Special Condition 1.e for dairy operations.

        4.      Metering:

                a.     Biogas digester Net Energy Metering shall be accomplished using a TOU meter capable of
                       separately registering the flow of electricity in two directions. If the Biogas Customer-Generator’s existing
                       meter is not capable of separately measuring the flow of electricity in two directions, the Biogas
                       Customer-Generator shall be responsible for all expenses involved in purchasing and installing a
                       meter that is able to separately measure electricity flow in two directions. If dual metering is
                       installed, the Net Energy Metering calculation shall yield a result identical to that of a single
                       meter capable of separately measuring the flow of electricity in two directions.

                b.     If none of the normal metering options at the Utility’s disposal that are necessary to render
                       accurate billing are acceptable to the Biogas Customer-Generator, the Utility shall have the right
                       to refuse interconnection under this schedule.

               c.      Dairy operations with service accounts that qualify for Special Condition 3 are required to meet the
                      provisions of Special Conditions 4.a and 4.b for the account serving the Eligible Biogas Digester Electrical
                      Generating Facility only; all other service accounts are only required to have the metering specified in the
                      TOU rate schedule on which it is billed.

                                                                     (Continued)
        4C20                                                          Issued by                      Date Filed                Mar 5, 2008
        Advice Ltr. No.        1971-E                             Lee Schavrien                      Effective                 Apr 4, 2008
                                                                Senior Vice President
        Decision No.           08-02-002                         Regulatory Affairs                  Resolution No.




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp6.pdf
                                   Pages 99 of 375
                                                San Diego Gas & Electric Company
                                                   Test Year 2012 GRC - APP
                                                 Non-Shared Service Workpapers




                                                                 Revised    Cal. P.U.C. Sheet No.                    20452-E
             San Diego Gas & Electric Company
                   San Diego, California            Canceling    Original   Cal. P.U.C. Sheet No.                  20182-E **

                                                       SCHEDULE NEM-BIO                                             Sheet 5
                               NET ENERGY METERING FOR BIOGAS CUSTOMER-GENERATORS


        SPECIAL CONDITIONS (Continued)

        4.      Metering (Continued)                                                                                               L

                d. Multiple Tariff Facilities will be metered under one of the options described in Special Condition 8.           L

        5.      Billing: Eligible biogas customer-generator will be billed monthly for all charges other than the
                Generation Rate Component on all Eligible Aggregated Metered Service Accounts. With each monthly
                billing statement, the Utility shall provide the eligible biogas customer-generator with information
                regarding energy (kWh) consumption and any energy (kWh) exported to the grid.

                The Utility shall start a customer on Schedule NEM-BIO effective with the first meter read date to the
                later of (1) customer notice to the Utility of a request for service on Schedule NEM-BIO or (2) SDG&E’s
                written authorization for parallel operation of the customer’s eligible generating facility.

                At the end of each Relevant Period, as defined in Special Condition 1.d, following the Date of Final
                Interconnection, the Utility shall proceed as follows:

                a.   The Utility will complete an Annual Reconciliation per Special Condition 1.f.

                b.   Any remaining Generation credit greater than the Eligible Generation Credit calculated per Special
                     Condition 1.g will be reduced to zero and the eligible biogas customer-generator shall not be
                     entitled to compensation for such credit, and a new Relevant Period shall commence.

                Pursuant to PU Code Section 2827(h)(3), once the true-up is completed at the end of the Relevant
                Period, any credit for excess energy (kWh) will be retained by the Utility and the net producer will not
                be owed any compensation for this excess energy. Customer-generators with Multiple Tariff Facilities
                with existing NEM, NEM-BIO and/or NEM-FC eligible generators interconnecting additional generators,
                will receive a bill reconciliation prior to taking service under Special Condition 8. This ensures that all
                NEM accounts have the same Relevant Period going forward.

        6.      Standby Charges: Consistent with electric Rate Schedules S or SI, to the extent that charges for
                transmission and distribution services are recovered through demand charges in any billing period, no
                standby charges shall apply in that monthly billing cycle except Multiple Tariff Facilities interconnected
                under the terms of Special Condition 8 may be subject to the requirements of Schedules S or SI.

        7.      Interconnection: Prior to Parallel Operation, the eligible biogas customer-generator must execute and
                comply with the applicable Utility Interconnection Agreement (Form 142-0761 or, for NEM / non-NEM
                Generating Facility export, Form 117-2160). The eligible biogas customer-generator shall meet all
                applicable safety and performance standards established by the National Electric Code, the Institute of
                Electrical and Electronics Engineers, and accredited testing laboratories such as Underwriters
                Laboratories and, where applicable, rules of the CPUC regarding safety and reliability.

        8.      Multiple Tariff Facilities: Multiple Tariff Facilities have the following additional provisions:

                a.   When Net Generation Output Metering (NGOM) is required, such NGOM must conform to the
                     requirements set forth in Electric Rule 21, Section F.

                b.   An NEM-eligible Constituent Generator Group is defined as a group of generators that is eligible
                     for service under the provisions of either schedule NEM, NEM-BIO or NEM-FC.



                                                                  (Continued)
        5C13                                                       Issued by                    Date Filed           Mar 5, 2008
        Advice Ltr. No.       1971-E                            Lee Schavrien                   Effective            Apr 4, 2008
                                                             Senior Vice President
        Decision No.          08-02-002                       Regulatory Affairs                Resolution No.




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                                  Pages 100 of 375
                                                San Diego Gas & Electric Company
                                                   Test Year 2012 GRC - APP
                                                 Non-Shared Service Workpapers




                                                                 Revised    Cal. P.U.C. Sheet No.                   20453-E
             San Diego Gas & Electric Company
                   San Diego, California            Canceling    Original   Cal. P.U.C. Sheet No.                  20183-E *

                                                       SCHEDULE NEM-BIO                                             Sheet 6
                                 NET ENERGY METERING FOR BIOGAS CUSTOMER-GENERATORS


        SPECIAL CONDITIONS (Continued)

        8.      Multiple Tariff Facilities: (Continued)

                c.    A non-NEM-eligible Constituent Generator Group is defined as a group of generators that does                 L
                      not take service under the provisions of schedules NEM, NEM-BIO or NEM-FC, but interconnects                 L
                      under the provisions of Electric Rule 21.                                                                    L

                d.    All metering for Multiple Tariff Facilities called for in this Special Condition must meet the
                      requirements needed to bill under the customer-generator’s OAS. All metering equipment and
                      Non Export Relays necessary to implement the provisions in this section will be provided at the
                      customer-generator’s expense.

                e.    Any generator(s) eligible for service under Schedule NEM-BIO with aggregated load accounts
                      and any generator(s) eligible for service under Schedule NEM for large wind generators (over 50
                      kW up to 1000 kW/Energy Co-metering) will be treated as a separate Constituent Generator
                      Group.

                f.    Billing Credits:

                     1)    For customer-generators with one NEM-eligible Constituent Generator Group and one or
                           more non-NEM-Eligible Generators without non-export relay, and energy (kWh) is exported to
                           the grid at the PCC, the billing credit will be calculated for each billing period as follows:

                           a)     NEM-eligible Export is the lesser of either all exported energy (kWh) as measured at the
                                  PCC or the NEM-eligible Constituent Generator Group’s production as measured at the
                                  NGOM(s)

                           b)     Multiply the NEM-eligible export determined in (a) above with the customer-generator’s
                                  rate per OAS and applicable NEM schedule.

                     2)    For customer-generators with multiple NEM-eligible Constituent Generator Groups and with
                           or without one or more non-Eligible Generator’s without non-export relay, and energy (kWh)
                           is exported to the grid at the PCC, the billing credit for each NEM-eligible Constituent
                           Generator Group will be calculated for each billing period as follows:

                           a)     Sum all NEM-eligible Constituent Generator Groups’ production (kWh) as measured at
                                  the NGOMs.

                           b)     Determine the proportion of energy production (kWh) attributable to each NEM-eligible
                                  Constitute Generator Group by dividing the NGOM reading of each by the sum from (a)
                                  above.

                           c)     NEM-eligible Export for each NEM-eligible Constituent Generator Group is the lesser of
                                  either its proportion of attributable energy production determined in (b) above multiplied
                                  by the total exported energy (kWh) as measured at the PCC or its energy production
                                  (kWh) measured at its NGOM.

                           d) Multiply each NEM-eligible Constituent Generator Group’s Export determined in (c) above
                              by the customer-generator’s rate per OAS and applicable NEM schedule.

                                                                  (Continued)
        6C12                                                       Issued by                   Date Filed           Mar 5, 2008
        Advice Ltr. No.         1971-E                          Lee Schavrien                  Effective             Apr 4, 2008
                                                             Senior Vice President
        Decision No.            08-02-002                     Regulatory Affairs               Resolution No.




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                                  Pages 101 of 375
                                                San Diego Gas & Electric Company
                                                   Test Year 2012 GRC - APP
                                                 Non-Shared Service Workpapers




                                                                 Original   Cal. P.U.C. Sheet No.                    20184-E *
             San Diego Gas & Electric Company
                   San Diego, California            Canceling               Cal. P.U.C. Sheet No.

                                                      SCHEDULE NEM-BIO                                                Sheet 7        N
                                 NET ENERGY METERING FOR BIOGAS CUSTOMER-GENERATORS                                                  N

        SPECIAL CONDITIONS (Continued)                                                                                               N
                                                                                                                                     |
        8.      Multiple Tariff Facilities: (Continued)                                                                              |
                                                                                                                                     |
                           If interval meters are used, this allocation of bill credit will be done on the aggregated intervals      |
                           over a billing period. If the OAS is a time-of-use (TOU) rate schedule, the allocation will be            |
                           performed for each aggregated TOU period separately.                                                      |
                                                                                                                                     |
                     3)    Billing credit will be applied consistent with the appropriate NEM tariff as follows:                     |
                                                                                                                                     |
                           a)     First, apply NEM-BIO Generation Rate Component credits (if any) to Generation Rate                 |
                                                                                                                                     |
                                  Component charges on any aggregated accounts served by the Generating Facility.
                                                                                                                                     |
                                                                                                                                     |
                           b)     Second, apply remaining NEM-BIO credits from (a) above and Generation Rate                         |
                                  Component credits from NEM-FC, and NEM of large wind (>50 kW) generators (if any)                  |
                                  as appropriate, to the remainder of generation component charges on the account                    |
                                  served by the generating facility (Host Account).                                                  |
                                                                                                                                     |
                           c)     Third, apply NEM solar and small wind (<50 kW) energy (generation and non-generation               |
                                  rate component) credits to energy charges of the accounts served by the generating                 |
                                  facility.                                                                                          |
                                                                                                                                     |
                g.   Multiple Tariff Facility Configurations and Metering                                                            |
                                                                                                                                     |
                     1)    For two or more of NEM-eligible Constituent Generator Groups and no non-NEM eligible                      |
                           Constituent Generator Groups, the customer-generator must install NGOM on each                            |
                           Constituent Generator Group. In addition, metering is required at the PCC.                                |
                                                                                                                                     |
                     2)    For both, NEM-eligible and non-NEM-eligible Constituent Generator Groups, the customer                    |
                           must select one of the following options:                                                                 |
                                                                                                                                     |
                           a)      Non Export Relay Option: A customer-generator must install a Non-Export relay on                  |
                                  their non-NEM Constituent Generator Groups and install metering as follows: 1) If there            |
                                                                                                                                     |
                                  is only one type of NEM-eligible Constituent Generator Group then metering at the PCC
                                                                                                                                     |
                                  is all that is required and the terms of the appropriate NEM tariff for that group shall
                                                                                                                                     |
                                  apply; 2) If there are two or more types of NEM-eligible Constituent Generator Groups,             |
                                  then metering at the PCC and NGOM metering of each NEM-eligible Constituent                        |
                                  Generator Group is required.                                                                       |
                                                                                                                                     |
                           b)     NGOM Option: The customer-generator must install NGOM on each NEM-eligible                         |
                                  Constituent Generator Group and metering at the PCC.                                               |
                                                                                                                                     N




                                                                  (Continued)
        7C19                                                       Issued by                   Date Filed             Aug 13, 2007
        Advice Ltr. No.         1777-E-B                        Lee Schavrien                  Effective             Sep 12, 2007
                                                             Senior Vice President
        Decision No.            05-08-013                     Regulatory Affairs               Resolution No.              E-3992




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                                                                 Original   Cal. P.U.C. Sheet No.                20185-E *
             San Diego Gas & Electric Company
                   San Diego, California            Canceling               Cal. P.U.C. Sheet No.

                                                      SCHEDULE NEM-BIO                                            Sheet 8       N
                               NET ENERGY METERING FOR BIOGAS CUSTOMER-GENERATORS                                               N

        SPECIAL CONDITIONS (Continued)                                                                                          N
                                                                                                                                |
        8.      Multiple Tariff Facilities: (Continued)                                                                         |
                                                                                                                                |
                g.   Multiple Tariff Facility Configurations and Metering (Continued)                                           |
                                                                                                                                |
                           For any of the above configurations, if the customer-generator has no Constituent Generator          |
                           Group eligible for Schedule NEM-BIO with aggregated accounts, but has a Constituent                  |
                           Generator Group eligible for Schedule NEM for small wind (50 kW or less) and/or solar                |
                           generators, the customer-generator may elect to take service for such under either Schedule          |
                           NEM for large wind generators or Schedule NEM-BIO or NEM-FC as appropriate to one of                 |
                                                                                                                                |
                           the other Constituent Generator Groups.
                                                                                                                                |
                                                                                                                                |
                           For the purpose of tariff administration, other metering configurations may be allowed at            |
                           SDG&E’s discretion.                                                                                  N




        8C16                                                       Issued by                   Date Filed        Aug 13, 2007
        Advice Ltr. No.       1777-E-B                          Lee Schavrien                  Effective         Sep 12, 2007
                                                            Senior Vice President
        Decision No.          05-08-013                      Regulatory Affairs                Resolution No.          E-3992




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        COM/MP1/avs                                         Date of Issuance 1/22/2010


        Decision 10-01-022 January 21, 2010

         BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

        Order Instituting Rulemaking Regarding Policies,
        Procedures and Rules for the California Solar       Rulemaking 08-03-008
        Initiative, the Self-Generation Incentive Program   (Filed March 13, 2008)
        and Other Distributed Generation Issues.




                    DECISION ESTABLISHING THE CALIFORNIA SOLAR
                      INITIATIVE THERMAL PROGRAM TO PROVIDE
                          SOLAR WATER HEATING INCENTIVES




        412713                                -1-




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                                                      TABLE OF CONTENTS

        Title                                                                                                                       Page

        DECISION ESTABLISHING THE CALIFORNIA SOLAR INITIATIVE
        THERMAL PROGRAM TO PROVIDE SOLAR WATER HEATING
        INCENTIVES..................................................................................................................... 2
         1. Summary ..................................................................................................................... 2
         2. Background ................................................................................................................. 3
         3. Overview of Staff Proposal ....................................................................................... 4
         4. Cost-Effectiveness ...................................................................................................... 6
            4.1 Comments .......................................................................................................... 10
            4.2. Discussion ......................................................................................................... 11
         5. Goals, Strategy and Program Design Principles.................................................. 15
            5.1. Comments ......................................................................................................... 17
            5.2. Discussion ......................................................................................................... 18
         6. Technology Eligibility.............................................................................................. 21
            6.1. Comments ......................................................................................................... 23
            6.2. Discussion ......................................................................................................... 25
         7. Incentive Design ....................................................................................................... 28
            7.1. Gas-Displacing Incentives .............................................................................. 28
                  7.1.1. Incentive Rate ...................................................................................... 30
                  7.1.2. Incentive Declines ............................................................................... 31
                  7.1.3. Incentive Caps ..................................................................................... 32
                  7.1.4. Incentive Budget Allocations ............................................................ 34
            7.2. Electric-Displacing Incentives........................................................................ 37
                  7.2.1. Incentive Rate, Caps and Declines ................................................... 39
                  7.2.2. Counting Electric Displacement ....................................................... 40
            7.3. Incentive Calculator ........................................................................................ 41
         8. System Performance Monitoring ........................................................................... 42
         9. Program Administration ......................................................................................... 44
            9.1. Administrative Structure................................................................................ 44
            9.2. Coordination with Energy Efficiency Program.......................................... 46
            9.3. Other Administrative Issues .......................................................................... 51
        10. Budget ....................................................................................................................... 52
            10.1. Gas-Displacing Budget ................................................................................. 53
            10.2. Electric-Displacing Budget ........................................................................... 57
        11. Energy Efficiency Requirements ........................................................................... 61
        12. Market Facilitation, Marketing and Outreach..................................................... 64


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        Title                                                                                                                        Page

        13. Measurement and Evaluation................................................................................ 66
        14. Implementation Timing and Program Handbook.............................................. 69
            14.1. Comments....................................................................................................... 69
            14.2. Discussion ....................................................................................................... 70
        15. Low-Income CSI Thermal ...................................................................................... 73
        16. Comments on Proposed Decision ......................................................................... 74
        17. Assignment of Proceeding ..................................................................................... 76
        Findings of Fact............................................................................................................... 76
        Conclusions of Law ........................................................................................................ 78
        ORDER ............................................................................................................................. 83
        APPENDIX A – California Solar Initiative Thermal Program




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                     DECISION ESTABLISHING THE CALIFORNIA SOLAR
                       INITIATIVE THERMAL PROGRAM TO PROVIDE
                           SOLAR WATER HEATING INCENTIVES

         1. Summary
               This decision establishes a California Solar Initiative (CSI) Thermal
         Program to provide incentives to promote the installation of solar water heating
         systems in the territories of Pacific Gas and Electric Company (PG&E), Southern
         California Edison Company (SCE), San Diego Gas & Electric Company (SDG&E)
         and Southern California Gas Company (SoCalGas). The CSI Thermal Program
         will be funded by $250 million in collections from gas ratepayers, pursuant to
         Assembly Bill (AB) 1470 (Stats. 2007, Ch. 536), as well as up to $100.8 million in
         funds already authorized and currently being collected through the
         general market CSI photovoltaic program and earmarked in Senate Bill 1 (Stats.
         2006, Ch. 132) for solar thermal projects such as solar water heating. Monies
         collected under AB 1470 from gas ratepayers will fund incentives to solar water
         heating systems that displace natural gas usage, while funds collected through
         CSI from electric ratepayers will fund electric displacing solar water heating
         systems.
               The CSI Thermal Program will be administered by PG&E, SCE, SoCalGas,
         and by the California Center for Sustainable Energy (CCSE) in the SDG&E
         territory. PG&E and SDG&E, in coordination with its program administrator,
         CCSE, will disburse incentives to both electric and gas ratepayers who install
         eligible solar water heating systems in their territories. SCE will disburse
         incentives through the CSI Thermal Program to customers who install electric
         displacing solar water heating systems. SoCalGas will disburse incentives to
         customers in its territory who install gas displacing solar water heating systems.



                                                 -2-




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                  This decision sets forth the details necessary to implement the CSI Thermal
         Program, including program goals, technology eligibility, incentive structure,
         energy efficiency requirements, performance monitoring, program
         administration, budget and implementation timing.
         2. Background
                  In early 2006, the Commission, in collaboration with the California Energy
         Commission, established the California Solar Initiative (CSI), a $2.5 billion
         incentive program to promote solar development through 2016, to be funded
         from the distribution rates of gas and electric ratepayers. (See Decision
         (D.) 06-01-024.) At that time, the Commission stated its intent to consider
         incentives for solar water heating (SWH) as part of the CSI program, and
         directed San Diego Gas & Electric Company (SDG&E) to contract with California
         Center for Sustainable Energy (CCSE) (formerly the San Diego Regional Energy
         Office) to administer a pilot program for SWH incentives in the SDG&E territory.
         (Id. at 13.)
                  Subsequently, with the passage of Senate Bill (SB) 1 in August of 2006,
         funds for CSI were limited to $2.16 billion and could no longer be collected from
         gas ratepayers. At the same time, SB 1 included a provision allowing
         $100.8 million of total CSI funds to be used for incentives for solar thermal
         technologies, such as solar water heating. (See Pub. Util. Code § 2851(b).)1 With
         CSI funding now limited to collections from electric ratepayers, the Commission
         concluded in D.06-12-033 that although CSI would include as part of its total
         budget $100.8 million for incentives to solar thermal technologies, CSI should



         1   All statutory references are to the Public Utilities Code, unless otherwise noted.




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         only pay incentives to solar thermal technologies that displace electric usage.
         (D.06-12-033, Conclusion of Law 19 at 38.) The SWH pilot in the SDG&E
         territory, budgeted at $3 million, was allowed to proceed to provide useful
         information on SWH incentives in general. (Id., Conclusion of Law 20.)
               In February 2007, the Commission approved the SWH pilot budget of
         $2.59 million and the pilot began operation in the SDG&E territory on
         July 2, 2007, with a scheduled end date of December 31, 2008.2 In D.08-06-029,
         the Commission made minor modifications to the pilot and allowed it to run
         until December 31, 2009 or until the budget is exhausted, whichever occurs first.
               In late 2007, the Governor signed Assembly Bill (AB) 1470, authorizing the
         creation of a $250 million incentive program to promote the installation of
         200,000 SWH systems in homes and businesses that displace the use of natural
         gas by 2017. The statute requires the Commission to evaluate data from the
         SWH pilot and determine whether an SWH program is “cost effective for
         ratepayers and in the public interest” before designing and implementing an
         incentive program for gas customers. (Section 2863(a).)
         3. Overview of Staff Proposal
               On July 15, 2009, the Administrative Law Judge (ALJ) issued a ruling
         requesting comments on a proposal by the Commission’s Energy Division staff
         for an SWH incentive program as envisioned by AB 1470.3 The program would
         fund gas-displacing SWH systems on new and existing homes and businesses,

         2 See “Assigned Commissioner[s] and Administrative Law Judge’s Ruling Approving
         Solar Water Heating Pilot Program,” Rulemaking (R.) 06-03-004, February 15, 2007.
         3 “Administrative Law Judge’s Ruling Noticing Workshop and Requesting Comment
         on Staff Proposal for Solar Water Heating Program,” R.08-03-008, July 15, 2009
         (Staff Proposal).




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          38. Customers in the SDG&E area who apply for incentives from the SWH
        Pilot Program between July 15, 2009 and December 31, 2009 may apply for and
        receive any higher incentive offered through the CSI Thermal program, if they
        meet all program eligibility criteria.

                                            O R D E R

              IT IS ORDERED that:
           1. The California Solar Initiative Thermal Program set forth in Appendix A is
        adopted and shall be administered by Pacific Gas and Electric Company,
        Southern California Edison Company, Southern California Gas Company, and
        the California Center for Sustainable Energy (collectively, the California Solar
        Initiative Thermal Program Administrators).
           2. Within 60 days of this order, San Diego Gas & Electric Company shall
        revise its contract with the California Center for Sustainable Energy to specify
        that California Center for Sustainable Energy will act as Program Administrator
        for the California Solar Initiative Thermal Program in the San Diego Gas &
        Electric Company territory.
           3. Within 60 days of this order, the Commission’s Energy Division shall hold
        workshops regarding:
              a) Development of siting, installation, freeze protection, and
                 system sizing requirements to maximize solar water
                 heating system performance and guard against oversizing
                 of systems;
              b) Development of an on-line incentive calculation tool that
                 estimates natural gas or electricity displacement based on
                 solar water heating system location, design, and expected
                 performance; and
              c) Development of appropriate energy efficiency
                 improvements that reduce water heating demand and that


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                 are broadly applicable, do not require solar water heating
                 system installer to develop new competencies, do not
                 significantly increase project cost or delay installation, are
                 easily validated on system inspection, and are likely to be
                 retained by the system owner.
           4. By April 1, 2010, the California Solar Initiative Thermal Program
        Administrators, namely Pacific Gas and Electric Company, Southern California
        Edison Company, Southern California Gas Company, and the California Center
        for Sustainable Energy, shall complete development of the on-line incentive
        calculation tool and provide it to Energy Division for review.
           5. By April 1, 2010, the California Solar Initiative Thermal Program
        Administrators, namely Pacific Gas and Electric Company, Southern California
        Edison Company, Southern California Gas Company, and the California Center
        for Sustainable Energy, shall complete drafting of the single-family residential
        customer portion of the California Solar Initiative Thermal Program Handbook,
        which shall be a subset of the general market California Solar Initiative
        Handbook, and jointly submit it as an Advice Letter in order to begin accepting
        solar water heating incentive applications from single-family residential
        customers on May 1, 2010.
           6. By April 1, 2010, each California Solar Initiative Thermal Program
        Administrator, namely Pacific Gas and Electric Company, Southern California
        Edison Company, Southern California Gas Company, and the California Center
        for Sustainable Energy, shall submit a separate Advice Letter that includes: a) a
        detailed estimate of its program budget for the first year of program
        implementation, indicating direct and indirect expenses, labor and non-labor, for
        incentives, administration, market facilitation, and measurement and evaluation;




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        and b) its proposed market facilitation strategic plan and detailed budget for the
        first two years of program implementation.
           7. By May 1, 2010, the California Solar Initiative Thermal Program
        Administrators, namely Pacific Gas and Electric Company, Southern California
        Edison Company, Southern California Gas Company, and the California Center
        for Sustainable Energy, shall complete drafting of the commercial and
        multifamily project portion of the California Solar Initiative Thermal Program
        Handbook, which shall be a subset of the general market California Solar
        Initiative Handbook, and submit it as an Advice Letter in order to begin
        accepting incentive applications for commercial and multifamily projects on
        June 1, 2010.
           8. Within 180 days of this order, the Energy Division shall hold a workshop
        on the issue of the eligibility of non-solar water heating solar thermal
        technologies that displace gas usage and meet all other program requirements,
        including certification from the Solar Rating and Certification Corporation. The
        workshop should address how to estimate these technologies thermal
        displacement for incentive calculation purposes and whether performance-based
        incentives are appropriate for these systems. Following the workshop,
        Energy Division should provide a workshop report to the service list of this
        proceeding, or its successor proceeding, and the Administrative Law Judge.
           9. The California Solar Initiative Thermal Program Administrators, namely
        Pacific Gas and Electric Company, Southern California Edison Company,
        Southern California Gas Company, and the California Center for Sustainable
        Energy, may file advice letters to modify the California Solar Initiative Thermal
        Program Handbook and expand program eligibility if the Solar Rating and




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        Certification Corporation adopts certifications for additional solar thermal
        technologies such as concentrating solar collectors.
          10. The Energy Division shall monitor implementation of the California Solar
        Initiative Thermal Program and notify the Administrative Law Judge and
        assigned Commissioner if there are great disparities in participation between the
        single-family residential, commercial, and multifamily budget categories.
          11. The Energy Division shall obtain parties’ input and consult with the
        assigned Commissioner to establish the California Solar Initiative Thermal
        Measurement and Evaluation budget and scoping plan through an assigned
        Commissioner’s Ruling.
          12. The Energy Division shall issue a Request for Proposals for an
        independent entity to perform the measurement and evaluation work, as set
        forth in the assigned Commissioner’s Ruling, select the measurement and
        evaluation contractor, and oversee the measurement and evaluation work.
        Pacific Gas and Electric Company, Southern California Edison Company,
        San Diego Gas & Electric Company, and Southern California Gas Company shall
        reimburse the Commission for this measurement and evaluation contract
        according to the percentages set forth in Appendix A.
          13. In administering the California Solar Initiative Thermal Program, the
        California Solar Initiative Thermal Program Administrators, namely Pacific Gas
        and Electric Company, Southern California Edison Company, Southern
        California Gas Company, and the California Center for Sustainable Energy, shall
        perform all duties specified in Appendix A, including but not limited to the
        following:
              a) Separately submit semi-annual expense reports to the
                  Energy Division as a subset of and along with general
                  market California Solar Initiative expense reports;


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              b) Separately submit an Advice Letter with proposed
                 California Solar Initiative Thermal market facilitation
                 budgets and activities for each calendar year, which
                 addresses the activities identified in Appendix A, no later
                 than October 1 of the preceding year;
              c) Separately submit quarterly progress reports to the
                 Energy Division;
              d) Jointly host quarterly forums, in coordination with forums
                 in the general market California Solar Initiative program,
                 to obtain input from the public and interested parties on
                 the program status;
              e) Jointly ensure development and maintenance of a
                 statewide program database as directed by
                 Energy Division, and ensure program participants provide
                 system data for the database, application processing, and
                 program evaluation purposes;
              f) Determine convenient ways for customers to make a
                 combined application for energy efficiency and solar
                 incentives, although customers may not receive incentives
                 from both programs for the same solar water heating
                 system;
              g) Post weekly information on their program websites and
                 the statewide Go Solar California website regarding
                 participation and incentive levels;
              h) Provide written notification of incentive reductions to the
                 Administrative Law Judge, with a copy to the service list of
                 this or any successor proceeding, within five business days
                 following a reduction;
              i) Perform system inspections; and
              j) Coordinate measurement and evaluation activities with the
                 general market California Solar Initiative program.
          14. Energy Division shall monitor incentive caps under this program and may
        propose Program Handbook changes to adjust the caps by Commission
        resolution.



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          15. The California Center for Sustainable Energy may move no more than
        $50,000 annually from its market facilitation budget to cover administrative
        expenses.
          16. Within 90 days of this order, Pacific Gas and Electric Company, Southern
        California Edison Company, San Diego Gas and Electric Company, and Southern
        California Gas Company shall each file an advice letter to amend their
        preliminary statements and establish a memorandum account to track actual
        annual expenditures for the gas-displacing California Solar Initiative Thermal
        program, beginning on the effective date of this decision through
        December 31, 2017. On an annual basis, each utility may, in its appropriate
        ratemaking proceeding, seek recovery from its gas customers on an equal cents
        per therm basis of the prior year’s memorandum account balance, excluding
        customers participating in the California Alternate Rates for Energy Program, the
        Family Electric Rate Assistance Program, and any customers who are currently
        exempt from funding the Self Generation Incentive Program. Total expenditures
        by each utility over the duration of the California Solar Initiative Thermal
        Program may not exceed the amounts in Table 5 of this decision.
          17. The Administrative Law Judge may modify the dates set forth in this
        order as needed and for good cause to ensure effective program implementation.




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               18. Rulemaking 08-03-008 shall remain open.
                  This order is effective today.
                  Dated January 21, 2010, at San Francisco, California.


                                                            MICHAEL R. PEEVEY
                                                                      President
                                                            DIAN M. GRUENEICH
                                                            JOHN A. BOHN
                                                            TIMOTHY ALAN SIMON
                                                                     Commissioners




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                                                                Original   Cal. P.U.C. Sheet No.                  21143-E*
          San Diego Gas & Electric Company
                San Diego, California             Canceling                Cal. P.U.C. Sheet No.

                                                      SCHEDULE VNM-A                                              Sheet 1        N
                       VIRTUAL NET ENERGY METERING FOR MULTIFAMILY AFFORDABLE HOUSING                                            N

        APPLICABILITY                                                                                                            N

        Optionally available to Qualified Customers as defined in Special Condition (SC) 4, owning, renting, or
        leasing in Multi-Family Affordable Housing Accommodations as defined in SC 3, where the Owner of the
        complex has installed a solar “eligible customer-generator” with generating capacity of 1 megawatt (MW) or
        less, as defined in Schedule NEM and Public Utilities (PU) Code Section 2827, and contracts with the Utility
        to have all eligible output from the generator supplied to the Utility for the purpose of providing a credit to the
        Qualified Customers within the complex. The terms of this rate schedule shall apply to any Qualified
        Customer that is designated by the Owner on a Solar Generation Credit Allocation Request Form, unless the
        customer provides written notification to the Utility declining to receive a credit. Virtual Net Energy Metering
        (VNM) facilitates cost savings for Owners by avoiding the installation of an eligible customer-generator on
        each individual dwelling unit, and also provides Qualified Customers with the benefits that would otherwise
        be provided under Net Energy Metering (NEM). Owners that install an eligible customer-generator for the
        purpose of VNM-A may be eligible for additional up-front incentives (see SC 11).

        Service on this rate schedule must be taken in combination with the Qualified Customer’s otherwise
        applicable rate schedule (OAS). This schedule will be available to eligible customer-generators, upon
        request, on a first-come-first-served basis until the time that total rated generating capacity used by both
        NEM and VNM-A eligible customer-generators exceeds 2.5% of SDG&E’s aggregate customer peak
        demand until December 31, 2015 or until all funds available for incentives have been allocated, whichever
        comes first. VNM-A Customers are not eligible to take service under SDG&E Schedule DR-SES.

        TERRITORY

        Within the entire territory served by the Utility.

        RATES

        The Qualified Customer Bill as determined under SC 8c. is applicable, less Customer’s Allocated Credit.

        SPECIAL CONDITIONS
        1. Definitions: The Definitions of terms used in this schedule are found either herein or in Rule 1.
        2. Treatment of Generation: Eligible customer-generators that are installed and utilized in providing service
           under terms of this rate schedule shall be treated as though they were installed and utilized under terms
           of Schedule NEM, unless otherwise specified herein.
        3. Affordable Housing Multi-Family Accommodations: Per PU Code Section 2852, is multi-family housing
           that meets at least one of following criteria:
            a) Residential housing financed with low-income housing tax credits, tax-exempt mortgage revenue
               bonds, general obligation bonds, or local, state, or federal loans or grants, and for which the rents of
               the occupants who are lower income households, as defined in Section 50079.5 of the Health and
               Safety Code, do not exceed those prescribed by deed restrictions or regulatory agreements pursuant
               to the terms of the financing or financial assistance.

            b) A residential complex in which at least 20 percent of the total units are sold or rented to lower
               income households, as defined in Section 50079.5 of the Health and Safety Code, and the housing
               units targeted for lower income households are subject to a deed restriction or affordability covenant
               with a public entity that ensures that the units will be available at an affordable housing cost, as
               defined in Section 50052.5 of the Health and Safety Code, or at an affordable rent, as defined in
               Section 50053 of the Health and Safety Code for a period of at least 30 years.                                    N

                                                                 (Continued)
        1C12                                                      Issued by                   Date Filed          Apr 17, 2009
        Advice Ltr. No.    2064-E-A                           Lee Schavrien                   Effective            Jun 8, 2009
                                                             Senior Vice President
        Decision No.       D.08-10-036                        Regulatory Affairs              Resolution No.




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                                                              Original   Cal. P.U.C. Sheet No.                    21144-E*
          San Diego Gas & Electric Company
                San Diego, California            Canceling               Cal. P.U.C. Sheet No.

                                                     SCHEDULE VNM-A                                                Sheet 2       N
                       VIRTUAL NET ENERGY METERING FOR MULTIFAMILY AFFORDABLE HOUSING                                            N

        SPECIAL CONDITIONS (Continued)                                                                                           N

        3. Affordable Housing Multi-Family Accommodations: (Continued)

              For the purpose of VNM-A, this definition also includes New Solar Homes Partnership (NHSP)-eligible
              Affordable housing as defined in Public Resource Code Section 25401.6.

        4. Qualified Customer: Is a customer that is: a) located on the same property as the Owner’s eligible
           customer-generator and not subdivided by governmental or private right of way nor by property owned
           by anyone other than the Owner; b) is physically connected to the same Service Delivery Point (as
           defined in Rule 16) as the Owner’s eligible customer-generator; and c) is receiving service on a rate
           schedule that would be applicable to a similar customer receiving service in combination with Schedule
           NEM.

              The Qualified Customer definition shall extend to Owner for the purpose of billing common use areas
              and unoccupied units.

        5. Owner: The Enterprise, or Entity, that owns the Multi-Family Affordable Housing Accommodations.

        6. Generator Interconnection Responsibility: To be eligible for VNM-A service, the Owner shall have an
           effective interconnection agreement with the Utility and have submitted a Solar Generation Credit
           Allocation Request to the Utility. In addition, the Owner shall have paid all costs associated with the
           Utility installing a Generator Output Meter capable of recording in 15 minute increments, any wiring,
           trenching, conduit, or other facility costs incurred by the Utility to interconnect with the Owner’s eligible
           customer-generator adjusted based on Rule 2 factors for a one-time payment. The location of the
           customer’s Generator Output Metering equipment shall be approved by the Utility, and will normally be
           grouped with the service and metering equipment for one, or more, of the tenant or house meters.

              If there is any load behind the Generation Output Meter in addition to incidental load related to the
              operation of the eligible customer-generator, SDG&E reserves the right to require, at the Owner’s
              expense, the purchase and installation of metering equipment necessary to determine the total
              generation and total usage at the interconnection point. Such usage shall be billed as a common area
              account to ensure that all eligible generation output is allocated and that netting only occurs after credits
              have been allocated.

        7. Solar Generation Credit Allocation Request Form (Form 142-02768): A form completed by the Owner
           that designates how the Energy Delivered, as defined in SC 8a., will be allocated among the tenants and
           common use of the complex. The initial Owner-designated percentage split between common use and
           tenants shall become effective on the regularly scheduled monthly meter read date closest to the date on
           which the form is received by the Utility and will remain in effect for a minimum of five years. The
           designated allocation between tenant units shall remain in effect for a minimum of twelve months. The
           Owner may submit an updated form to revise these allocations at any time thereafter. These additional
           adjustments must also remain effective for at least twelve months. Modified Solar Generation Credit
           Allocation Request Forms shall become effective on the first regularly scheduled monthly meter read
           date that is at least 15 days following receipt by the Utility.

              The Owner shall bear responsibility for ensuring that the percent allocations for individual Qualified
              Customers are based on the relative size of the tenant’s unit, consistent with the manner in which
              affordable housing rents are established. Each tenant unit in the complex must receive a percent
              allocation of the total tenant-designated credit. Credit that is allocated to a particular unit, but not
              applied to a Qualified Customer’s bill due to occupant nonparticipation or unit vacancy (no active                 N
              account) will be retained by the Utility.

                                                               (Continued)
        2C9                                                     Issued by                   Date Filed            Apr 17, 2009
        Advice Ltr. No.    2064-E-A                          Lee Schavrien                  Effective              Jun 8, 2009
                                                          Senior Vice President
        Decision No.       D.08-10-036                     Regulatory Affairs               Resolution No.




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                                                             Revised    Cal. P.U.C. Sheet No.                  21618-E
         San Diego Gas & Electric Company
               San Diego, California            Canceling    Original   Cal. P.U.C. Sheet No.                 21145-E*

                                                    SCHEDULE VNM-A                                             Sheet 3
                      VIRTUAL NET ENERGY METERING FOR MULTIFAMILY AFFORDABLE HOUSING


       SPECIAL CONDITIONS (Continued)

       8. Billing Process: The following billing process shall be used.

             a) Energy Delivered: The metered output, delivered to the grid, as recorded by the Generator Output
                Meter and validated by the appropriate Utility billing processes during the specific billing period.

             b) Allocation of Credit: Monthly allocated Credits for common areas and Qualified Customers are
                determined by multiplying the monthly Energy Delivered (kWh) by the percentages contained in the
                Solar Generation Credit Allocation Request Form on file with the Utility, and then converting each
                kWh credit to dollars using the Qualified Customer’s OAS.

             c) Qualified Customer Bill: The OAS for each Qualified Customer, adjusted to conform to the conditions
                set forth in Schedule NEM. Qualified Customers served under this schedule are responsible for all
                charges from their OAS including monthly billed minimum charges, customer charges, meter
                charges, facilities charges, energy and demand charges, excluding any adjustments due to power
                factor provisions. Applicable demand charges are defined in the OAS.

             d) Virtual Net Energy Metering and Billing: VNM means measuring the difference between the electric
                energy supplied by the Utility to Qualified Customers and the electric energy generated by an eligible
                customer-generator, fed to the electric grid, and credited to Qualified Customers over a 12-month
                period (Relevant Period).

                 At the end of each Relevant Period following the Qualified Customer’s date of SDG&E’s written
                 authorization for the eligible customer-generator’s parallel Operation with SDG&E’s electrical system,
                 the Qualified Customer shall be billed for net electric energy used during that period. If a Qualified
                 Customer terminates service under this rate schedule prior to the end of any Relevant Period, the
                 Utility shall reconcile the customer’s consumption of electric energy with any remaining credit, and
                 bill the customer as if it were the end of the normal Relevant Period.

                 (1) For an OAS with Baseline Rates:

                      If the Qualified Customer is a net consumer for the month, the net kWh consumed shall be billed
                      in accordance with the Qualified Customer’s OAS. If the Qualified Customer is a net generator,
                      the net kWh generated shall be valued at the applicable baseline rates up to the billing period’s
                      baseline allowance, with any excess kWh generated valued at the applicable non-baseline rates.

                 (2) For an OAS with Time-of-Use Rates

                      If the Qualified Customer is a net consumer during any discrete TOU period, the net kWh
                      consumed shall be billed at the applicable TOU rates charged in the OAS. If the Qualified
                      Customer is a net generator, the net kWh generated shall be valued at the applicable TOU rates
                      charged in the OAS.



                                                                                                                             D




                                                              (Continued)
       3C7                                                     Issued by                   Date Filed          Feb 1, 2010
       Advice Ltr. No.     2145-E                           Lee Schavrien                  Effective           Feb 1, 2010
                                                         Senior Vice President
       Decision No.                                       Regulatory Affairs               Resolution No.




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                                                              Revised    Cal. P.U.C. Sheet No.                    21619-E
          San Diego Gas & Electric Company
                San Diego, California            Canceling    Original   Cal. P.U.C. Sheet No.                   21146-E*

                                                     SCHEDULE VNM-A                                               Sheet 4
                            VIRTUAL NET METERING FOR MULTIFAMILY AFFORDABLE HOUSING


        SPECIAL CONDITIONS (Continued)
                                                                                                                                N
              Assembly Bill 920: Pursuant to Assembly Bill 920, starting January 1, 2011, a NEM customer with "net
              surplus electricity" (all electricity generated by an eligible customer measured in kilowatt-hours that
              exceeds the amount of electricity consumed by that eligible customer over a 12-month period), will be
              provided with options regarding net surplus compensation, which valuation remains subject to further
              Commission action. Until then, NEM customers may choose to:

                       (i) Begin the tracking of surplus energy at the end of the customer’s current 12-month relevant
                           period; or
                       (ii) Begin the tracking of surplus energy immediately, thereby establishing a new 12-month
                            relevant period. Under this option, SDG&E will perform the normal reconciliation of the
                            customer’s account and the new 12-month relevant period will begin on the next regularly-
                            scheduled meter read date. Under this selection, any surplus electricity available at the time
                            of selecting the new relevant 12-month period will be zeroed out; or
                       (iii) Not receive any true-up net surplus electricity compensation by notifying SDG&E in writing
                             that they do not wish to participate                                                               N

        9. Monthly Billing: The Utility shall provide Qualified Customers with eligible customer-generator production
           and individual consumption information with each regular monthly bill. The information shall include the
           current monetary balance owed to the Utility for the net energy consumed in the current Relevant Period.
           Qualified Customers shall pay any balance due for net energy consumed monthly. Any remaining credit
           over a monthly billing cycle shall be carried over to the following monthly billing period, until the end of
           the Relevant Period.

              Qualified Customers shall not be eligible for the Level Pay Plan option set forth in Rule 9.

        10. Generator Limitation: No generator shall be included behind the above described Generator Output
            Meter other than a Solar Generator.

        11. Multifamily Affordable Solar Housing (MASH) Installation Incentives: D.08-10-036 established a $108
            million solar incentive program for MASH. Under the approved incentive structure, an Owner may obtain
            an up-front rebate for the installation of a qualifying solar energy system, based on an estimate of system
            performance using the Expected Based Buydown (EPBB) methodology. Owners will receive $3.30 per
            watt for systems offsetting common use and $4.00 per watt for systems offsetting tenant load. An
            installation may receive both incentive levels if it will offset both common area and tenant load. These
            incentives will be apportioned in accordance with the Owner’s initial five-year allocation.




        4C7                                                     Issued by                   Date Filed            Feb 1, 2010
        Advice Ltr. No.     2145-E                           Lee Schavrien                  Effective             Feb 1, 2010
                                                          Senior Vice President
        Decision No.                                       Regulatory Affairs               Resolution No.




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        ALJ/DKF/sid                             Date of Issuance 9/5/2008


        Decision 08-09-012 September 4, 2008

        BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

        Order Instituting Rulemaking to Integrate
        Procurement Policies and Consider Long-Term            Rulemaking 06-02-013
        Procurement Plans.                                    (Filed February 16, 2006)




                          (See Appendix A for a list of appearances.)


                       DECISION ON NON-BYPASSABLE CHARGES
                            FOR NEW WORLD GENERATION
                                AND RELATED ISSUES




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        R.06-02-013 ALJ/DKF/sid


                                                   TABLE OF CONTENTS

                   Title                                                                                                    Page

         DECISION ON NON-BYPASSABLE CHARGES ...................................................... 2
         FOR NEW WORLD GENERATION ............................................................................ 2
         AND RELATED ISSUES ................................................................................................ 2
            1. Summary ........................................................................................................... 2
            2. Background....................................................................................................... 4
                2.1. D.04-12-048 ............................................................................................... 7
                2.2. D.06-07-029 ............................................................................................... 8
            3. Guiding Principles ......................................................................................... 10
            4. Applicability of Stranded Cost Recovery and Net Cost
                Allocation NBCs............................................................................................. 11
                4.1. Forecasted Departing Load.................................................................. 11
                     4.1.1. Positions of the Parties ............................................................. 13
                     4.1.2. Discussion................................................................................... 14
                     4.1.3. TURN’s Recommendation for a Binding Notice of Intent
                             Process ........................................................................................ 26
                     4.1.4. Effect of Large Municipalizations........................................... 27
                     4.1.5. New Western Area Power Administration (WAPA)
                             Departing Load and Split Wheeling Departing Load ......... 30
                4.2. AReM’s Request for Confirmation Regarding
                     Customers Currently Eligible to Return to DA................................. 32
                     4.2.1. Parties’ Positions ....................................................................... 32
                     4.2.2. Discussion .................................................................................... 35
                4.3. Above-Market Standard Offers for New QF Contracts................... 37
                4.4. Other Applicability Related Issues that Will Not Be Addressed in
                     this Proceeding....................................................................................... 38
            5. Framework for the D.04-12-048 NBC.......................................................... 39
            6. Implementation Issues for Cost Allocation Under D.04-12-048 ............. 39
                6.1. Total Portfolio and Separate Charge Approaches ............................ 40
                     6.1.1. Positions of the Parties ............................................................. 40
                         6.1.1.1. Total Portfolio .................................................................. 40
                         6.1.1.2. Separate Charge............................................................... 44
                     6.1.2. Discussion................................................................................... 45
                         6.1.2.1. The Handling of Negative Charges.............................. 45
                         6.1.2.2. Pre-restructuring Resources not Subject to Ongoing
                                   CTC Treatment ................................................................ 49


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                              6.1.2.3. The 10-Year Limitation on Cost Recovery Under
                                             D.04-12-048 ....................................................................... 52
                              6.1.2.4. RPS Resources .................................................................. 55
                              6.1.2.5. Future Modifications....................................................... 57
                              6.1.2.6. Summary........................................................................... 58
                 6.2. Vintaging................................................................................................. 59
                       6.2.1. Positions of the Parties ............................................................. 60
                       6.2.2. Discussion................................................................................... 64
                 6.3. Calculation of the D.04-12-048 NBC ................................................... 68
                       6.3.1. Areas of Agreement .................................................................. 69
                       6.3.2. Levelized Fixed Costs............................................................... 70
                       6.3.3. Determination of Capacity Adders and Line Loss
                                    Adjustments ............................................................................... 71
                 6.4. Cost-Effectiveness.................................................................................. 72
                       6.4.1. ALJ Questions ............................................................................ 72
                       6.4.2. Responses to the IOU Exhibits ................................................ 74
                       6.4.3. Discussion................................................................................... 77
                 6.5. Additional Issues ................................................................................... 80
                       6.5.1. Limit on NBCs ........................................................................... 80
                       6.5.2. Cost Recovery Period for non-RPS PPAs .............................. 81
             7. Framework for the D.06-07-029 NBC.......................................................... 81
             8. Implementation Issues for Cost Allocation Under D.06-07-029 ............. 84
                 8.1. Use of the DA CRS................................................................................. 85
                       8.1.1. Discussion................................................................................... 86
                 8.2. Inclusion of the Charge under the DA CRS Cap .............................. 86
                       8.2.1. Discussion................................................................................... 87
                 8.3. Five-Year Limitation ............................................................................. 88
                       8.3.1. Discussion................................................................................... 90
             9. Comments on Proposed Decision ............................................................... 90
                 9.1. Applicability of the NBCs .................................................................... 91
                 9.2. The D.04-12-048 NBC ............................................................................ 94
             10. Assignment of Proceeding............................................................................ 95
         Findings of Fact ............................................................................................................. 95
         Conclusions of Law..................................................................................................... 104
         ORDER.......................................................................................................................... 107




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         APPENDIX A – List of Appearances
         APPENDIX B – List of Acronyms and Abbreviations
         APPENDIX C – List of Terms
         APPENDIX D – Summary of Consumer Responsibility for Various IOU/DWR
                      Cost Elements
         APPENDIX E – Cost Responsibility Surcharge Calculations




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                          DECISION ON NON-BYPASSABLE CHARGES
                               FOR NEW WORLD GENERATION
                                   AND RELATED ISSUES
         1. Summary
               By this decision, we implement new generation1 non-bypassable charges
         (NBCs) previously established by Decision (D.) 04-12-048 and D.06-07-029. The
         applicability and form of these charges are determined for customers of the
         investor-owned utilities (IOUs)2 that choose direct access (DA)3 service or the
         services of a community choice aggregator (CCA),4 as well as municipal
         departing load (MDL)5 and customer generation departing load (CGDL)6
         customers. Among other things, this decision:

         1 New generation includes generation from both fossil fueled and renewable resources
         contracted for or constructed by the investor-owned utilities subsequent to January 1,
         2003.
         2 Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric Company
         (SDG&E) and Southern California Edison Company (SCE).
         3 DA load customers purchase electricity from an independent electric service provider
         (ESP) and receive transmission and distribution service from the IOU.
         4 CCAs are governmental entities formed by cities and counties to serve the energy
         requirements of their local residents and businesses. The IOU continues to provide
         transmission and distribution service.
         5 Departing load (DL) generally refers to retail customers who were formerly IOU
         customers but now receive energy, transmission and distribution services from publicly
         owned utilities, self-generation or other means. MDL refers to DL served by a “publicly
         owned utility” (POU) as that term is defined in Public Utilities Code Section 9604(d),
         including municipalities or irrigation districts. There are two categories of MDL:
         transferred MDL and new MDL. Transferred MDL is load that was served by an IOU
         on or after December 20, 1995, and subsequently departed to be served by a POU.
         (Resolution E-4064, p. 1, fn. 1.) MDL also includes new MDL, which is load that has
         never been served by an IOU but is located in an area that had previously been in the
         IOU’s service territory (as that territory existed on February 1, 2001) and was annexed
         or otherwise expanded into by a POU.” (Resolution E-4064, p. 1, fn.1.)




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               1. Determines that once departed from bundled service, MDL (with
                  the exception of large municipalizations) and CGDL will not
                  have to pay the new generation related NBCs because, by
                  procuring resources based on LTPP forecasts that exclude CGDL
                  and MDL classes, the IOU will not have incurred costs on behalf
                  of these customers.

               2. Determines that for large municipalizations whose loads are
                  included in the adopted load forecasts, the Commission will
                  address the cost responsibility for payment of the new generation
                  related NBCs through an application process.

               3. Determines that the new generation NBC authorized by
                  D.04-12-048 should be implemented as a component of the cost
                  responsibility surcharge (CRS).7 The revised CRS shall be
                  calculated on the following bases:




         (footnote continued from previous page)

         6 The term “Customer Generation” refers to cogeneration, renewable technologies, or
         any other type of generation that (a) is dedicated wholly or in part to serve a specific
         customer’s load; and (b) relies on non-utility or dedicated utility distribution wires
         rather than the utility grid, to serve the customer, the customer’s affiliates and/or
         tenant’s, and/or not more than two other persons or corporations.
         7 The other components include the ongoing competition transition charge (ongoing
         CTC), and Department of Water Resources (DWR) power and bond charges. For
         PG&E, DA and non-exempt MDL are responsible for the Energy Charge Recovery
         Amount (ECRA), formerly the regulatory asset charge, which recovers PG&E’s
         bankruptcy-related costs pursuant to D.03-12-035. This charge was included as an
         element to be collected from CRS in D.04-02-062. Pursuant to D.04-11-015, the ECRA
         superseded and replaced the regulatory asset charge on March 1, 2005. For SCE, DA
         and DL were responsible for the historical procurement charge (HPC), which recovers
         costs from a settlement of the filed rate case in federal court. SCE has fully recovered
         this charge, and the HPC is no longer being collected.




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                   • With a few exceptions, use of a total portfolio approach that
                     accounts for the ongoing CTC, DWR power charges and
                     D.04-12-048 charges.8 This includes netting the individually
                     calculated annual charges and carrying over any negative
                     total charge to offset positive charges in subsequent years.
                     Further, we determine that pre-restructuring resources9
                     should continue to be included in the portfolio of resources
                     used in determining any ongoing CTC and D.04-12-048
                     charges, once cost recovery of the DWR contracts ends.
                     Finally, we will address the effects of the 10-year limitation on
                     cost recovery of new non-renewable portfolio standard (RPS)
                     generation resources on bundled customer indifference, on a
                     case-by-case basis, if and when the IOUs request cost recovery
                     extensions, pursuant to the provisions of D.04-12-048.
                   • Use of the market benchmark adopted in D.06-07-030, as
                     modified by D.07-01-030, to determine above-market costs.
                   • Use of a vintaging methodology based on the calendar year in
                     which customers depart and on whether they depart in the
                     first or second half of the calendar year.

         2. Background
               Track 3 of Phase II of this proceeding was established in March 2007 to
         separately address NBCs and related issues. Specifically, Track 3 and this

         8 Public Utilities Code Section 367(a) sets forth the method for the calculation of the
         ongoing CTC. Also, in some situations, there will be departing load customers who do
         not pay the DWR power charges, and thus, the total portfolio method (indifference
         calculation) is not applicable in calculating ongoing CTC. (See D.07-01-020, p. 5 &
         D.06-07-030, pp. 35-38; see also D.05-01-035, p. 3.) (Order modifying Resolution E-3831
         and denying rehearing of Resolution, as modified.)
         9 For purposes of this decision, “pre-restructuring resources” refers to those current
         IOU resources that existed prior to March 31, 1998 and are not subject to ongoing CTC
         treatment. These resources consist principally of the IOUs’ retained generation (i.e.,
         hydro, coal and nuclear plants). Power from these resources tends to be cheaper when
         compared to the costs related to ongoing CTC, the DWR contracts and new generation.




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          25. This decision should be made effective immediately.


                                          O R D E R

              IT IS ORDERED that:
           1. Decision (D.) 04-12-048 and D.06-07-029 non-bypassable charges (NBCs)
        shall be imposed on direct access (DA) and community choice aggregation
        customers, as well as new Western Area Power Administration (WAPA)
        departing load and split wheeling departing load customers.
           2. Because customer generation departing load (CGDL) and municipal
        departing load (MDL) are excluded, as classes, from the adopted load forecasts
        on which the investor-owned utilities (IOUs) long term procurement plans
        (LTPPs) are based, CGDL and MDL customers are excluded from having to pay
        the D.04-12-048 and D.06-07-029 NBCs, including any above market costs related
        to RPS contracts, with the exception of those customers described in Ordering
        Paragraph 3.
           3. Consistent with the provisions in this decision, an IOU may file an
        application requesting implementation of the D.04-12-048 and D.06-07-029 NBCs
        on departing load associated with a large municipalization. In the application,
        the IOU should demonstrate how the loads of these customers were included in
        an adopted load forecast, establishing that the IOU reasonably incurred costs on
        behalf of such customers. The Commission will determine the fair share of these
        customers for paying the D.04-12-048 and D.06-07-029 costs based on a departure
        date established through a binding notice of intent or alternative process.
           4. Bundled service customers who are eligible to return to direct access shall
        not be excluded from having to pay the NBC associated with D.04-12-048.



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           5. The IOUs are allowed to recover the above-market costs of new qualifying
        facilities standard offer contracts through the D.04-12-048 NBC.
           6. As described in the body of this decision, the D.04-12-048 NBC shall be
        implemented as a component of the cost responsibility surcharge (CRS),
        calculated on a total portfolio basis with the netting of individually calculate
        annual charges and the carrying over of negative total charges for use in
        offsetting positive charges in subsequent years.
           7. Pre-restructuring resources shall continue to be included in the portfolio of
        resources used in determining D.04-12-048 charges, once recovery of DWR
        power costs ends.
          8. If, due to future changing circumstances, the processes adopted by this
        decision for determining the D.04-12-48 NBC become unworkable, unbalanced,
        or unfair, parties may propose and request modifications to the form of the NBC
        or how the NBC should be determined or calculated.
           9. The Alliance for Retail Energy Market’s request to defer the development
        of a vintaging system for DA customers to Rulemaking (R.) 07-05-025 is denied.
          10. A vintaging (date of departure) methodology, where customers leaving in
        the first half of any particular year would be responsible for stranded costs
        associated with new generation resource commitments made through the end of
        the previous year, and where customers leaving in the second half of any
        particular year would be responsible for stranded costs associated with new
        generation resource commitments made through the end of that particular year,
        is adopted.
          11. Levelized fixed cost recovery shall not be used in determining the
        D.04-12-048 NBC.




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        R.06-02-013 ALJ/DKF/sid


          12. The D.04-12-048 NBC 10-year cost recovery period for power purchase
        agreements (PPAs) shall begin with the commencement of operation of the
        project.
          13. To the extent that large municipalization, new WAPA departing load or
        split wheeling departing load customers are subject to the cost allocation
        mechanism (CAM), the departing customers should be responsible for any
        uneconomic PPA costs which are represented by the total annual PPA cost, less
        energy auction revenues, less the value of the resource adequacy (RA) credit,
        with the IOU retaining the RA credit for its own use.
          14. The DA CRS and the D.06-07-029 NBC shall be calculated and billed as
        separate items.
          15. The D.06-07-029 NBC shall not be included under a 2.7 cent per kilowatt
        hour DA CRS cap.
          16. The maximum term length of the CAM shall remain at 10 years, as
        adopted in D.06-07-029.
          17. The Northern California Power Association’s Motion for Party Status, filed
        August 14, 2008, is granted.
          18. R.06-02-013 is closed.
              This order is effective today.
              Dated September 4, 2008, at San Francisco, California.


                                                         MICHAEL R. PEEVEY
                                                                   President
                                                         DIAN M. GRUENEICH
                                                         JOHN A. BOHN
                                                         RACHELLE B. CHONG
                                                         TIMOTHY ALAN SIMON
                                                                 Commissioners


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        A.08-11-014 ALJ/DUG/lil




                             ATTACHMENT A




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                                     A.08-11-014
                     SAN DIEGO GAS & ELECTRIC COMPANY (U 902 E)
             APPLICATION FOR AUTHORITY TO UPDATE MARGINAL COSTS, COST
                       ALLOCATION, AND ELECTRIC RATE DESIGN

                                       SETTLEMENT AGREEMENT
                                             May 22, 2009

            No element of this Settlement Agreement shall be deemed precedential as to the
            Commission or any of the Parties, either in the context of this San Diego Gas & Electric
            Company (SDG&E) 2009 Rate Design Window (“RDW”) -- Application 08-11-014,
            proceeding or in any future proceeding, and no Party shall use the contents of this
            Settlement, or any documents, discussions or other communications related to this
            Settlement, against any other Party in future Commission proceedings.


            1. General: Unless otherwise specified, Parties stipulate to all proposals and
            assumptions in SDG&E’s RDW application and supporting testimony, as listed in
            APPENDIX A.

            RESIDENTIAL ISSUES

            2. California Alternate Rates for Energy (“CARE”) Rates: Parties agree to SDG&E’s
            proposed reduction in CARE tier 3 rates in this RDW proceeding. Subsequently, CARE
            tier 3 rates will be frozen (no upward or downward movement) at this level until the next
            General Rate Case Phase II or until superseded by any CARE rate design provisions in
            Assembly Bill (“AB”) 1X reform legislation that is passed and becomes law. See
            APPENDIX B for the proposed unbundled unit charges for residential non-CARE and
            CARE customers that would become effective with the implementation of this rate design
            window.

            3. Baseline Allowances: SDG&E proposed to reduce the residential baseline allowances
            over a three year period to the higher of the level identified by Public Utilities Code
            section 739 or the level in effect in 2001 when AB 1X was passed. Parties agree to
            SDG&E’s proposed baseline reduction for year 1 effective January 1, 2010, upon
            implementation of the 2008 RDW rates. If AB 1X reform legislation is passed and
            becomes law, then there will be no further reduction in baseline allowances stemming
            from this settlement. If there is no enactment of AB 1X reform legislation by October 31,
            2010, Parties further agree to SDG&E’s year 2 reduction in baseline allowances and that
            this change will take place on January 1, 2011. Parties are not precluded by this
            settlement from making proposals for changes to SDG&E’s baseline allowances in
            subsequent regulatory proceedings. See APPENDIX C for the proposed baseline
            allowances that would become effective with the implementation of this rate design
            window and the proposed baseline allowances for year 1 and year 2 under the conditions
            set forth herein. In APPENDIX C, the percentage of average residential usage column in
            APPENDIX C is provided for informational purposes only. The above agreement



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            establishes the baseline quantities shown in APPENDIX C. The schedule in APPENDIX
            C supersedes and replaces Attachment RWH-1 contained in the Prepared Revised Direct
            Testimony of Robert W. Hansen (served January 27, 2009).

            4. Residential Rate Presentment: Residential Rate Presentment: The Parties concur as
            to the importance of making aggregated kWh rate information available to residential
            customers. Thus, SDG&E agrees to provide residential customers the ability to view
            their total kWh rates by tier, first as a web-based presentation and second on a customer's
            bill. SDG&E will provide on its website for each group of Residential, Residential-Low
            Income, and Residential-Direct Access customers their total kWh rates by tier no later
            than December 31, 2009. Prior to this date, SDG&E will provide a draft website
            presentation to Division of Ratepayer Advocates (“DRA”) and Utility Consumers’ Action
            Network (“UCAN”) for their advice and comment, and will work in good faith to
            incorporate such advice and comment into the final website presentation that will be
            made available to residential customers. SDG&E also agrees to work in good faith with
            DRA and UCAN to provide an estimate of the total costs, timeline and format related to
            creating a customer bill presentment version of the above website presentation no later
            than June 1, 2010.

            OTHER ISSUES

            5. Critical Peak Pricing (“CPP”): Existing CPP Bill Protection shall be extended as
            follows:
                a. A customer that defaulted to, and received service under, CPP-D during the
                   summer of 2008 and remains on CPP-D through the summer of 2009 would be
                   provided with twelve additional months of bill protection.
                b. A customer that defaulted to, and opted-out of CPP-D during the summer of 2008
                   would be provided with 12 months of bill protection in the event it chooses to opt-
                   in and receive service under CPP-D during the summer of 2009.
                c. The existing bill protection provisions of Schedule EECC-CPP-D, Special
                   Condition 8 remain unchanged.

            6. Medium and Large Commercial & Industrial (“C&I”) Class Split: SDG&E’s
            proposed Medium and Large C&I class split at 500 kW shall not be implemented.

            7. Revisions to Schedule OL-2: Special Condition 6: Incidental Loads. Incidental,
            non-lighting loads may be served under this Schedule only where such connected loads
            for that meter do not exceed 15 percent of the customer’s total connected load. Incidental
            Loads must also be controlled for dusk to dawn operation exclusively.

            A customer seeking service under this Schedule may split its load at a premise in order to
            separately meter load that is not controlled for exclusive dusk to dawn operation. Such
            separately metered load, not served under this Schedule, shall be billed in accordance
            with the applicable rate schedule. The customer shall be responsible for all costs
            associated with splitting load, including costs incurred by SDG&E.




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            8. Miscellaneous Add-ons to the Medium and Large C&I Distribution Rate:
            SDG&E agrees to withdraw its proposal for allocation and rate design of Miscellaneous
            Add-on costs for the medium and large C&I class. Rate changes occurring prior to the
            next rate proceeding associated with Miscellaneous Add-ons will be made on a
            proportional basis to recover the amount allocated to the C&I class.

            9. Creation of Tariff Schedule OL-TOU: SDG&E will create a new SDG&E rate
            schedule titled OL-TOU. This schedule will have the same rates and structure as the
            current A-TOU, but will be limited in its applicability. See APPENDIX D.

            Applicability
            Applicable to metered outdoor area lighting load, not including street or highway
            lighting, controlled for nighttime operation and used for sports and recreation areas.
            Incidental, non-outdoor area lighting load shall be served under this schedule if the
            incidental load meets the following conditions: 1) does not exceed 15 percent of the
            customer’s Maximum Monthly Demand and 2) does not exceed 20 kW, regardless of the
            time such incidental load operates. Service under this schedule is not applicable to any
            customer whose monthly maximum demand is less than 20 kW and whose incidental
            load causes a summer on-peak demand that equals, exceeds, or is expected to equal or
            exceed 20 kW for three consecutive billing periods.

            In addition, the following definition will be added to the schedule for clarification:

                   Nighttime and daytime operation is defined as the following hours:

                   Summer
                   Daytime: 6 a.m. – 6 p.m. Weekdays
                   Nighttime: 6 p.m. – 6 a.m. Weekdays, plus Weekends and Holidays

                   Winter
                   Daytime: 6 a.m. – 5 p.m. Weekdays
                   Nighttime: 5 p.m. – 6 a.m. Weekdays, plus Weekends and Holidays


            ///

            ///




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                                APPENDIX A




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                                                APPENDIX A
                                        SETTLEMENT AGREEMENT,
                                           Item No. 1 – GENERAL

            Parties hereby stipulate to the adoption of the following terms:

               1. SDG&E’s allocation of costs to customer classes as presented in the Prepared
                  Revised Direct Testimony of James S. Parsons (January 27, 2009), except that
                  results for the Medium Commercial and Large C&I classes will be combined
                  since SDG&E’s proposed split of the Medium and Large C&I class is not adopted
                  pursuant to Settlement Agreement, Item 6.

               2. SDG&E’s rate design and allocation tables contained in SDG&E’s Settlement
                  Testimony, which is being served concurrently with the filing of the Motion for
                  Adoption of Joint Party Settlement, supersede and replace the rate design and
                  allocation tables contained in the Prepared Revised Direct Testimonies of Robert
                  W. Hansen and James S. Parsons (served January 27, 2009). The rate design
                  tables contained in SDG&E’s Settlement Testimony show the present and
                  proposed cost allocation, present and proposed rate tables, bill impact tables, and
                  allocation tables have been updated to reflect the Settlement Agreement terms.
                  Proposed rate changes to be implemented January 1, 2010.

               3. Elimination of Residential and Small Commercial Customer Time of Use
                  (“TOU”) metering charges on January 1, 2010, as described in the Prepared
                  Revised Direct Testimony of Robert W. Hansen (served January 27, 2009).

               4. Recovery of Residential California Solar Initiative (“CSI”) costs will be
                  simplified to an equal-cents-per-kWh charge applicable to all non-exempt
                  residential usage, as described in the Prepared Revised Direct Testimony of
                  Robert W. Hansen (served January 27, 2009).

               5. SDG&E’s miscellaneous tariff clean-up proposals, as described in the Prepared
                  Revised Direct Testimony of Robert W. Hansen (served January 27, 2009) and
                  the Prepared Supplemental Testimony of Robert W. Hansen (served January 30,
                  2009). Specifically, SDG&E’s tariff language changes to:

                       a.   Schedule EV-TOU (modification to electric vehicle rate options);
                       b.   Schedule EV-TOU2 (modification to electric vehicle rate options);
                       c.   Schedule EV-TOU3 (modification to electric vehicle rate options);
                       d.   Schedule DG-R (clarification that this schedule is not limited to customers
                            that own distributed generation);
                       e.   Clarification of language on the minimum bill applicable to residential
                            customers;
                       f.   CPP-D Special Condition 3 (clarification regarding the default rate);
                       g.   CPP-D Special Condition 15 (correction of inadvertent omission);
                       h.   CPP-E Special Condition 15 (reflection of correction to CPP-D);



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                      i. Clarification on daylight savings time language in Schedule DR-SES;
                      j. Elimination of Rule 24 and all associated tariff references.

               6. SDG&E’s distribution rate for Schedule LS-3 will be realigned with the rest of
                  the lighting class, as described in the Prepared Revised Direct Testimony of
                  Robert W. Hansen (served January 27, 2009).

               7. SDG&E’s proposal of a new Sports Field Outdoor Lighting tariff Schedule OL-2,
                  as described in the Prepared Revised Direct Testimony of Robert W. Hansen
                  (served January 27, 2009), subject to Settlement Agreement, Item 7.

               8. SDG&E’s sales forecasts, as presented in the Prepared Direct Testimony of Greg
                  Katsapis (served November 14, 2008), which shows the following projected sales
                  for 2009:
                         Residential                          7,829 sales (GWh)
                         Commercial/Industrial/Agriculture 12,950 sales (GWh)
                         Street Lighting                      111 sales (GWh)
                         TOTAL                                20,890 sales (GWh)

               9. Modification of SDG&E’s CPP rate so that CPP events can be called any day of
                  the week, year round, as described in the Prepared Direct Testimony of James
                  Spurgeon (served November 14, 2008).

               10. Modification of SDG&E’s CPP rate so that CPP customers default to CPP only
                   after SDG&E’s billing and systems upgrades have been completed and customers
                   have had an Advanced Metering Initiative (“AMI”) meter for at least 12 months,
                   as described in the Prepared Direct Testimony of James Spurgeon (served
                   November 14, 2008).

               11. Planned implementation of the Peak Time Rebate (“PTR”) for Small Non-
                   Residential Customers will be eliminated, as described in the Prepared Direct
                   Testimony of James Spurgeon (served November 14, 2008).

               12. Residential PTR credits will be based on a per-event basis rather than total usage
                   PTR, upon the full deployment of SDG&E’s AMI meters and completion of the
                   meter data management and billing system modifications required to bill PTR
                   credits on a per-event basis. The Residential PTR tariff will be changed to reflect
                   the term above. See Prepared Direct Testimony of James Spurgeon (served
                   November 14, 2008).

               13. Implementation of a memorandum account to track the reasonable incremental
                   costs that SDG&E expects to incur a result of implementing a time-of-use rate,
                   coupled with a default CPP rate for approximately 120,000 customers that have
                   only previously been exposed to a flat rate. (See Prepared Direct Testimony of
                   James Spurgeon (served November 14, 2008).




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                               APPENDIX B




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                                                                                                                                                                                                      APPENDIX B
                                                                                                                                                                                     SAN DIEGO GAS & ELEC TR IC COM PANY
                                                                                                                                                                                    Rate De sign W ind ow Application (A.) 0 8-11-014

                                                                                                                                                                          PROPOS ED UNBUNDLED UNIT CHARGES FOR SCHEDULE DR AND DR-LI


                                                                                                                                                      TRANS           DIS T          PPP            ND          CTC            RS          TRAC       TOTAL UDC    E ECC      DWR BOND    20% CA RE    TOTAL
                                                                                            LINE            DESCRIPT IO N               UNITS          RATE           RA TE          RA TE         RATE         RA TE         RATE         RATE         RA TE      RATE         RATE      DISCOUNT      RA TE
                                                                                            NO.                 (A)                      (B)            (C)            (D)            (E)           (F)          (G)           (H )         (I)          (J)         (K )        (L)         (M)         (N )


                                                                                             1     SC HEDULE DR
                                                                                             2     Ba si c Service Fee               $/Month              0.0 0           0.00         0.0 0         0.0 0           0.00        0.00        0 .00        0.00        0.00        0.00       --            0. 0
                                                                                             3     Su mm er
                                                                                             4      B aseline E nergy                $/kWh            0.0128 4        0.067 82     0.0033 4      0.0004 6      0.00209       0.00 051    (0.06 877)    0.01 829   0 .105 47    0.004 91      --        0 .128 6
                                                                                             5      1 01% t o 13 0% o f B aseli ne   $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051    (0.05 788)    0.03 846   0 .105 47    0.004 91      --        0 .148 8
                                                                                             6      1 31% t o 20 0% o f B aseli ne   $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051     0.08 121     0.17 755   0 .105 47    0.004 91      --        0 .287 9
                                                                                             7      A bove 200% of B aseline         $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051     0.10 121     0.19 755   0 .105 47    0.004 91      --        0 .307 9
                                                                                             8     W i nter
                                                                                             9      B aseline E nergy                $/kWh            0.0128 4        0.067 82     0.0033 4      0.0004 6      0.00209       0.00 051    (0.04 149)    0.04 557   0 .078 19    0.004 91      --        0 .128 6
                                                                                            10      1 01% t o 13 0% o f B aseli ne   $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051    (0.03 060)    0.06 574   0 .078 19    0.004 91      --        0 .148 8
                                                                                            11      1 31% t o 20 0% o f B aseli ne   $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051     0.09 248     0.18 882   0 .078 19    0.004 91      --        0 .271 9
                                                                                            12      A bove 200% of B aseline         $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051     0.11 248     0.20 882   0 .078 19    0.004 91      --        0 .291 9
                                                                                            13     Minim um Bill                     $/Da y              0.00 0          0.0 00       0.00 0        0.00 0          0 .000     0 .000       0. 000       0.170      0.0 00       0.0 00      --           0.1 7
                                                                                            14
                                                                                            15     SC HEDULE DR-LI *
                                                                                            16     Ba si c Service Fee               $/Month              0.0 0           0.00         0.0 0         0.0 0           0.00        0.00        0 .00        0.00        0.00        0.00        0.00         0. 0
                                                                                            17     Su mm er
                                                                                            18      B aseline E nergy                $/kWh            0.0128 4        0.067 82     0.0033 4      0.0004 6      0.00209       0.00 051    (0.06 386)    0.02 320   0 .105 47    0.000 00   (0.02814)    0 .100 5
                                                                                            19      1 01% t o 13 0% o f B aseli ne   $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051    (0.05 297)    0.04 337   0 .105 47    0.000 00   (0.03218)    0 .116 6




                                   Pages 169 of 375
                                                                                            20      1 31% t o 20 0% o f B aseli ne   $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051     0.02 847     0.12 481   0 .105 47    0.000 00   (0.04847)    0 .181 8
                                                                                            21      A bove 200% of B aseline         $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051     0.02 847     0.12 481   0 .105 47    0.000 00   (0.04847)    0 .181 8
                                                                                            22     W i nter
                                                                                                                                                                                                                                                                                                                      Test Year 2012 GRC - APP




                                                                                            23      B aseline E nergy                $/kWh            0.0128 4        0.067 82     0.0033 4      0.0004 6      0.00209       0.00 051    (0.03 658)    0.05 048   0 .078 19    0.000 00   (0.02814)    0 .100 5
                                                                                            24      1 01% t o 13 0% o f B aseli ne   $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051    (0.02 569)    0.07 065   0 .078 19    0.000 00   (0.03218)    0 .116 6
                                                                                                                                                                                                                                                                                                                    Non-Shared Service Workpapers




                                                                                            25      1 31% t o 20 0% o f B aseli ne   $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051     0.04 141     0.13 775   0 .078 19    0.000 00   (0.04560)    0 .170 3
                                                                                                                                                                                                                                                                                                                   San Diego Gas & Electric Company




                                                                                            26      A bove 200% of B aseline         $/kWh            0.0128 4        0.077 10     0.0033 4      0.0004 6      0.00209       0.00 051     0.04 141     0.13 775   0 .078 19    0.000 00   (0.04560)    0 .170 3
                                                                                            27      M ini m um Bi ll                 $/Da y              0.00 0         0.0 00        0.00 0       0.00 0        0 .000         0 .000       0. 000       0.170      0.0 00      0.0 00      (0.034)       0.1 3

                                                                                                   * Effective rates show n for DR -LI reflect the 20% C AR E discount and exemp tion from th e CA RE su rcharge.




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                               APPENDIX C
               The schedule contained in this appendix supersedes and replaces Attachment RWH-1
                    contained in the Prepared Revised Direct Testimony of Robert W. Hansen
                                          (served January 27, 2009).




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                                                                                                                                                                               APPENDIX C


                                                                                                                                                                          San Diego Gas and Electric Company
                                                                                                                                                                     Rate Design Window Application (A.) 08-11-014
                                                                                                                                                                            Residential Baseline Allowances
                                                                                                                                                                                     kWh per Day


                                                                                                                                                                     Present                     Settlement 1st-Year Levels                        Settlement 2nd-Year Levels
                                                                                                                                                                                                                 Change From Present                               Change From Present
                                                                                                                                                    2001 Level in
                                                                                                                                        At Low-End Effect When           % of Average Settlement % of Average                            Settlement % of Average
                                                                                                              Customer                  Range of PU    AB1X               Residential  1st-Year   Residential                             2nd-Year   Residential
                                                                                                     Season       Type     Climate Zone Code §739 Implemented kWh/Day    Consumption    Levels   Consumption         kWh/Day   Percent     Levels*  Consumption    kWh/Day   Percent
                                                                                            Line #     (A)         (B)          (C)          (D)         (E)       (F)        (G)         (H)         (I)               (J)       (K)        (L)         (M)          (N)       (O)      Line #
                                                                                              1                            Coastal          8.5         8.3       10.2       57%         9.6         55%               (0.6)    -5.9%       9.0         53%          (1.2)   -11.8%        1
                                                                                              2                            Inland           9.9         8.3       11.8       57%         11.2        55%               (0.6)    -5.1%       10.6        53%          (1.2)   -10.2%        2
                                                                                                                 Basic
                                                                                              3                            Mountain         13.3        9.9       15.5       56%         14.8        54%               (0.7)    -4.5%       14.1        52%          (1.4)    -9.0%        3
                                                                                               4                           Desert           14.6        11.4      17.3       56%         16.4        54%               (0.9)    -5.2%       15.5        52%          (1.8)   -10.4%        4
                                                                                                     Summer
                                                                                               5                           Coastal          5.9         9.8       9.8        71%          9.8        71%                0.0      0.0%        9.8        71%           0.0      0.0%        5
                                                                                               6                           Inland           8.5         9.8       11.6       62%         11.0        60%               (0.6)    -5.2%       10.4        58%          (1.2)   -10.3%        6
                                                                                                              All-Electric
                                                                                               7                           Mountain         15.0        14.6      18.4       59%         17.3        56%               (1.1)    -6.0%       16.2        53%          (2.2)   -12.0%        7
                                                                                               8                           Desert           16.5        19.5      19.5       56%         19.5        56%                0.0      0.0%       19.5        56%           0.0      0.0%        8
                                                                                               9                           Coastal           8.8         8.3      10.8       58%         10.1        56%               (0.7)    -6.5%        9.4        53%          (1.4)   -13.0%        9
                                                                                              10                           Inland            9.4         8.3      11.5       59%         10.8        56%               (0.7)    -6.1%       10.1        53%          (1.4)   -12.2%        10
                                                                                                                 Basic
                                                                                              11                           Mountain         12.2        9.9       14.6       57%         13.8        55%               (0.8)    -5.5%       13.0        53%          (1.6)   -11.0%        11
                                                                                              12                           Desert            9.5         8.3      12.0       59%         11.2        56%               (0.8)    -6.7%       10.4        53%          (1.6)   -13.3%        12
                                                                                                     Winter
                                                                                              13                           Coastal           9.0        16.6      16.6       82%         16.6        82%                0.0      0.0%       16.6        82%           0.0      0.0%        13
                                                                                              14                           Inland           12.6        16.6      19.1       74%         18.3        73%               (0.8)    -4.2%       17.5        71%          (1.6)    -8.4%        14
                                                                                                              All-Electric
                                                                                              15                           Mountain         22.6        26.5      29.5       72%         28.5        70%               (1.0)    -3.4%       27.5        69%          (2.0)    -6.8%        15
                                                                                              16                           Desert           17.1        21.5      22.3       71%         22.0        71%               (0.3)    -1.3%       21.7        70%          (0.6)    -2.7%        16




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                               APPENDIX D




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                                             APPENDIX D
                               Summary of Proposed Tariff Schedule OL-TOU


                                         UDC          EECC        DWR-BC            Total Rate
                                          Schedule OL-TOU ($/kWh)
               Energy Charge
               Summer
                  On-Peak                  0.08112        0.22147        0.00491        0.30750
                  Semi-Peak                0.07380        0.09168        0.00491        0.17039
                  Off-Peak                 0.07364        0.06778        0.00491        0.14633
               Winter
                  On-Peak                  0.07742        0.10147        0.00491        0.18380
                  Semi-Peak                0.07380        0.09437        0.00491        0.17308
                  Off-Peak                 0.07364        0.06877        0.00491        0.14732
               Basic Service Fee               9.56                                         9.56




                                                     Summer
                 On-Peak      11 a.m. - 6 p.m. Weekdays
                                                              Daytime   6 a.m. – 6 p.m. Weekdays
                              6 a.m. - 11 a.m. Weekdays
                Semi-Peak
                              6 p.m. - 10 p.m. Weekdays
                                                                        6 p.m. – 6 a.m. Weekdays,
                              10 p.m. - 6 a.m. Weekdays      Nighttime
                                                                       plus Weekends and Holidays
                 Off-Peak     Plus Weekends & Holidays
                                                      Winter
                              6 a.m. - 5 p.m. Weekdays      Daytime    6 a.m. – 5 p.m. Weekdays
                Semi-Peak
                              8 p.m. - 10 p.m. Weekdays
                              10 p.m. - 6 a.m. Weekdays                 5 p.m. – 6 a.m. Weekdays,
                                                             Nighttime
                 Off-Peak     Plus Weekends & Holidays                 plus Weekends and Holidays
                 On-Peak      5 p.m. - 8 p.m. Weekdays




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         1 Application No:     A.08-02-001
           Exhibit No.:
         2
           Witness:            Rodger Schwecke
         3
         4
                                                               )
         5 In the Matter of the Application of San Diego Gas & )

         6 Electric Company (U 902 G) and Southern California )         A.08-02-001
           Gas Company (U 904 G) for Authority to Revise       )   (Filed February 4, 2008)
         7 Their Rates Effective January 1, 2009, in Their     )
           Biennial Cost Allocation Proceeding.                )
         8                                                     )
         9
        10
        11
        12                             PREPARED DIRECT TESTIMONY
        13
                                             OF RODGER SCHWECKE
        14
                                  SAN DIEGO GAS & ELECTRIC COMPANY
        15

        16                                             AND
        17                        SOUTHERN CALIFORNIA GAS COMPANY
        18
        19

        20

        21

        22
        23

        24

        25

        26
                                BEFORE THE PUBLIC UTILITIES COMMISSION
        27                           OF THE STATE OF CALIFORNIA
                                            December 5, 2008
        28




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         1                                                     TABLE OF CONTENTS
         2                                                                                                                                 Page
         3 I.       Qualifications .............................................................................................................1

         4 II.      Purpose of Testimony ................................................................................................1
         5 III.     Narrowing the Regulatory Gap ..................................................................................4
         6          A.      Overview of the Current Regulatory Gap ........................................................4
                    B.      Different Rate Design, Cost Recovery and Price Signals ................................5
         7
                    C.      Mismatched Service Obligations......................................................................8
         8          D.      Balancing Service.............................................................................................9

         9 IV.      Proposed Noncore Rate Redesign and Elimination of the Peaking Service Tariff....9

        10          A.      Transmission-Level Rate Options ....................................................................9
                    B.      Differentiation of Interruptible Rates from Firm Rates..................................12
        11
             V.     Other Proposals Needed to Narrow the Regulatory Gap .........................................13
        12
                    A.      Ability to Negotiate Transportation Rates to Compete ..................................13
        13
                    B.      Continued Utility Service to Bypassed Customers ........................................14
        14
             VI.    Proposals for the Utilities’ System Operator Related Functions .............................16
        15
                    A.      Reasonableness Review Risk .........................................................................16
        16          B.      Minimum Flowing Supply Requirement for End-Use Customers .................17
                    C.      Formula for Calculating Required Purchases by the HUB ............................20
        17          D.      Procedure for Approval of Minimum Flow Supply Requirement Tools .......22
                    E.      Access to Operational Information by the HUB ............................................22
        18
        19 VII. Eligibility for Electric Generation Core Service......................................................23

        20          A.      Request ...........................................................................................................23
                    B.      Customer Benefits ..........................................................................................25
        21          C.      Eligibility Criteria...........................................................................................26
                    D.      Potential Impacts ............................................................................................27
        22
             VIII. Backbone Transmission Cost Study ........................................................................27
        23
             IX.    SDG&E Curtailment Charge Refunds .....................................................................34
        24
        25          A.      SDG&E Curtailment History .........................................................................34
                    B.      Accounts No Longer Customers of Record....................................................35
        26
        27

        28


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         1 X.   Sempra-Wide NGV Rate .........................................................................................36
         2      A.      Background.....................................................................................................36
                B.      Request ...........................................................................................................36
         3
                C.      Customer Benefits ..........................................................................................37
         4      D.      Potential Impacts ............................................................................................37

         5

         6
         7

         8

         9

        10

        11

        12

        13
        14

        15

        16

        17

        18
        19

        20
        21

        22
        23

        24
        25

        26
        27

        28


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        1                               PREPARED DIRECT TESTIMONY
                                           OF RODGER SCHWECKE
        2

        3 I.       Qualifications

        4          My name is Rodger Schwecke. I am employed by Southern California Gas Company

        5 (SoCalGas) as the Director of Energy Markets and Capacity Products in the Customer Services

        6 Department. My business address is 555 West Fifth Street, Los Angeles, California, 90013-
        7 1011. My responsibilities are to manage service to the largest gas customers of San Diego Gas

        8 & Electric (SDG&E) and SoCalGas, specifically large electric generators, refineries and
        9 wholesale customers. I also manage for SDG&E and SoCalGas the unbundled storage program,
       10 the Operational HUB (G-PAL) services and minimum flowing supply purchases, policies and
       11 procedures for scheduling and nominations on the SDG&E and SoCalGas systems, daily
       12 operation and enhancements to SoCalGas' Electronic Bulletin Board (EBB), and all aspects of

       13 SDG&E/SoCalGas’ interconnect and operational balancing agreements with all suppliers
       14 delivering natural gas into the utility system.
       15          I have been employed by SoCalGas and its affiliates since June 1983 in numerous

       16 positions, including General Manager/Vice President – Bangor Gas Company; Vice President
       17 Marketing - Frontier Energy; and Business Development Manager, Senior Pipeline Products

       18 Manager, Project Manager, Account Executive Supervisor, Market Planner Analyst, and Energy
       19 Systems Engineer for SoCalGas. I assumed my current position in December 2007. During my

       20 employment I have been responsible for various aspects of utility development and operations,

       21 sales and marketing, regulatory matters, and customer relations. I graduated in 1983 from

       22 California State University, Long Beach, with a Bachelor of Science in Chemical Engineering.
       23          I have previously testified before the California Public Utilities Commission, State of

       24 Maine Utilities Commission, and the North Carolina Utilities Commission.

       25 II.      Purpose of Testimony

       26          The purpose of my testimony is to sponsor: new rate proposals for core and noncore

       27 customers of SDG&E and SoCalGas (Utilities); proposals for the Utilities’ System Operator; and

       28 the Utilities’ backbone transmission cost study. The first set of rate proposals address the




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        1 Commission’s order to close or sufficiently narrow the “regulatory gap” between the Utilities’
        2 rates and services and those of competing interstate pipelines to allow SoCalGas to eliminate the

        3 Peaking Service tariff (Schedule GT-PS) without creating an undue risk of significant cost shifts
                                                            1
        4 due to uneconomic partial bypass of the Utilities. The transportation service proposal includes:

        5             a new reservation charge rate design option for transmission-level noncore

        6              customers, based on the embedded costs and capacity of the transmission

        7              system, plus a volumetric usage rate to recover the remaining non-base margin

        8              costs. The term for this option is three (3) years;

        9             an all-volumetric rate for firm, full requirements transportation with a term of

       10              six years;

       11             an all-volumetric interruptible rate equal to the volumetric firm rate, with a

       12              one-month term.

       13          Under this proposal to narrow the regulatory gap, the Utilities also propose changes to the

       14 load balancing rules that set requirements for allowable differentials between customer usage and

       15 customer deliveries of natural gas, so the rules will be more consistent with those of competing

       16 interstate pipelines. If the Commission adopts the Utilities’ proposals to narrow the regulatory

       17 gap, then the Utilities propose to eliminate the Peaking Service tariff. However, as described

       18 later in this testimony, because the proposals cannot completely close the regulatory gap, the
       19 Utilities need to retain certain other tools, aside from the Peaking Service tariff, to compete with

       20 uneconomic partial bypass and prevent cost shifts. In this testimony, I review the key elements
       21 of the regulatory gap that, as the Commission has consistently determined, create a need for a

       22 rate design to prevent uneconomic partial bypass and cost shifting from partial-bypass customers
       23 to other customers of the Utilities. I then further describe the Utilities’ proposals and how they

       24 address the regulatory gap while meeting the needs of the majority of the Utilities’ customers
       25
            1/
       26          D.06-12-031, p. 143, O.P. 9(a) “In its next Biennial Cost Allocation Proceeding (BCAP),
                   SoCalGas shall include a proposal for a total redesign of its rate consistent with the discussion
       27          regarding closing or minimizing the regulatory gap” and 9(b) as modified by D.07-09-046, p. 25,
                   O.P. 2. 9(b) “At the conclusion of SoCalGas’ next BCAP, we intend to sunset the existing
       28          peaking rate tariff.” Also, see discussion in D.06-12-031, p.129. “A wholesale change in rate
                   design may be needed if parties want to truly resolve the peaking rate issue, promote pipe-to-pipe
                   competition, and protect the captive customers who remain on the system.”

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        1 that would not benefit from partial bypass. The embedded cost allocation analysis for this
        2 proposed rate design is presented in the testimonies of Mr. Emmrich for SoCalGas and Dr.

        3 Schmidt for SDG&E. Further details of the rate design itself are presented in the testimonies of

        4 Mr. Lenart for SoCalGas and Mr. Bonnett for SDG&E.

        5          Second, I am making certain proposals regarding the activities of the Utilities’ System

        6 Operator. The Utilities propose five key items as they relate to the System Operator functions.
        7 These proposals include:

        8             a minimum flowing supply requirement for end-use customers to ensure the

        9              system operates reliably without the need to curtail customers;

       10             a formula for calculating required purchases to meet minimum flowing supply

       11              requirements;

       12             a procedure for approving tools to meet the minimum flowing supply

       13              requirements beyond what was adopted in D.07-12-019; and

       14             the level of access to operational information by the Operational HUB (HUB).

       15          Third, I am sponsoring a proposal to revise the eligibility criteria for the Core

       16 Commercial and Industrial Service rate schedule(s). The Utilities propose to increase the size-

       17 limit eligibility for electric generation (EG) customers desiring core service to 1 megawatt

       18 (“MW”) of installed capacity, regardless of monthly usage (average monthly usage is
       19 approximately 34,000 therms). This proposal includes retaining the ability of an EG customer

       20 with a higher capacity to elect core service if its average monthly usage is 20,800 therms or less.
       21          Fourth, my testimony presents the backbone transmission cost study as ordered in

       22 D.06-12-031. The Utilities recommend that the Commission consider the adoption of a
       23 cost-based firm access rights (FAR) charge using updated cost information in the 18-month

       24 review proceeding for FAR, which will be filed in mid-2010. The Commission has indicated it
       25 intends to use that proceeding to consider modifications to the FAR program, including further

       26 unbundling and at-risk proposals. The Commission has also indicated that incorporation of a
       27 cost-based rate would be at the end of the first three-year term for FAR, which will be near the

       28


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        1 end of this Biennial Cost Allocation Proceeding (BCAP) period if the Utilities’ proposal to
                                                                         2
        2 extend the BCAP term from two years to three years is adopted.

        3          Fifth, I am sponsoring the Utilities’ recommendation for how to refund to SDG&E

        4 customers $3.3 million in gas curtailment violation charges collected between November 2000

        5 and February 2001. The Utilities propose to refund these charges to customers of record at that

        6 time, taking into account the need to avoid rewarding customers that did not comply with the
        7 curtailment orders.

        8          Finally, my testimony proposes to establish a single “Sempra-wide” natural gas vehicle

        9 (NGV) rate for use across the Utilities’ service territories.

       10 III.     Narrowing the Regulatory Gap

       11          A.      Overview of the Current Regulatory Gap

       12          In D.06-12-031, the Commission reaffirmed that a “regulatory gap” exists between the

       13 reservation rates and service obligations of pipelines regulated by the Federal Energy Regulatory
       14 Commission (FERC) (and proprietary pipelines) and the all-volumetric rates and service

       15 obligations of the Utilities. The Commission further reaffirmed that this gap provides an

       16 incentive for the Utilities’ customers to take baseload transportation service from a FERC-

       17 regulated pipeline while taking swing service (peaking or residual load service) from the

       18 Utilities. The Commission observed that there would be a resulting shift of costs from partial-
       19 bypass customers to the Utilities’ remaining customers.

       20          The Peaking Service tariff has effectively allowed SoCalGas to compete with

       21 uneconomic partial bypass of its system and to recover the cost to provide transportation service

       22 to any partial bypass customer who continues to be connected to the SoCalGas system for
       23 standby or swing service. In fact, the Commission recognized that eliminating the Peaking

       24 Service tariff without changes to the Utilities’ all-volumetric rate structure will lead to higher-
       25 cost service, since the Utilities’ largest customers would take service for the baseload portion of

       26 their load from competing pipelines, leaving smaller customers, who are not the target of bypass
       27 pipelines, to pick up the remaining costs. The Commission also recognized the essential fairness

       28   2/
                   If the three-year term is not adopted, then implementation of the cost based rate would come one
                   year into the next BCAP term.

                                                                 -4-




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp11.pdf
                                   Pages 180 of 375
                                     San Diego Gas & Electric Company
                                        Test Year 2012 GRC - APP
                                      Non-Shared Service Workpapers




                                                                                                   Ken Deremer
                                                                                                         Director
                                                                                   Tariffs & Regulatory Accounts
                                                                                         8330 Century Park Court
                                                                                     San Diego, CA 92123-1548

                                                                                            Tel: 858.654.1756
                                                                                           Fax: 858.654.1788
                                                                                  kderemer@semprautilities.com




                                                        October 16, 2008


      ADVICE LETTER 2033-E
      (U902-E)

      PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

      SUBJECT:          UPDATE TO SCHEDULE NEM AND RELATED TARIFF CLEAN-UP

      San Diego Gas & Electric Company (SDG&E) hereby submits for approval the following
      revisions to its electric tariffs as shown in the enclosed attachment.

      PURPOSE
      This filing revises SDG&E’s electric Schedule NEM, Net Energy Metering, to reflect the total
      rated generating capacity allotted to NEM customers under California Public Utilities (PU) Code
      § 2827.C.1. Additionally, this filing removes duplicative NEM-related Special Conditions from
      SDG&E electric Schedules DR, DR-TOU, DM, DS, DT, DT-RV, and A.

      DISCUSSION
      California Public Utilities Code requires SDG&E to limit Schedule NEM availability to customers,
      on a first come first served basis, until the time that total rated generating capacity used by
      eligible customer generators exceeds 2.5% of SDG&E’s aggregate customer peak demand.1
      Previously, California Senate Bill (SB) 816, effective July 21, 2005, had required SDG&E to limit
      total rated NEM generating capacity to 50 Megawatts.

      SDG&E has therefore appropriately updated the availability limit stated in its Schedule NEM to
      2.5% of SDG&E’s aggregate customer peak demand. In addition, SDG&E has eliminated
      Special Conditions titled ‘Net Energy’ and ‘Net Energy Billing’, which appear in electric tariffs
      DR, DR-TOU, DM, DS, DT, DT-RV, and A. These Special Conditions contain duplicative
      language that is currently included in Schedule NEM.

      This filing will not increase any rate or charge, cause the withdrawal of service, or conflict with
      any rate schedule or rule.

      EFFECTIVE DATE
      SDG&E believes this Advice Letter is subject to Energy Division and should be classified as Tier
      2 (effective after staff approval) pursuant to GO 96-B. SDG&E respectfully requests that this
      filing be approved effective November 15, 2008, thirty days from the date filed.



      1
          See PU Code § 2827.C.1




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp12.pdf
                                   Pages 181 of 375
                                     San Diego Gas & Electric Company
                                        Test Year 2012 GRC - APP
                                      Non-Shared Service Workpapers




       Public Utilities Commission                      2                               October 16, 2008

       PROTEST
       Anyone may protest this Advice Letter to the California Public Utilities Commission. The protest
       must state the grounds upon which it is based, including such items as financial and service
       impact, and should be submitted expeditiously. The protest must be made in writing and must
       be received within 20 days of the date this Advice Letter was filed with the Commission. There
       is no restriction on who may file a protest. The address for mailing or delivering a protest to the
       Commission is:

              CPUC Energy Division
              Attention: Tariff Unit
              505 Van Ness Avenue
              San Francisco, CA 94102

       Copies of the protest should also be sent via e-mail to the attention of both Honesto Gatchalian
       (jnj@cpuc.ca.gov) and Maria Salinas (mas@cpuc.ca.gov) of the Energy Division. A copy of the
       protest should also be sent via both e-mail and facsimile to the address shown below on the
       same date it is mailed or delivered to the Commission.

              Attn: Todd Cahill
              Regulatory Tariff Manager
              8330 Century Park Court, Room 32C
              San Diego, CA 92123-1548
              Facsimile No. (858) 654-1788
              E-mail: tcahill@semprautilities.com

       NOTICE
       A copy of this filing has been served on the utilities and interested parties shown on the
       attached list, by either providing them a copy electronically or by mailing them a copy hereof,
       properly stamped and addressed.

       Address changes should be directed to SDG&E Tariffs by facsimile at (858) 654-1788 or by e-
       mail at SDG&ETariffs@semprautilities.com.



                                                         _______________________________
                                                         KEN DEREMER
                                                         Director – Tariffs & Regulatory Accounts
       (cc list enclosed)




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp12.pdf
                                   Pages 182 of 375
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp13.pdf




                                                                                                                                                   Productivity Enhancements - Re-bill Benefits


                                                                                                             Description                           Amount                                                         Source
                                                                                            Annual Exceptions                                               404,000   Annual based on historical monthly average 2006-2009
                                                                                                                                                                      Assumptions based on analysis of current work items. Meter Read errors and pre-bill edits that
                                                                                                                                                                      are caused by manual meter read issues represents 32.8 percent of exceptions. This
                                                                                            Reduction Rate                                                32.8%       represents the exceptions expected to be eliminated in 2012.
                                                                                            Expected Reduction in exceptions                             132,512
                                                                                            Cost per exception                                             $1.42      Average exception processed; applied average salary * note below
                                                                                            Cost reduction due to decreased exceptions               $188,167.04
                                                                                            Annual Re-bills                                              101,200      Monthly average of re-bills, based on 2005 -2009 historical data

                                                                                                                                                                      Assumptions based on analysis of current work items. Re-bills related to read errors (read




                                                                                                                                                                                                                                                                          San Diego Gas & Electric Company
                                                                                                                                                                                                                                                                           Non-Shared Service Workpapers
                                                                                            Reduction Rate                                                30.0%       corrections) and re-billing for previously estimated usage represents 30% of historical re-bills.
                                                                                            Excpected Reduction in re-bills                               30,360




                                                                                                                                                                                                                                                                             Test Year 2012 GRC - APP
                                                                                            Cost per Re-bill                                               $2.42      Time Study conducted based on average processing time and average salary * note below
                                                                                            cost reduction for decreased re-bills                     $73,471.20
                                   Pages 183 of 375




                                                                                            Total Re-bill/Reduced Exception Benefit                  $261,638.24
                                                                                            FTE Reduction                                                     6.3     Average salary of impacted employees $41,500


                                                                                            Cost Per Exception Calculation and Assumptions
                                                                                            Average Salary $19.95 per hour
                                                                                            Average processing time per transaction 4.3 minutes

                                                                                            Cost per Rebill Calculation and Assumptions
                                                                                            Average Salary $19.95 per hour
                                                                                            Average processing time per transaction 7.25 minutes
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp13.pdf




                                                                                            Volumes: Exceptions Historical Data 2005-2009
                                                                                                  January   February March         April     May      June      July       August    September October   November December
                                                                                             2006    34,510    31,792      37,390     32,275   30,740    33,238     31,915    36,749    33,955    40,666    30,076       27,360         400,666
                                                                                             2007    40,544    29,927      30,221     30,830   32,863    28,281     31,505    39,976    33,701    35,620    26,573       29,209         389,250
                                                                                             2008    41,112    33,304      32,749     37,381   33,905    30,695     37,595    38,894    37,577    42,751    30,927       36,335         433,225
                                                                                             2009    36,352    29,165      33,553     34,955   35,061    34,973     33,849    32,868    34,634    34,813    24,706       27,776         392,705
                                                                                                                                                                                                                   Total              1,615,846
                                                                                                                                                                                                                   Month Avg            403,962



                                                                                            Volumes: Re-bill Historical Data 2005-2009
                                                                                                  January    February March         April       May       June      July       August    September October   November December
                                                                                             2005     7,649       6,657       7,642       6,602     5,929     5,625      5,699     6,949     6,250     6,069    20,588        6,538     92,197




                                                                                                                                                                                                                                                  San Diego Gas & Electric Company
                                                                                                                                                                                                                                                   Non-Shared Service Workpapers
                                                                                             2006     6,181       6,121       6,320       5,345     5,712     5,594      4,912     7,348     7,274     7,619     5,223        4,475     72,124
                                                                                             2007     6,182       5,477       8,005       7,309     7,657     8,700      7,468     8,504     7,936     9,832     8,389        7,230     92,689




                                                                                                                                                                                                                                                     Test Year 2012 GRC - APP
                                                                                             2008    36,813       9,513      11,100       8,076     6,379     8,266     19,884     9,991     9,346     8,553     7,530        6,787    142,238
                                                                                             2009     7,799       8,194       8,811       8,523     8,763     8,894      8,743    10,592     9,068     9,745     6,565       11,143    106,840
                                   Pages 184 of 375




                                                                                                                                                                                                                       Total           506,088
                                                                                                                                                                                                                       Month Avg       101,218
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp14.pdf




                                                                                                                    Smart Meter - Complex Billing 2012

                                                                                                             Description                      Amount      Source/Assumptions
                                                                                                                                                         Source 2009 Average
                                                                                            Average mmb salary 2009                              $41,500 Salary
                                                                                            Number of impacted billing employees                      17 11 @ AS4, 7 @AS5
                                                                                            Average costs 2009 salary                           $705,500




                                                                                                                                                                                       San Diego Gas & Electric Company
                                                                                                                                                                                        Non-Shared Service Workpapers
                                                                                                                                                                                          Test Year 2012 GRC - APP
                                                                                                                                                          35% increase based on
                                   Pages 185 of 375




                                                                                                                                                          time study for transaction
                                                                                                                                                          processing in pilot
                                                                                                                                                          program for dynamic
                                                                                                                                                          pricing rates. Supported
                                                                                                                                                          by this is the increase in
                                                                                                                                                          data points that will need
                                                                                                                                                          to be analyzed when
                                                                                                                                                          comparing 1 month of
                                                                                                                                                          consumption vs. the
                                                                                                                                                          hundreds of interval data
                                                                                            Additional time to process PWQ for complex rate       35.0% points.
                                                                                            Additional cost processing more complex rates       $246,925
                                                                                            FTE Increase                                              6.0
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp15.pdf




                                                                                                                                 Smart Meter - Increased Salaries 2012

                                                                                                            Description                     Amount                               Source
                                                                                            Average Salary of AS4/AS5 biller (17 FTE)   $      41,500
                                                                                            Impacted Salaries of AS4/AS5                $     705,500
                                                                                            Average Salary of SA2                       $      43,600
                                                                                            Impacted Salaries of SA2 (2 FTE)            $      87,200
                                                                                            Total impacted salaries                     $     792,700
                                                                                                                                                      Assumed increase * Differential of average salary to




                                                                                                                                                                                                             San Diego Gas & Electric Company
                                                                                            Assumed increase                                    19.4% midpoint at re-leveled position to TS4 or SA2




                                                                                                                                                                                                              Non-Shared Service Workpapers
                                                                                            Increased Salaries 2012                     $     153,784




                                                                                                                                                                                                                Test Year 2012 GRC - APP
                                   Pages 186 of 375
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp16.pdf




                                                                                                                                   Billing - Net Energy Metering (NEM) Labor Forecast
                                                                                            Year End Totals                                                 2005       2006    2007    2008     2009      2010*      2011*     2012*
                                                                                            Active NEM Accounts                                             3190       3910   4,640   5,524    7,926     11,100      15700     22100
                                                                                            Percent Growth                                                             23%      19%     19%      43%        40%       41%       41%
                                                                                            Average Number of New Customer Per Month                                                      74      200        265       383       533

                                                                                            Required FTEs
                                                                                             - New Set-Ups                                                                             0.50     0.75       1.10       1.50      2.00
                                                                                             - Monthly Exception Handling and Maintenance                                              1.00     1.25       1.50       1.75      2.00
                                                                                             - Customer Contact                                                                        0.75     1.00       1.25       1.50      2.00




                                                                                                                                                                                                                                       San Diego Gas & Electric Company
                                                                                                                                                                                                                                        Non-Shared Service Workpapers
                                                                                             - Mail Room Support (Bill Redesign Enhancement in 2012)                                   0.15     0.25       0.35       0.45      0.00




                                                                                                                                                                                                                                          Test Year 2012 GRC - APP
                                                                                               Total                                                                                   2.40     3.25       4.20       5.20      6.00
                                   Pages 187 of 375




                                                                                            Actual Staffing Level - FTE                                                                2.25     2.75       2.75       3.75      4.75

                                                                                            FTE Upward Pressure                                                                                 0.50       1.45       1.45      1.25
                                                                                             (Difference currently made up by overtime and flexing staff)

                                                                                            Proposed FTE Increase                                                                               0.00       1.00       1.00      1.00

                                                                                            *Estimated Increase

                                                                                            Customer Account Associate (AS5) = Labor $43,000                                                            $43,000    $43,000   $43,000
                                                                                            Customer Account Associate (AS5) = Non - Labor $2,000                                                        $2,000     $2,000    $2,000
                                                                                            Total                                                                                                       $45,000    $45,000   $45,000




                                                                                                                                                                   1
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp17.pdf




                                                                                                                           Billing Operations Support (BOS) Work Item Projection

                                                                                            BOS Work Item Projection
                                                                                                                                                           Average 2006-2008    2009   2010    2011    2012
                                                                                            Total Work Items Received                                                     573    967   1112    1279    1471
                                                                                            Percent Increase                                                                    69%    15%*    15%*    15%*
                                                                                            Needed FTEs                                                                  0.82   1.38    1.59    1.83     2.1
                                                                                            Existing FTEs                                                                   1      1       1       1       1

                                                                                            Required Additional FTEs                                                       0       0      0      0.5      1




                                                                                                                                                                                                               San Diego Gas & Electric Company
                                                                                                                                                                                                                Non-Shared Service Workpapers
                                                                                                                                                                                                                  Test Year 2012 GRC - APP
                                                                                            1 FTE/Work Items                                         700
                                   Pages 188 of 375




                                                                                            Additional Upward Pressures

                                                                                            Net Metering Growth
                                                                                            Virtual Net Metering
                                                                                            AB920
                                                                                            AB2466
                                                                                            Additional testing/ support due to complexity of rates


                                                                                            * 15% growth rate is based upon the current
                                                                                            growth rate of Net Metering, which in 2009 was
                                                                                            40%. As just under 40% of the current work
                                                                                            items are related to Net Metering issues, it is
                                                                                            projected that work items will increase by 15%
                                                                                            per year.

                                                                                            Only four years of historical data was available
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp18.pdf




                                                                                                                                     Switch Meter Activity

                                                                                             Year     2007      2008               2009                2010               2011               2012
                                                                                            Labor     Units     Units         Units     $         Units     $        Units     $        Units     $
                                                                                             SA4        0          0           1      54000        1      54000       1      54000       1      54000
                                                                                            Activity
                                                                                              * Switched Meter Activity        718                826                 950               1092




                                                                                                                                                                                                              San Diego Gas & Electric Company
                                                                                                                                                                                                               Non-Shared Service Workpapers
                                                                                                                                                                                                                 Test Year 2012 GRC - APP
                                                                                             Total                             718                826                 950               1092
                                   Pages 189 of 375




                                                                                            Assumptions for forecasting future:
                                                                                            15% increase in bill correction activity as a result of accelerated investigations/resolution
                                                                                            15% increase in activity is based on monthly analysis of existing 2009 data
                                                                                            Switched Meter investigations require account analysis (including usage, customer history, customer data), f
                                                                                            investigations (coordinating field personnel appointments, visible confirmation of switched meters, drive time
                                                                                            resolution (conclusion of investigation, worksheet preparation, account level cor Meters can be switched betw
                                                                                            2 or more customers. The more meters involved (for example, at an apartment complex), the more complex
                                                                                            the investigation. Most investigations result in account corrections. Some investigations validate that the met
                                                                                            not switched. Because of the coordinated effort with Field Personnel, the Billing Department, property manag
                                                                                            the investigations can be lengthy and time consuming to finalize.

                                                                                            Average of 2.7 hours per each switched meter investigation
                                                                                            Activity levels based on 2009 tracked activity for switched meters
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp19.pdf




                                                                                            Revert to Owner (RTO) Activity Level

                                                                                                    Year          2007         2008               2009                2010                2011               2012
                                                                                            Labor                 Units        Units         Units      $        Units      $        Units      $       Units      $
                                                                                             AS5                    1            1            1      42,000       2      63,000       2      63,000      2      63,000
                                                                                            Activity
                                                                                            RTO Base Activity    25,500        22,800       22,100              22,100              22,100             22,100
                                                                                            Activity Growth                                                      7,735               7,735              7,735
                                                                                             Total               25,515        22,823       22,122              29,835              29,835             29,835




                                                                                                                                                                                                                         San Diego Gas & Electric Company
                                                                                               Change                         -10.55%       -0.31%                3%                  3%                 3%




                                                                                                                                                                                                                          Non-Shared Service Workpapers
                                                                                                                                                                                                                            Test Year 2012 GRC - APP
                                                                                            * Assumption = increase of 35% of base activity as a result of ongoing maintenance and re-certification process.
                                   Pages 190 of 375




                                                                                            35% of the sampled agreements were either aged and/or had no recent activity, making these candidates for a
                                                                                            maintenance and re-certification program. Anticipated increase of cancellation of existing agreements upon
                                                                                            implementation of maintenance program In 2009, volumes of RTO activity remained the same as 2008.

                                                                                            Existing agreements for RTO do not expire. To protect the customer from being held responsible for bills at
                                                                                            properties that they many no longer manage, rent, or own, a maintenance and re-certification process was
                                                                                            implemented in 2010. The process reviews aged agreements and identifies customers who may no longer be
                                                                                            a candidate for the program. The tasks associated with the maintenance/re-certification process includes:
                                                                                            additional research, filing, account review, account maintenance, mailing customer communication and/or initiating
                                                                                            customer contact, and responding to customer inquiries as part of the re-certification process. The standard activity
                                                                                            level is quantified, taking into consideration a 15% increase in tasks for each agreement.
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO000.000_Supp20.pdf




                                                                                                                                  Billing Determinants

                                                                                             Year    2007       2008           2009               2010              2011               2012
                                                                                            Labor    Units      Units     Units     $        Units     $       Units     $        Units     $
                                                                                             AS5                                              0.5    21000      0.5    21000       0.5    21000
                                                                                            Activity
                                                                                              Transactions        0         0               11400              11400              11400

                                                                                             Total                                          11400              11400              11400




                                                                                                                                                                                                                 San Diego Gas & Electric Company
                                                                                                                                                                                                                  Non-Shared Service Workpapers
                                                                                                                                                                                                                    Test Year 2012 GRC - APP
                                   Pages 191 of 375




                                                                                            * Assumptions:
                                                                                            1 FTE = ~ 22800 annual transactions

                                                                                            monthly volumes expected at 950 transactions based on tracking established using 2010 data

                                                                                            * As of 2010, these are newly developed processes and exceptions
                                                                                            Transactions include exceptions related to new premises, discrepancies reported by field personnel to validate the
                                                                                            accuracy of bill determinants, re-bills for noted discrepancies, and customer inquiries.
                                              San Diego Gas & Electric Company
                                                 Test Year 2012 GRC - APP
                                               Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                B. Office Credit & Collections
Workpaper:               1OO002.000

Summary for Category: B. Office Credit & Collections

                                                                In 2009$ (000)
                                    Adjusted-Recorded                        Adjusted-Forecast
                                       2009                   2010               2011            2012
             Labor                        1,864                2,101               2,252            2,273
             Non-Labor                      467                 496                  499                503
             NSE                               0                     0                  0                 0
               Total                      2,331                2,597               2,751            2,776
               FTE                          32.6                36.5                38.9                39.2

   Workpapers belonging to this Category:
    1OO002.000 OFFICE CREDIT & COLLECTIONS
         Labor                       1,864                     2,101              2,252             2,273
         Non-Labor                     467                       496                499               503
         NSE                             0                         0                  0                 0
            Total                    2,331                     2,597              2,751             2,776
            FTE                       32.6                      36.5               38.9              39.2




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 192 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                   Non-Shared Service Workpapers




                Beginning of Workpaper
       1OO002.000 - OFFICE CREDIT & COLLECTIONS




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 193 of 375
                                              San Diego Gas & Electric Company
                                                 Test Year 2012 GRC - APP
                                               Non-Shared Service Workpapers


Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Office Credit & Collections
Category-Sub            1. CS Operations-Office Credit & Collections
Workpaper:              1OO002.000 - OFFICE CREDIT & COLLECTIONS

Activity Description:
               This workgroup includes staff responsible for final bill collection, skip tracing, turn on
               investigations, deposit analysis, theft investigation, activities supporting remittance processing
               and policy and procedures supporting mitigating risk to other ratepayers.
Forecast Methodology:

        Labor - 5-YR Average
               Work volumes in Credit and Collections are driven by many factors that vary over time and
               impact various functions within the overall process. Examples would include the strength of the
               economy, unemployment levels, and the ability of small commercial customers to obtain credit
               and maintain cash flows. For these reasons, it is logical to project future expenses by using a
               five year historical average to encompass the fluctuations in workflow volumes over a
               reasonable timeframe.
        Non-Labor - 5-YR Average
              Work volumes in Credit and Collections are driven by many factors that vary over time and
              impact various functions within the overall process. Examples would include the strength of the
              economy, unemployment levels, and the ability of small commercial customers to obtain credit
              and maintain cash flows. For these reasons, it is logical to project future expenses by using a
              five year historical average to encompass the fluctuations in workflow volumes over a
              reasonable timeframe.
        NSE - 5-YR Average
               N/A


Summary of Results:

                                                                  In 2009$ (000)
                                        Adjusted-Recorded                                       Adjusted-Forecast
Years                     2005        2006         2007        2008         2009            2010         2011       2012
Labor                    2,211       2,095        1,854       1,865        1,864           2,101        2,252       2,273
Non-Labor                  548         504          491         450          467             496          499        503
NSE                          0           0            0           0            0               0            0         0
   Total                 2,759       2,599        2,345       2,315        2,331           2,597        2,751       2,776
   FTE                    39.2        36.8         33.3        33.2         32.6            36.5         38.9        39.2




                    SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                            Pages 194 of 375
                                                San Diego Gas & Electric Company
                                                   Test Year 2012 GRC - APP
                                                 Non-Shared Service Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 B. Office Credit & Collections
Category-Sub:             1. CS Operations-Office Credit & Collections
Workpaper:                1OO002.000 - OFFICE CREDIT & COLLECTIONS

Forecast Summary:
                                                                       In 2009 $(000)
     Forecast Method                      Base Forecast                  Forecast Adjustments              Adjusted-Forecast
                                       2010         2011     2012       2010       2011     2012          2010     2011        2012
 Labor              5-YR Average       1,977        1,977   1,977        124       275       296          2,101    2,252   2,273
 Non-Labor          5-YR Average        492           492        492           4     7         11          496      499        503
 NSE                5-YR Average          0             0          0           0     0          0            0         0         0
 Total                                 2,469        2,469   2,469        128       282       307          2,597    2,751   2,776
 FTE                5-YR Average        35.0         35.0    35.0         1.5       3.9       4.2          36.5     38.9       39.2


Forecast Adjustment Details:
       Year/Expl.           Labor              NLbr         NSE        Total        FTE     Adj_Type

         2010                      0            4            0            4          0.0    1-Sided Adj

           POS ID challenge question system implementation. Increases customer service and helps
           meet mandatory Red Flag requirements.

         2010                  88               0            0           88          0.0    1-Sided Adj

           Add one AD2 employee to run and analyze complex data queries as requested by interveners
           and Commission staff.

         2010                      0            0            0            0          1.0    1-Sided Adj

           Add one AD2 employee to run and analyze complex data queries as requested by interveners
           and Commission staff.

         2010                  49               0            0           49          0.0    1-Sided Adj

           Training for Smart Meter will decline and return O&M FTE count to 4.0 total for Meter
           Revenue Protection.

         2010                      0            0            0            0          0.6    1-Sided Adj

           Training for Smart Meter will decline and return O&M FTE count to 4.0 total for Meter
           Revenue Protection.

         2010                      0            0            0            0          -0.4   1-Sided Adj

           5 year average dollar and FTE impact removed as it is planned for at SCG, in USS cost
           center 2200-0354.

         2010                      8            0            0            8          0.0    1-Sided Adj

           Customer growth handled through Overtime




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 195 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Office Credit & Collections
Category-Sub:         1. CS Operations-Office Credit & Collections
Workpaper:            1OO002.000 - OFFICE CREDIT & COLLECTIONS

      Year/Expl.        Labor          NLbr       NSE         Total        FTE   Adj Type

      2010                   0             2            0             2       0.0    1-Sided Adj

         Non Labor increase as a result of customer growth.

      2010                 -35             0            0        -35          0.0    1-Sided Adj

         5 year average dollar and FTE impact removed as it is planned for at SCG, in USS cost
         center 2200-0354.

      2010                   0            -2            0             -2      0.0    1-Sided Adj

         5 year average dollar and FTE impact removed as it is planned for at SCG, in USS cost
         center 2200-0354.

      2010                  14             0            0         14          0.0    1-Sided Adj

         0.25 FTE to help complete the escheatment process each year. 0.25 of an SA2.

      2010                   0             0            0             0       0.3    1-Sided Adj

         0.25 FTE to help complete the escheatment process each year. 0.25 of an SA2.

      2010 Total           124             4            0        128           1.5




      2011                  14             0            0         14          0.0    1-Sided Adj

         0.25 FTE to help complete the escheatment process each year. 0.25 of an SA2.

      2011                   0             0            0             0       0.3    1-Sided Adj

         0.25 FTE to help complete the escheatment process each year. 0.25 of an SA2.

      2011                   0             4            0             4       0.0    1-Sided Adj

         POS ID challenge question system implementation. Increases customer service and helps
         meet mandatory Red Flag requirements.

      2011                  88             0            0         88          0.0    1-Sided Adj

         Add one AD2 employee to run and analyze complex data queries as requested by interveners
         and Commission staff.

      2011                   0             0            0             0       1.0    1-Sided Adj

         Add one AD2 employee to run and analyze complex data queries as requested by interveners
         and Commission staff.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 196 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Office Credit & Collections
Category-Sub:         1. CS Operations-Office Credit & Collections
Workpaper:            1OO002.000 - OFFICE CREDIT & COLLECTIONS

      Year/Expl.        Labor          NLbr       NSE         Total         FTE    Adj Type

      2011                  20             0            0          20           0.0   1-Sided Adj

         Customer Growth handled through overtime.

      2011                   0             0            0             0         0.4   1-Sided Adj

         Customer growth handled through overtime.

      2011                 139             0            0         139           0.0   1-Sided Adj

         Increase in 2 MRP investigators (2 SA4 positions) due to the permanent increase in
         workloads as a result of Smart Meter installations.

      2011                   0             0            0             0         2.0   1-Sided Adj

         Increase in 2 MRP investigators (2 SA4 positions) due to the permanent increase in
         workloads as a result of Smart Meter installations.

      2011                   0             5            0             5         0.0   1-Sided Adj

         Non Labor associated with customer growth.

      2011                  49             0            0          49           0.0   1-Sided Adj

         Training for Smart Meter will decline and return O&M FTE count to 4.0 for Meter Revenue
         Protection.

      2011                   0             0            0             0         0.6   1-Sided Adj

         Training for Smart Meter will decline and return O&M FTE count to 4.0 for Meter Revenue
         Protection.

      2011                   0             0            0             0        -0.4   1-Sided Adj

         5 year average dollar and FTE impact removed as it is planned for at SCG, in USS cost
         center 2200-0354.

      2011                 -35             0            0         -35           0.0   1-Sided Adj

         5 year average dollar and FTE impact removed as it is planned for at SCG, in USS cost
         center 2200-0354.

      2011                   0            -2            0             -2        0.0   1-Sided Adj

         5 year average dollar and FTE impact removed as it is planned for at SCG, in USS cost
         center 2200-0354.

      2011 Total           275             7            0         282           3.9




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 197 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Office Credit & Collections
Category-Sub:         1. CS Operations-Office Credit & Collections
Workpaper:            1OO002.000 - OFFICE CREDIT & COLLECTIONS

      Year/Expl.        Labor          NLbr       NSE         Total         FTE    Adj Type



      2012                  14             0            0          14           0.0   1-Sided Adj

         0.25 FTE to help complete the escheatment process each year. 0.25 of an SA2.

      2012                   0             0            0             0         0.3   1-Sided Adj

         0.25 FTE to help complete the escheatment process each year. 0.25 of an SA2.

      2012                   0             4            0             4         0.0   1-Sided Adj

         POS ID challenge question system implementation. Increases customer service and helps
         meet mandatory Red Flag requirements.

      2012                  88             0            0          88           0.0   1-Sided Adj

         Add one AD2 employee to run and analyze complex data queries as requested by interveners
         and Commission staff.

      2012                   0             0            0             0         1.0   1-Sided Adj

         Add one AD2 employee to run and analyze complex data queries as requested by interveners
         and Commission staff.

      2012                  41             0            0          41           0.0   1-Sided Adj

         Customer Growth handled by overtime.

      2012                   0             0            0             0         0.7   1-Sided Adj

         Customer growth handled by overtime.

      2012                 139             0            0         139           0.0   1-Sided Adj

         Increase in 2 MRP investigators (2 SA4 positions) due to the permanent increase in
         workloads as a result of Smart Meter installations.

      2012                   0             0            0             0         2.0   1-Sided Adj

         Increase in 2 MRP investigators (2 SA4 positions) due to the permanent increase in
         workloads as a result of Smart Meter installations.

      2012                   0             9            0             9         0.0   1-Sided Adj

         Non labor increase due to customer growth.

      2012                  49             0            0          49           0.0   1-Sided Adj

         Training for Smart Meter will decline and return O&M FTE count to 4.0 for Meter Revenue
         Protection.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 198 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Office Credit & Collections
Category-Sub:         1. CS Operations-Office Credit & Collections
Workpaper:            1OO002.000 - OFFICE CREDIT & COLLECTIONS

      Year/Expl.        Labor          NLbr      NSE          Total        FTE    Adj Type

      2012                   0            0            0              0        0.6   1-Sided Adj

         Training for Smart Meter will decline and return O&M FTE count to 4.0 for Meter Revenue
         Protection.

      2012                   0            0            0              0       -0.4   1-Sided Adj

         5 year average dollar and FTE impact removed as it is planned for at SCG, in USS cost
         center 2200-0354.

      2012                 -35            0            0          -35          0.0   1-Sided Adj

         5 year average dollar and FTE impact removed as it is planned for at SCG, in USS cost
         center 2200-0354.

      2012                   0            -2           0              -2       0.0   1-Sided Adj

         5 year average dollar and FTE impact removed as it is planned for at SCG, in USS cost
         center 2200-0354.

      2012 Total           296           11            0         307           4.2




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 199 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Office Credit & Collections
Category-Sub:           1. CS Operations-Office Credit & Collections
Workpaper:              1OO002.000 - OFFICE CREDIT & COLLECTIONS

Determination of Adjusted-Recorded:
                                2005 ($000)              2006 ($000)         2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                               1,726                1,659              1,525          1,562        1,615
     Non-Labor                             635                  543                465            450          467
     NSE                                     0                    0                  0              0            0
         Total                           2,361                2,202              1,990          2,012        2,082
         FTE                              33.7                 31.5               28.5           28.1         27.9
  Adjustments (Nominal $) **
     Labor                                    0                    0                -4              0            0
     Non-Labor                            -160                   -85                -2              0            0
     NSE                                      0                    0                 0              0            0
         Total                            -160                   -85                -6              0            0
         FTE                                0.0                  0.0               0.0            0.0          0.0
  Recorded-Adjusted (Nominal $)
     Labor                               1,726                1,659              1,522          1,562        1,615
     Non-Labor                             475                  458                463            450          467
     NSE                                     0                    0                  0              0            0
          Total                          2,201                2,117              1,984          2,012        2,082
          FTE                             33.7                 31.5               28.5           28.1         27.9
  Vacation & Sick (Nominal $)
     Labor                                 249                  267                228            257          249
     Non-Labor                                0                    0                  0              0            0
     NSE                                      0                    0                  0              0            0
          Total                            249                  267                228            257          249
          FTE                               5.5                  5.3                4.8            5.1          4.7
  Escalation to 2009$
     Labor                                 236                  170                105             46            0
     Non-Labor                               73                   46                 28             0            0
     NSE                                      0                    0                  0             0            0
         Total                             309                  216                133             46            0
         FTE                                0.0                  0.0                0.0           0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                               2,211                2,095              1,854          1,865        1,864
     Non-Labor                             548                  504                491            450          467
     NSE                                     0                    0                  0              0            0
         Total                           2,759                2,599              2,346          2,315        2,332
         FTE                              39.2                 36.8               33.3           33.2         32.6



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 200 of 375
                                              San Diego Gas & Electric Company
                                                 Test Year 2012 GRC - APP
                                               Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                B. Office Credit & Collections
Category-Sub:            1. CS Operations-Office Credit & Collections
Workpaper:               1OO002.000 - OFFICE CREDIT & COLLECTIONS


Summary of Adjustments to Recorded:

                                                                    In Nominal $ (000)
 Year                                     2005                  2006              2007              2008            2009
    Labor                                    0                     0                -4          -0.178                 0
    Non-Labor                             -160                   -85                -2                0                0
    NSE                                      0                     0                   0              0                0
        Total                             -160                   -85                -6          -0.178                 0
    FTE                                    0.0                   0.0               0.0               0.0             0.0


Detail of Adjustments to Recorded:

Year/Expl.       Labor         NLbr        NSE         FTE         Adj_Type      From CCtr                 RefID

2005                   0           -75           0        0.0 CCTR Transf        To 2100-0280.000            SDALEY2009091
                                                                                                                4135210043
   HR Claims costs

2005                   0           -85           0        0.0 CCTR Transf        To 2100-3637.000            SDALEY2009091
                                                                                                                4135321620
   To align historical to forecast for software license

2005 Total             0          -160           0        0.0



2006                   0           -85           0        0.0 CCTR Transf        To 2100-3637.000            SDALEY2009091
                                                                                                                4143930690
   To align historical to forecast for software license.

2006 Total             0           -85           0        0.0



2007                  -1              0          0        0.0 1-Sided Adj        N/A                         SDALEY2009092
                                                                                                                9070845073
   CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2007                  -3              0          0        0.0 1-Sided Adj        N/A                         SDALEY2009092
                                                                                                                9070945373
   CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2007                   0            -2           0        0.0 1-Sided Adj        N/A                         SDALEY2009092
                                                                                                                9071030450
   CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2007                   0        -0.016           0        0.0 1-Sided Adj        N/A                         SDALEY2009092
                                                                                                                9071111390
   CEMA - To remove incremental firestorm costs requested in CEMA for recovery.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 201 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Office Credit & Collections
Category-Sub:           1. CS Operations-Office Credit & Collections
Workpaper:              1OO002.000 - OFFICE CREDIT & COLLECTIONS


Year/Expl.      Labor         NLbr       NSE      FTE      Adj Type           From CCtr    RefID

2007                 0        -0.070        0     0.0 1-Sided Adj       N/A               SDALEY2009092
                                                                                             9071413847
    CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2007 Total           -4           -2        0     0.0



2008            -0.178            0         0     0.0 1-Sided Adj       N/A               SDALEY2009092
                                                                                             9071242923
    CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2008 Total       -0.178           0         0     0.0



2009 Total           0            0         0     0.0




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 202 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                   Non-Shared Service Workpapers




     Supplemental Workpapers for Workpaper 1OO002.000




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 203 of 375
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                                       Test Year 2012 GRC - APP
                                     Non-Shared Service Workpapers




            Application of San Diego Gas & Electric Company
            (U-902-E) for Adoption of an Advanced Metering
            Infrastructure Deployment Scenario and Associated Cost
            Recovery and Rate Design.


            Application 05-03-015
            Exhibit No.:




                                               CHAPTER 3
              METER READING AND CUSTOMER SERVICE FIELD FUNCTIONS,
                    SAFETY, BILLING AND REVENUE PROTECTION



                                     Prepared Supplemental, Consolidating
                                    Superseding and Replacement Testimony
                                                      of
                                             JAMES S. TEETER

                               SAN DIEGO GAS & ELECTRIC COMPANY




                           BEFORE THE PUBLIC UTILITIES COMMISSION
                                OF THE STATE OF CALIFORNIA



                                               March 28, 2006




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO002.000_Supp1.pdf
                                  Pages 204 of 375
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                                                   TABLE OF CONTENTS

         I.    INTRODUCTION................................................................................................. 1
         II.   BACKGROUND ................................................................................................... 1
         III.  BASE ASSUMPTIONS ........................................................................................ 2
               A.   Manual Meter Reading Costs Will Be Eliminated ..................................... 2
               B.   No Lay-Off Policy Resulting From AMI Deployment............................... 3
               C.   Employee Safety ......................................................................................... 3
               D.   Billing Will Be More Accurate And Timely .............................................. 4
               E.   Information Will Be Available More Quickly............................................ 4
               F.   More Complex Rates Will Be Enabled....................................................... 4
         IV.   SUMMARY OF COSTS & BENEFITS ............................................................. 5
         V.    AMI COST IMPACTS BY FUNCTIONAL AREA- O&M ONLY ................. 5
               A.   Meter Reading Cost Impacts....................................................................... 5
               B.   Billing And Meter Revenue Protection Cost Impacts................................. 6
               C.   Meter Installation Costs .............................................................................. 7
         VI.   AMI BENEFITS IMPACTS BY FUNCTIONAL AREA - CAPITAL, O&M 7
               A.   Meter Reading And Customer Service Field Benefits................................ 7
               B.   Safety Benefits ............................................................................................ 8
               C.   Billing And Meter Revenue Protection Benefits ........................................ 8
         VII. OTHER NON-QUANTIFIABLE BENEFITS AND IMPACTS .................... 10
               A.   Fewer Estimated Bills Results In Fewer Adjusted Bills........................... 10
               B.   Customer Privacy/Less Intrusion On Customer Property......................... 10
               C.   More Accurate Meters .............................................................................. 10
               D.   Quicker Detection Of Anomalies (OBR, Gas Leaks)............................... 10
         VIII. AMI PROJECT RISK AND SDG&E MITIGATION .................................... 11
         IX.   CONCLUSION ................................................................................................... 12
         X.    QUALIFICATIONS OF JAMES S. TEETER................................................. 13




                                                                     i




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                                      Test Year 2012 GRC - APP
                                    Non-Shared Service Workpapers




      1                                           CHAPTER 3
      2        METER READING AND CUSTOMER SERVICE FIELD FUNCTIONS,
      3                 SAFETY, BILLING AND REVENUE PROTECTION
      4                           Prepared Supplemental, Consolidating
      5                          Superseding and Replacement Testimony
      6                                                of
      7                                     JAMES S. TEETER
      8                       SAN DIEGO GAS & ELECTRIC COMPANY
      9   I.      INTRODUCTION
     10           The purpose of my testimony is to present the customer service operational
     11   benefits and costs that SDG&E will experience when an advanced metering infrastructure
     12   (AMI) is deployed and installed in its service territory. The benefits include reduced
     13   operational costs, reduced or avoided energy theft, improved customer service and more
     14   accurate metering and billing information.
     15           This testimony consolidates, supersedes, and replaces all previous direct and
     16   supplemental testimony filed by me or by any other SDG&E witness testifying in this
     17   docket, on the topics covered herein.
     18   II.     BACKGROUND
     19           Manual meter reading requires considerable walking and driving. Meter readers
     20   must deal daily with sometimes dangerous traffic and customer premise accessibility
     21    s      el         e a sa       o s e          h
          s e. ur t , D & e re e r et cs m r m t s ah ot o
          i us C r n yS G Em t r drt vlo ut e ’ e rec m n t
     22   collect customer usage information (meter reads) with a hand-held data collection device.
     23   SG&E uses meter reads to prepare monthly bills.
     24           After the meter reading route is completed, the customer meter reads are
     25                               d c           o
                                     e ei tS G Es ut ei r ao ss m T i
                                                         f
          transferred from the hand-hl dv eo D & ’cs m rnom t n yt . h
                                                            i    e    s
     26                                 e an      ci
                                 oe t m t r i bs l t n S G Es ak
          data transfer must be dn aa e red g aeoao. D & ’bc-office
     27   billing systems then perform a series of data validation routines which will, if warranted,
     28   automatically trigger a pre-billing review that may result in bill adjustments. The largest
     29   number of bill adjustments is due to meter reading error.
     30           When customers move from one residence or business to another, Customer
     31     ve l       s
           e c id C F pr nem sv it e rn cm le “l e re r
                               s e e
          Sri Fe (S ) e onl ut ith m t ad o p ta c s odro a
                                             e    o    ”




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       1             ”      a e
           cag o acut ret otnh ed e ”o t ea i ut ead “t t
                                     a
           “hne f con odro b i t “n r d frh dprn cs m rn a s r
                                           e  tg o          a
       2    a     e    o .
           e ”o t e ut e                                                    e t
                                                                           re o
           r d frh nwcs m r A certain number of these orders is to perform “ vrt
       3    we”
           o nrreads where service is left on for the convenience of property owners or managers
       4   when a tenant moves. Also, when meter reading errors are suspected, CSF employees
       5        f    e    i        e o ’ e
            ut e om “ a vry odr th ut e s e r
           m spr r a r d e f” re at cs m r m t .
       6          AMI will eliminate many such field visits which are necessary under current
       7   manual meter reading operations and, therefore, will reduce meter reading costs. SDG&E
       8   also expects AMI to improve customer service since SDG&E will obtain meter reads
       9   electronically on the date a customer desires rather than on a service order schedule
      10   which is subject to delay due to workload constraints.
      11                                        e a    ud         e   f
                                          ,ne e r a s at e D & ’ss m e om
                  To prevent billing errorsoc m t dticp r S G Es yt pr r s
      12   a series of billing edits prior to sending the customer bill. Despite comprehensive edits,
      13   some billing adjustments are required after bills have been sent. Other anomalies (billing
      14                     o ee t       eo
                            s e c d f ro p t n fh ii cc ,uh s e ri “f
                                                 e ln
           exceptions) are al dt t a e cm li o t b l g yl sc a m t sn of
                                                        e        e     ”
      15   status but registering consumption (OBR), meter failures and unauthorized energy usage
      16   (theft). With AMI, many of these billing exceptions will be eliminated and others will be
      17   detected more quickly.
      18          In my testimony, I discuss the following benefits:
      19                   Customer Service Operational Benefits of AMI System
              Function                       Operational Benefits
              Meter Reading                  Substantially reduced costs, customer convenience
              Customer Service Field         More convenient service dates; reduced costs
              Safety                         Dramatic reduction in meter-reading related
                                             accidents following AMI deployment
              Billing                        Improved accuracy and timeliness
              Meter Revenue Protection       Reduced meter failures; reduction and earlier
              (MRP)                          detection of energy theft and OBR, benefiting
                                             SDG&E customers
      20   III.   BASE ASSUMPTIONS
      21          A. Manual Meter Reading Costs Will Be Eliminated
      22              All meter data will be collected remotely by the AMI system. Meter readers
      23          will no longer visit customer premises, and the CSF staff will be reduced by
      24          approximately 25%. Meter access problems will be eliminated for all monthly
      25            e an            ot             ” i ts
                   e re i s n fr m j i o “hne f con cv i
                  m t r d g ad o a a ry f cag o acutat ie.

                                                      JST-2




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   1
   2         B. No Lay-Off Policy Resulting From AMI Deployment
   3            SDG&E recognizes the value of its employees and has developed an approach
   4         to manage labor force impacts as effectively and efficiently as possible. Although
   5         SDG&E expects AMI to eliminate areas of work, SDG&E will manage the
   6         process with zero lay-offs as a result of the AMI deployment and installation.
   7         SDG&E has reviewed the historical annual turnover rates in the affected areas.
   8         The expected turnover during the deployment and installation period exceeds the
   9         number of positions eliminated. To further mitigate adverse impacts on the
  10         affected workforce, SDG&E plans to re-train displaced employees to fill new
  11         areas of work created by AMI.
  12                                                    Table JST 3-1
  13                        Field Workforce Attrition Rates / Expected FTE Losses

                                     Attrition Rates / Expected FTE Losses
                                                                             Expected                                Approx
                                                          Historic            Annual         Required*                Work-
                                                           Annual            Attrition         Annual                 Group
                                                          Attrition           2008 -          Attrition            Population
                                                         2000 - 2005           2010          2008 - 2011           in Jan 2008
            Meter Readers                                   61%                75%             34.3%                   178
            Meter Reading Supervisors                       20%                30%             34.3%                    9
            Meter Reading Analysts                          13%                13%             34.3%                    4
            Meter Reading Administrative
            Support                                          18%                18%              34.3%                 12
            Customer Service Field Employees                 7%                  7%               5.1%                243
                          * necessary attrition required each year to reach projected post AMI workforce in 2011


  14            As shown in Table JST 3-1 (above), no layoffs of meter readers will be
  15         necessary over the AMI installation period. Any displaced employees will be
  16         offered retraining and reassignment.
  17         C. Employee Safety
  18            Meter Readers typically have relatively high injury rates due to repetitive
  19         motion, high vehicle use and environmental hazards. Following AMI system
  20         installation, far fewer employees will be required to visit meters, so these types of



                                                     JST-3




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       1        injuries will virtually be eliminated. As a result, SDG&E expects a substantial
       2        improvement in overall employee safety.
       3        D. Billing Will Be More Accurate And Timely
       4           Meter reading errors currently account for 78% of adjusted bills. Since AMI
       5        meter reads will be transmitted electronically, the number of billing adjustments
       6        will drop dramatically. With a manual meter reading system, 15-20% of meters
       7        are currently read one to four days after the scheduled meter read date, delaying
       8        the processing and mailing of bills. Another 3% of bills are held by Billing for
       9        investigation. AMI will reduce dramatically the number of delayed bills. The
      10        associated benefit dollars are included in this chapter.
      11        E. Information Will Be Available More Quickly
      12           Since meter data will be available on a more frequent basis, it will be possible
      13        to resolve anomalies more quickly, shortening the time SDG&E needs to resolve
      14        the problem. For example, new algorithms will make it possible to detect gas
      15        leaks in days rather than months. Similarly, when meters stop functioning or
      16              e     ” a s n g ti              k
                 hn e ri“f tu ei e s r g sg, D & a t apor t a
                w e m t sn ofs t bg r ie n uaeS G Ecn ae prpie
      17        action virtually in real time. Benefit dollars associated with these changes are
      18        included in this chapter.
      19        F. More Complex Rates Will Be Enabled
      20           AMI will provide more meter data which will, in turn, permit SDG&E to offer
      21        new dynamic rates. Dynamic rates will induce our customers to optimize their
      22        energy use thereby providing peak load reduction. With AMI, rates can be more
      23        customized and time differentiated as well. Additional rate options and increased
      24        billing flexibility will, however, create more complexity and increase labor time
      25        and costs for processing customer billing adjustments. For example, with 720
      26        hourly data points each month (under AMI) instead of one data point (today), it
      27        will be more challenging to prepare pre-bill or post-bill adjustments. There also
      28        will be more data elements to maintain, such as meter pulse multipliers and
      29        demand response event tracking and reconciliation. These incremental costs are
      30        included in this chapter.



                                                    JST-4




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         1   IV.       SUMMARY OF COSTS & BENEFITS
         2                                                   Table JST 3-2
         3                                            Direct Dollars (in Thousands)
                                                                                                           Average
                                                                                                            Annual

             Costs                                           Total           2008     2009       2010    2011-2038
             O&M

             Billing and MRP                                17,265       361.2       677.2      773.0       551.9
             Meter Reading and CSF                            154            34.7     59.5       59.5          0.0
                                      Total O&M Costs       17,419       395.9       736.7      832.5       551.9
                                           Total Costs      17,419       395.9       736.7      832.5       551.9


                                                                                                           Average
                                                                                                            Annual

             Benefits                                        Total           2008     2009       2010    2011-2038

             Capital

             Electric Materials                              1,654            2.2     10.7       19.1        57.9
             Gas Materials                                    874             1.2       6.4      11.7        30.5
             Meter Reading and CSF                           5,509           32.7     32.7         0.0      194.4
                                  Total Capital Benefits     8,037           36.1     49.8       30.8       282.9
             O&M

             Billing                                       188,078     1,160.0      3,148.5    5,137.1     6,379.7
             Claims                                            40             2.7       2.7        2.7         1.1
             Electric Materials                             11,121           25.3    121.1      216.9       384.2
             Gas Materials                                   5,884           13.9     73.1      132.3       202.3
             Labor and Contract Support                    103,801       239.1      1,185.3    2,131.4     3,580.2
             Meter Reading and CSF                         334,121       500.2      3,673.8    7,485.4   11,516.5
                                   Total O&M Benefits      643,044     1,941.1      8,204.4   15,105.6   22,064.0
                                        Total Benefits     651,081     1,977.2      8,254.2   15,136.4   22,346.9

         4   V.        AMI COST IMPACTS BY FUNCTIONAL AREA- O&M ONLY
         5             A. Meter Reading Cost Impacts
         6                   Additional labor will be required to adjust meter reading routes during the
         7             AMI deployment and installation period as referenced in Table JST 3-2.
         8             Reassigning meter routes allows SDG&E to achieve meter reading labor force
         9             reductions earlier. SDG&E envisions hiring three additional meter route
        10             coordinators. This will allow the meter reading workforce to be dispatched
                                                                     JST-5




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       1         efficiently and SDG&E to achieve labor savings only two months after the meters
       2         are replaced. The value of achieving these savings earlier in the deployment
       3         process is significantly greater than the additional costs.
       4         B.      Billing And Meter Revenue Protection Cost Impacts
       5              1. Billing deployment costs
       6                 The Major Markets Billing staff are experienced in handling special
       7              billing issues and billing involving interval data. Accordingly, when AMI
       8              meters are installed and new information systems are introduced, the Major
       9              Markets Billing group will require approximately 40 hours of training. All
      10              other Billing employees will require 80 hours of training.
      11              2. Billing Transition Period
      12                 System adjustments are routinely required following a large system
      13               s lt n  n i um        i          o   i ”
                      n aao D r gh aj t n pr dko n s “t m e o,
                      i tli . ui t s d s et e o,nw a a s r pr d
      14              substantial effort is required to analyze and trouble-shoot installation
      15              problems and to correct billing information manually.
      16                     Moreover, when new meters are installed, a number of data elements
      17              must be recorded properly to set up the billing systems. The exception rate is
      18              approximately 7% higher than for other types of service orders. Additionally,
      19              new data about meter communications are typically required (such as AMI
      20              communication module serial numbers). SDG&E computed the costs
      21              associated with this effort by multiplying 7% of changed meters times the
      22              average cost to process a billing exception. These costs are included in this
      23              chapter.
      24              3. More Complex Billing
      25                 Hourly meters generate more data to process. When billing adjustments
      26              are required (even though such adjustments will occur less often than with
      27              existing meters), the amount of data to process and the more complex rates
      28                lqr    tn b m      ei      e
                       i e i ad i la ri . rj t n w r ae o S G Es
                      wlr u e dioal o t ePo cos e bsd n D & ’
      29              experience in processing bills for the Statewide Pricing Pilot (SPP) conducted
      30                                 e tv      a   s qr
                               4 S G Es ur tn r l a con e i 2-50% more
                      in 2003-0. D & ’cr n i e adtacutr u e 0



                                                      JST-6




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       1              time to complete billing adjustments compared to simpler single-entry meter
       2              readings.
       3                 Further, more complex billing requires superior analytical skills and
       4              knowledge. Much of the exception bill processing will shift from clerical
       5              workers to billing analysts. In order to compensate, attract and retain
       6              employees with higher skill sets, SDG&E assumes salaries will increase by
       7              20% for the impacted billing groups.
       8              4. Meter Revenue Protection Costs
       9                 During the installation period, SDG&E will need six additional Meter
      10              Revenue Protection agents to handle the large number of energy theft cases
      11              the company anticipates discovering when the new meters are installed. There
      12              also will be some transitional costs during the first year to determine the best
      13              way to process false positive signals. After AMI installation is complete,
      14              SDG&E will require two additional agents to prosecute the large number of
      15              energy thefts we expect to uncover.
      16         C.      Meter Installation Costs
      17              During AMI system installation, there is a potential for installation and meter
      18         communications problems that will require some bill estimations. Further,
      19         SDG&E will have difficulty obtaining access to install some meters.
      20         Accordingly, SDG&E anticipates a temporary increase in estimated bills.
      21         Estimating bills will allow SDG&E and customers to realize the meter reading
      22         reduction benefit regardless of any unexpected installation problems.
      23   VI.   AMI BENEFITS IMPACTS BY FUNCTIONAL AREA - CAPITAL, O&M
      24         A. Meter Reading And Customer Service Field Benefits
      25              All manual meter reading costs will be eliminated. These costs include labor
      26         for meter readers, office meter read routing and support, vehicles and associated
      27         fuel, hardware and software, equipment, uniforms, and supplies. SDG&E
      28         computed the cost savings in each of these categories from 2005 budget costs,
      29         escalated into 2006 dollars and translated to a cost per meter basis. O&M cost
      30         savings are presented in Table JST 3-2 based on cost per meter times the number
      31         of meters converted to AMI.

                                                      JST-7




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       1            The capital benefits in this chapter include avoiding the need to replace meter
       2         reading handheld data collection devices, which are replaced on 5-7 year cycle,
       3         and CSF mobile data terminals and modems. Cost reductions have been included
       4         that would have been incurred in 2014-2015. Cost reductions were not included
       5         for data collection devices that are due to be replaced in 2007-2008 because
       6         SDG&E will need these new devices to read meters until the end of 2010.
       7            CSF benefits for reducing change of accounts, revert to owner, and read verify
       8         field service orders were determined by projecting the number of service orders
       9         expected in future years, calculating the number of employees required to
      10         complete those orders and multiplying that number by current labor rates. Cost
      11         savings include labor, vehicles and mobile data terminal (MDT) devices as well
      12         as normal equipment breakage.
      13         B. Safety Benefits
      14            Meter readers and CSF have a high number of safety incidents attributed to
      15         the work environment. SDG&E expects AMI will eliminate Motor Vehicle
      16         Incidents (MVI) and injuries reported to doctors (OSHAs), which include Lost
      17         Work Days (LWDs) resulting from an OSHA-related incident.
      18            Average workers compensation costs for meter readers in 2001-2004 were
      19         used to calculate expected safety cost benefits. To calculate this benefit, SDG&E
      20         multiplied the average cost per injury (OSHA recordable incident) by the number
      21         of safety incidents to be eliminated. SDG&E meter readers have experienced
      22         improved safety records in recent years and SDG&E continued this downward
      23         trend when calculating the cost reductions. For Customer Service Field injuries,
      24         SDG&E used a five-year average safety record since that group has not
      25         experienced declining safety incidents.
      26            Similarly, SDG&E derived the benefit of reduced motor vehicle claims by
      27         multiplying the average vehicle incident claim paid from January 2000-June 2004
      28         times the number of claims to be eliminated.
      29         C. Billing And Meter Revenue Protection Benefits
      30            Billing exceptions and billing adjustments will be reduced. Reduced billing
      31         adjustments due to meter reading errors will eliminate approximately 4,000

                                                   JST-8




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       1        electric re-bills and 2,800 gas re-bills each month (78% of Mass Market bills).
       2        Billing exceptions are also expected to be reduced by 35%.
       3           Cash flow will be improved by eliminating late meter reads. Historically,
       4        about 15-20% of meter readings have not been available on the scheduled billing
       5        date due to workload peaks and unavoidable operational issues. AMI will
       6        eliminate delayed bills. When bills are delayed one or more days, the due date is
       7        also delayed, and customers tend to pay their bills one day later. Similarly, billing
       8        for customers with a large number of accounts (summary billing) will also create
       9        cash flow benefits since SDG&E will no longer need to hold summary bills for
      10        four working days to allow time for manual meter reading.
      11           Although industry estimates of energy theft are reported to be 1-2% of
      12        revenue, SDG&E assumes that no more than 0.65% of electric revenue is lost due
      13        to meter error, energy theft and other unaccounted for energy due to prior
      14        Unaccounted for Energy (UFE) analyses. Ratepayers benefit when losses are
      15        reduced and energy costs can be shifted to those who use the energy instead of to
      16        all remaining customers, creating downward pressure on rates.
      17           A common method of stealing electric energy is to remove the meter and re-
      18        install it upside-down, causing the meter to run backwards. During 2004, 42% of
      19        energy theft discovered by SDG&E was reported by meter readers, predominantly
      20        as a result of upside-down meters. Using tamper alarms and analyzing hourly
      21        energy usage, these sources of energy theft can be eliminated. SDG&E estimates
      22        that losses prevented (revenue gained) will be 0.30% times 42%, and further
      23        reduced for losses that cannot be recovered.
      24           Revenue losses are also caused by meter error including meters that fail
      25        (100% reduction in recording) and mechanical meters that slow down over time
      26        as mechanical parts wear out (but prior to change out when the meter falls out of
      27        calibration compliance). Such losses were assumed to be 0.30% lower with solid-
      28        state meters, which is in line with experience of other utilities that installed
      29        advanced metering. SDG&E derived the increased revenue by multiplying the
      30        average revenue gained per meter times the number of meters replaced.
      31

                                                    JST-9




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       1   VII.   OTHER NON-QUANTIFIABLE BENEFITS AND IMPACTS
       2          A. Fewer Estimated Bills Results In Fewer Adjusted Bills
       3             Estimated bills very often result in adjusted bills in subsequent months. AMI
       4          will eliminate estimated bills due to meter access or staffing issues and manual
       5          meter reading errors also will be eliminated.
       6          B. Customer Privacy/Less Intrusion On Customer Property

       7             Since meter readers will not be required to visit customer premises, meter
       8           a s l   t       o s     t      h
                  e e i o i rd o cs m r poe y ah ot Fw r D &
                  r drwlntn ue n ut e ’ rpr ec m n . e eS G E
       9          customer visits will reduce collateral customer property damage.1
      10          C. More Accurate Meters
      11             Mechanical meters, in addition to being less accurate than solid-state
      12          electronic meters when new, fail as they age. Many meters stop completely and
      13          register zero-use. Such failures often go undetected for a period of time because
      14          they are assumed to be caused by customer vacancy. When a failed meter is
      15            ee t    o s e i e       r    a      ” t i
                   e c da ,ut e r b gt tpy l grh “om l r rat e
                  dt t lecs m ra ol a do a aa e t n nr a ,e ocv
      16          bill. In many cases, SDG&E must reach a compromise with the customer on
      17          paying a large retroactive bill. Eliminating slow meters and other metering issues
      18           vvg o          e      g     l st      t l
                  n l n l tn uacut fr ee ue i e l n cua b lad
                  i o i “ sad ncon d o” nry s wlr u i acr e is n
      19          assign payment obligations to those customers who use the energy rather than to
      20          all other customers.
      21          D. Quicker Detection Of Anomalies (OBR, Gas Leaks)
      22             Faster detection of high gas usage and potential gas leaks will allow SDG&E
      23          to investigate these situations as much as one month earlier. In addition to
      24          preventing a dangerous incident, earlier detection also reduces the financial
      25          burden on the customer. Also, quicker detection of anomalies, such as customers
      26               n n     e    ” as ll      e o       sv e
                   h bg s g m t i“f tu wl l w h ut et r l t r
                  w o ei ui a e rn ofs t , i ao t cs m ro eo ehi
      27          account before an adjusted bill is required. Similarly, access to hourly usage data



           1
            SDG&E currently incurs expenses for property damage arising from SDG&E personnel
           service visits.

                                                    JST-10




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       1          may also help customers understand their energy use patterns and end-uses during
       2          specific days.
       3   VIII. AMI PROJECT RISK AND SDG&E MITIGATION
       4          The major risk for the meter reading and safety benefits described above is the
       5    a ly   d
           n it o e c S G Es e re i fr s u k s sm t . D & a
                              e an
           i b i tr ue D & ’m t r d g oc a qi l a et a d S G Ehs
                                       e    cy     i e
       6   assumed that meter reader positions will be eliminated within two billing cycles after
       7   installation. To eliminate a meter reader position, SDG&E must be able to remotely read
       8   the majority of meters on an associated meter route. The ability to eliminate a route is
       9   mostly a function of gaining access to customer premises, which is discussed as a risk in
      10       r s sm         e              i e l
            . a az’ e i n (hp r 2. D & a et a iso a
           MrC r na t t oy C at 1) S G Em y sm tb lfr small number
      11   of customers for a short time period to eliminate whole meter routes.
      12          The major risk for the revenue protection benefit is if customers learn to divert
      13   energy in new, unknown ways. Given historical data from Automated Meter Reading
      14   installations, this risk does not appear too great. Also, AMI endpoints may have
      15   increased sophistication in software and tamper sensors at detecting theft. Enhancements
      16   to back office systems with new algorithms and heuristics to identify new types of theft
      17   will be developed over time. That being said, SDG&E believes that the ingenuity of a
      18   few customers will lead to some new types of theft and we have, accordingly, included
      19   this assumption in the energy theft calculation.
      20          SDG&E does not have sufficient baseline data concerning the accuracy of the
      21   meter population to precisely project the increase in accuracy from AMI meters,
      22   however, increased accuracy is supported by industry data. Moreover, the Division of
      23   Ratepayer Advocates testimony2 discusses meter accuracy as a benefit for Pacific Gas
      24       ci          a             n    i i
           n Ee r C m ayn h cm ays MI rcei ( plao 0-06-028).
           ad l tc o pn i t to pn’A poed g A p ct n 5
      25   DRA cites a 0.4% increase in meter accuracy between electromechnical and solid state
      26   meters. SDG&E has assumed a 0.3% increase in meter accuracy.
      27          The final area of risk in this chapter is the expected gaps in interval data. There
      28   are roughly 720 intervals per billing cycle, per meter for residential customers. We will

           2                          s n Ee r C m ays plao fr u oi t Ic ae
                                              ci                    i i
             Testimony on Pacific Ga ad l tc o pn’A p ct n o A t ryo nr s    h t    e
           Revenue Requirements to Recover the Costs to Deploy an Advanced Metering
           Infrastructure; Application 05-06-028; January 18, 2006; page 7-6

                                                     JST-11




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       1   be collecting four times that number of intervals for commercial customers. There are a
       2          s    a      la      s g tv s
            u br fs e t cn n wl e t m s n n r l B sd n D & ’
           nm eo i ushta ad i l d o i i i e a . ae o S G Es
       3   experience with remote data collection, we anticipate that the communication
       4   infrastructure will cause the majority of interval data gaps. Missing intervals can be
       5     i e n         g t            di     o ’       tn
            sm t ui avne a oi m bsd n n n v ulut e s sg ptr I
           et a d s g dacd l rh s ae o a i i dacs m r uae ae . f
       6   there are significant numbers of missing intervals, however, then the bill will be marked
       7       i e     c a      e   i e l la
           s et a d. e et e fh e sm t b lwl e t cs m ro
           a “sm t ” Apr n g o t s et a d is i l d o ut einquiries.
       8   This risk is largely mitigated for SDG&E during the deployment period and for a few
       9   years thereafter, because the AMI communication vendor will be contractually
      10   responsible for the performance of the communication infrastructure through the Design,
      11     l       ne
            u dR nTa f m cai ,s i us i Pu Puck se i n (hp r 1.
                             s
           B i , u, r s r ehn m a d cs dn al rshi t t oy C at 1)
                                   s e          ’ sm        e
      12   IX.    CONCLUSION
      13          Once AMI is installed, SDG&E customers will receive even better service.
      14   Customer bills will be more accurate and timely. They will be able to schedule more
      15   same-day service orders and to start and stop service (change-of-accounts) on the day of
      16   their choice. Customers will receive the benefit of lower operating costs which should
      17   decrease the need for rate increases. Finally, customers will benefit from more intangible
      18   improvements, such as less intrusion on their property and fewer estimated bills.




                                                     JST-12




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        1   X.     QUALIFICATIONS OF JAMES S. TEETER
        2          My name is James S. Teeter and I am employed by San Diego Gas & Electric
        3   Company (SDG&E). My business address is 8306 Century Park Court, Suite 42J, San
        4   Diego, CA 92123-1530.
        5          My present position is Billing Manager in the Customer Billing Operations
        6   Department of SDG&E. I have been employed by SDG&E since 1972. Previous
        7   positions relevant to my testimony include Manager-Measurement and Billing (1998-
        8   2002) and Manager-Billing Services (1989-1998).
        9          I received a B. S. in Accounting from San Diego State University. I have not
       10   previously testified before the California Public Utilities Commission.
       11   This concludes my prepared direct testimony.




                                                     JST-13




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                                                                                                                                          SDG&E Credit Services
                                                                                                                                                                                     Total growth
                                                                                                                              Base Year             2010          2011        2012   increase from
                                                                                           Meter Growth Rate                       0%               0.4%          0.6%        0.9%

                                                                                           Adjusted Labor                     $ 1,986           $ 2,110       $ 2,261    $   2,282
                                                                                           Labor increase due to growth                         $     8       $    13    $      20   $    41

                                                                                           Adjusted Non-Labo                  $   487           $   491       $   494    $    499
                                                                                           Non Labor increase due to growth                     $     2       $     3    $      4    $     9




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                                        Friday, 

                                        November 9, 2007 





                                        Part IV

                                        Department of the Treasury
                                        Office of the Comptroller of the
                                        Currency
                                        12 CFR Part 41

                                        Federal Reserve System
                                        12 CFR Part 222

                                        Federal Deposit Insurance
                                        Corporation
                                        12 CFR Parts 334 and 364

                                        Department of the Treasury
                                        Office of Thrift Supervision
                                        12 CFR Part 571

                                        National Credit Union
                                        Administration
                                        12 CFR Part 717

                                        Federal Trade Commission
                                        16 CFR Part 681

                                        Identity Theft Red Flags and Address
                                        Discrepancies Under the Fair and
                                        Accurate Credit Transactions Act of 2003;
                                        Final Rule




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    63718         Federal Register / Vol. 72, No. 217 / Friday, November 9, 2007 / Rules and Regulations

    DEPARTMENT OF THE TREASURY                   and mitigate identity theft in connection   Office of Thrift Supervision, 1700 G
                                                 with the opening of certain accounts or     Street, NW., Washington, DC 20552.
    Office of the Comptroller of the             certain existing accounts. In addition,       NCUA: Regina M. Metz, Staff
    Currency                                     the Agencies are issuing guidelines to      Attorney, Office of General Counsel,
                                                 assist financial institutions and           (703) 518–6540, National Credit Union
    12 CFR Part 41                               creditors in the formulation and            Administration, 1775 Duke Street,
    [Docket ID OCC–2007–0017]
                                                 maintenance of a Program that satisfies     Alexandria, VA 22314–3428.
                                                 the requirements of the rules. The rules      FTC: Naomi B. Lefkovitz, Attorney, or
    RIN 1557–AC87                                implementing section 114 also require       Pavneet Singh, Attorney, Division of
                                                 credit and debit card issuers to assess     Privacy and Identity Protection, Bureau
    FEDERAL RESERVE SYSTEM                       the validity of notifications of changes    of Consumer Protection, (202) 326–
                                                 of address under certain circumstances.     2252, Federal Trade Commission, 600
    12 CFR Part 222                              Additionally, the Agencies are issuing      Pennsylvania Avenue, NW., Washington
    [Docket No. R–1255]                          joint rules under section 315 that          DC 20580.
                                                 provide guidance regarding reasonable       SUPPLEMENTARY INFORMATION:
    FEDERAL DEPOSIT INSURANCE                    policies and procedures that a user of
    CORPORATION                                  consumer reports must employ when a         I. Introduction
                                                 consumer reporting agency sends the            The President signed the FACT Act
    12 CFR Parts 334 and 364                     user a notice of address discrepancy.       into law on December 4, 2003.1 The
                                                 DATES: The joint final rules and            FACT Act added several new provisions
    RIN 3064–AD00
                                                 guidelines are effective January 1, 2008.   to the Fair Credit Reporting Act of 1970
    DEPARTMENT OF THE TREASURY                   The mandatory compliance date for this      (FCRA), 15 U.S.C. 1681 et seq. Section
                                                 rule is November 1, 2008.                   114 of the FACT Act, 15 U.S.C.
    Office of Thrift Supervision                                                             1681m(e), amends section 615 of the
                                                 FOR FURTHER INFORMATION CONTACT:
                                                                                             FCRA, and directs the Agencies to issue
                                                   OCC: Amy Friend, Assistant Chief          joint regulations and guidelines
    12 CFR Part 571                              Counsel, (202) 874–5200; Deborah Katz,      regarding the detection, prevention, and
    [Docket No. OTS–2007–0019]                   Senior Counsel, or Andra Shuster,           mitigation of identity theft, including
                                                 Special Counsel, Legislative and            special regulations requiring debit and
    RIN 1550–AC04                                Regulatory Activities Division, (202)       credit card issuers to validate
                                                 874–5090; Paul Utterback, Compliance        notifications of changes of address
    NATIONAL CREDIT UNION
                                                 Specialist, Compliance Department,          under certain circumstances.2 Section
    ADMINISTRATION
                                                 (202) 874–5461; or Aida Plaza Carter,       315 of the FACT Act, 15 U.S.C.
                                                 Director, Bank Information Technology,      1681c(h), adds a new section 605(h)(2)
    12 CFR Part 717
                                                 (202) 874–4740, Office of the               to the FCRA requiring the Agencies to
                                                 Comptroller of the Currency, 250 E          issue joint regulations that provide
    FEDERAL TRADE COMMISSION
                                                 Street, SW., Washington, DC 20219.          guidance regarding reasonable policies
    16 CFR Part 681                                Board: David A. Stein or Ky Tran-         and procedures that a user of a
                                                 Trong, Counsels, or Amy Burke,              consumer report should employ when
    RIN 3084–AA94                                Attorney, Division of Consumer and          the user receives a notice of address
                                                 Community Affairs, (202) 452–3667;          discrepancy.
    Identity Theft Red Flags and Address         Kara L. Handzlik, Attorney, Legal              On July 18, 2006, the Agencies
    Discrepancies Under the Fair and             Division, (202) 452–3852; or John           published a joint notice of proposed
    Accurate Credit Transactions Act of          Gibbons, Supervisory Financial Analyst,     rulemaking (NPRM) in the Federal
    2003                                         Division of Banking Supervision and         Register (71 FR 40786) proposing rules
    AGENCIES:  Office of the Comptroller of      Regulation, (202) 452–6409, Board of        and guidelines to implement section
    the Currency, Treasury (OCC); Board of       Governors of the Federal Reserve            114 and proposing rules to implement
    Governors of the Federal Reserve             System, 20th and C Streets, NW.,            section 315 of the FACT Act. The public
    System (Board); Federal Deposit              Washington, DC 20551.                       comment period closed on September
    Insurance Corporation (FDIC); Office of        FDIC: Jeffrey M. Kopchik, Senior          18, 2006. The Agencies collectively
    Thrift Supervision, Treasury (OTS);          Policy Analyst, (202) 898–3872, or          received a total of 129 comments in
    National Credit Union Administration         David P. Lafleur, Policy Analyst, (202)     response to the NPRM, although many
    (NCUA); and Federal Trade Commission         898–6569, Division of Supervision and       commenters sent copies of the same
    (FTC or Commission).                         Consumer Protection; Richard M.             letter to each of the Agencies. The
    ACTION: Joint final rules and guidelines.
                                                 Schwartz, Counsel, (202) 898–7424, or       comments included 63 from financial
                                                 Richard B. Foley, Counsel, (202) 898–       institutions, 12 from financial
    SUMMARY:   The OCC, Board, FDIC, OTS,        3784, Legal Division, Federal Deposit       institution holding companies, 23 from
    NCUA and FTC (the Agencies) are              Insurance Corporation, 550 17th Street,     financial institution trade associations,
    jointly issuing final rules and guidelines   NW., Washington, DC 20429.                  12 from individuals, nine from other
    implementing section 114 of the Fair           OTS: Ekita Mitchell, Consumer             trade associations, five from other
    and Accurate Credit Transactions Act of      Regulations Analyst, Compliance and         business entities, three from consumer
    2003 (FACT Act) and final rules              Consumer Protection, (202) 906–6451;
    implementing section 315 of the FACT         Kathleen M. McNulty, Technology               1 Pub.  L. 108–159.
    Act. The rules implementing section          Program Manager, Information                  2 Section 111 of the FACT Act defines ‘‘identity

    114 require each financial institution or    Technology Risk Management, (202)           theft’’ as ‘‘a fraud committed using the identifying
                                                                                             information of another person, subject to such
    creditor to develop and implement a          906–6322; or Richard Bennett, Senior        further definition as the [Federal Trade]
    written Identity Theft Prevention            Compliance Counsel, Regulations and         Commission may prescribe, by regulation.’’ 15
    Program (Program) to detect, prevent,        Legislation Division, (202) 906–7409,       U.S.C. 1681a(q)(3).




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                      Federal Register / Vol. 72, No. 217 / Friday, November 9, 2007 / Rules and Regulations                                                   63719

    groups,3 one from a member of                             indicators of a possible risk of identity             commenters suggested that the
    Congress, and one from the United                         theft (Red Flags), including indicators               regulations and guidelines take the form
    States Small Business Administration                      from among those listed in the                        of broad objectives modeled on the
    (SBA).                                                    guidelines. To promote flexibility and                objectives set forth in the ‘‘Interagency
                                                              responsiveness to the changing nature of              Guidelines Establishing Information
    II. Section 114 of the FACT Act
                                                              identity theft, the proposed rules also               Security Standards’’ (Information
    A. Red Flag Regulations and Guidelines                    stated that covered entities would need               Security Standards).7 A few financial
    1. Background                                             to include in their Programs relevant                 institution commenters asserted that the
                                                              Red Flags from applicable supervisory                 primary cause of identity theft is the
       Section 114 of the FACT Act requires                   guidance, their own experiences, and                  lack of care on the part of the consumer.
    the Agencies to jointly issue guidelines                  methods that the entity had identified                They stated that consumers should be
    for financial institutions and creditors                  that reflect changes in identity theft                held responsible for protecting their
    regarding identity theft with respect to                  risks.                                                own identifying information.
    their account holders and customers.                         The Agencies invited comment on all                  The Agencies have modified the
    Section 114 also directs the Agencies to                  aspects of the proposed regulations and               proposed rules and guidelines in light of
    prescribe joint regulations requiring                     guidelines implementing section 114,                  the comments received. An overview of
    each financial institution and creditor to                and specifically requested comment on                 the final rules, guidelines, and
    establish reasonable policies and                         whether the elements described in                     supplement, a discussion of the
    procedures for implementing the                           section 114 had been properly allocated               comments, and the specific manner in
    guidelines, to identify possible risks to                 between the proposed regulations and                  which the proposed rules and
    account holders or customers or to the                    the proposed guidelines.                              guidelines have been modified, follows.
    safety and soundness of the institution                      Consumer groups maintained that the
    or ‘‘customer.’’4                                         proposed regulations provided too                     3. Overview of final rules and
       In developing the guidelines, the                      much discretion to financial institutions             guidelines
    Agencies must identify patterns,                          and creditors to decide which accounts                   The Agencies are issuing final rules
    practices, and specific forms of activity                 and Red Flags to include in their                     and guidelines that provide both
    that indicate the possible existence of                   Programs and how to respond to those                  flexibility and more guidance to
    identity theft. The guidelines must be                    Red Flags. These commenters stated that               financial institutions and creditors. The
    updated as often as necessary, and                        the flexible and risk-based approach                  final rules also require the Program to
    cannot be inconsistent with the policies                  taken in the proposed rulemaking                      address accounts where identity theft is
    and procedures issued under section                       would permit ‘‘business as usual.’’
    326 of the USA PATRIOT Act,5 31                                                                                 most likely to occur. The final rules
                                                                 Some small financial institutions also             describe which financial institutions
    U.S.C. 5318(l), that require verification                 expressed concern about the flexibility
    of the identity of persons opening new                                                                          and creditors are required to have a
                                                              afforded by the proposal. These                       Program, the objectives of the Program,
    accounts. The Agencies also must                          commenters stated that they preferred to
    consider including reasonable                                                                                   the elements that the Program must
                                                              have clearer, more structured guidance                contain, and how the Program must be
    guidelines that would apply when a                        describing exactly how to develop and
    transaction occurs in connection with a                                                                         administered.
                                                              implement a Program and what they                        Under the final rules, only those
    consumer’s credit or deposit account                      would need to do to achieve
    that has been inactive for two years.                                                                           financial institutions and creditors that
                                                              compliance.                                           offer or maintain ‘‘covered accounts’’
    These guidelines would provide that in                       Most commenters, however, including
    such circumstances, a financial                                                                                 must develop and implement a written
                                                              many financial institutions and                       Program. A covered account is (1) an
    institution or creditor ‘‘shall follow                    creditors, asserted that the proposal was
    reasonable policies and procedures’’ for                                                                        account primarily for personal, family,
                                                              overly prescriptive, contained                        or household purposes, that involves or
    notifying the consumer, ‘‘in a manner                     requirements beyond those mandated in
    reasonably designed to reduce the                                                                               is designed to permit multiple payments
                                                              the FACT Act, would be costly and                     or transactions, or (2) any other account
    likelihood of identity theft.’’                           burdensome to implement, and would                    for which there is a reasonably
    2. Overview of Proposal and Comments                      complicate the existing efforts of                    foreseeable risk to customers or the
    Received                                                  financial institutions and creditors to               safety and soundness of the financial
       The Agencies proposed to implement                     detect and prevent identity theft. Some               institution or creditor from identity
    section 114 through regulations                           industry commenters asserted that the                 theft. Each financial institution and
    requiring each financial institution and                  rulemaking was unnecessary because                    creditor must periodically determine
    creditor to implement a written Program                   large businesses, such as banks and                   whether it offers or maintains a
    to detect, prevent and mitigate identity                  telecommunications companies, already                 ‘‘covered account.’’
    theft in connection with the opening of                   are motivated to prevent identity theft
                                                                                                                       The final regulations provide that the
    an account or any existing account. The                   and other forms of fraud in order to
                                                                                                                    Program must be designed to detect,
    Agencies also proposed guidelines that                    limit their own financial losses.
                                                                                                                    prevent, and mitigate identity theft in
    identified 31 patterns, practices, and                    Financial institution commenters
                                                                                                                    connection with the opening of a
    specific forms of activity that indicate a                maintained that they are already doing
                                                                                                                    covered account or any existing covered
    possible risk of identity theft. The                      most of what would be required by the
                                                                                                                    account. In addition, the Program must
    proposed regulations required each                        proposal as a result of having to comply
                                                                                                                    be tailored to the entity’s size,
    financial institution and creditor to                     with the customer identification
                                                                                                                    complexity and nature of its operations.
    incorporate into its Program relevant                     program (CIP) regulations implementing
                                                              section 326 of the USA PATRIOT Act 6                    7 12 CFR part 30, app. B (national banks); 12 CFR
      3 One  of these letters represented the comments        and other existing requirements. These                part 208, app. D–2 and part 225, app. F (state
    of five consumer groups.                                                                                        member banks and holding companies); 12 CFR
      4 Use of the term ‘‘customer,’’ here, appears to be       6 See, e.g., 31 CFR 103.121 (applicable to banks,   part 364, app. B (state non-member banks); 12 CFR
    a drafting error and likely should read ‘‘creditor.’’     thrifts and credit unions and certain non-federally   part 570, app. B (savings associations); 12 CFR part
      5 Pub. L. 107–56.                                       regulated banks).                                     748, App. A (credit unions).




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    63754         Federal Register / Vol. 72, No. 217 / Friday, November 9, 2007 / Rules and Regulations

    phone account, utility account,                  (i) Identify relevant Red Flags for the    implement reasonable policies and
    checking account, or savings account;         covered accounts that the financial           procedures to assess the validity of a
    and                                           institution or creditor offers or             change of address if it receives
       (ii) Any other account that the            maintains, and incorporate those Red          notification of a change of address for a
    financial institution or creditor offers or   Flags into its Program;                       consumer’s debit or credit card account
    maintains for which there is a                   (ii) Detect Red Flags that have been       and, within a short period of time
    reasonably foreseeable risk to customers      incorporated into the Program of the          afterwards (during at least the first 30
    or to the safety and soundness of the         financial institution or creditor;            days after it receives such notification),
    financial institution or creditor from           (iii) Respond appropriately to any Red     the card issuer receives a request for an
    identity theft, including financial,          Flags that are detected pursuant to           additional or replacement card for the
    operational, compliance, reputation, or       paragraph (d)(2)(ii) of this section to       same account. Under these
    litigation risks.                             prevent and mitigate identity theft; and      circumstances, the card issuer may not
       (4) Credit has the same meaning as in         (iv) Ensure the Program (including the     issue an additional or replacement card,
    15 U.S.C. 1681a(r)(5).                        Red Flags determined to be relevant) is       until, in accordance with its reasonable
       (5) Creditor has the same meaning as       updated periodically, to reflect changes      policies and procedures and for the
    in 15 U.S.C. 1681a(r)(5), and includes        in risks to customers and to the safety       purpose of assessing the validity of the
    lenders such as banks, finance                and soundness of the financial                change of address, the card issuer:
    companies, automobile dealers,                institution or creditor from identity            (1)(i) Notifies the cardholder of the
    mortgage brokers, utility companies,          theft.                                        request:
    and telecommunications companies.                (e) Administration of the Program.            (A) At the cardholder’s former
       (6) Customer means a person that has       Each financial institution or creditor        address; or
    a covered account with a financial            that is required to implement a Program          (B) By any other means of
    institution or creditor.                      must provide for the continued                communication that the card issuer and
       (7) Financial institution has the same     administration of the Program and must:       the cardholder have previously agreed
    meaning as in 15 U.S.C. 1681a(t).                (1) Obtain approval of the initial         to use; and
       (8) Identity theft has the same            written Program from either its board of         (ii) Provides to the cardholder a
    meaning as in 16 CFR 603.2(a).                directors or an appropriate committee of      reasonable means of promptly reporting
       (9) Red Flag means a pattern, practice,    the board of directors;                       incorrect address changes; or
    or specific activity that indicates the          (2) Involve the board of directors, an        (2) Otherwise assesses the validity of
    possible existence of identity theft.         appropriate committee thereof, or a           the change of address in accordance
       (10) Service provider means a person       designated employee at the level of           with the policies and procedures the
    that provides a service directly to the       senior management in the oversight,           card issuer has established pursuant to
    financial institution or creditor.            development, implementation and               § 41.90 of this part.
       (c) Periodic Identification of Covered     administration of the Program;                   (d) Alternative timing of address
    Accounts. Each financial institution or          (3) Train staff, as necessary, to          validation. A card issuer may satisfy the
    creditor must periodically determine          effectively implement the Program; and        requirements of paragraph (c) of this
                                                     (4) Exercise appropriate and effective     section if it validates an address
    whether it offers or maintains covered
                                                  oversight of service provider                 pursuant to the methods in paragraph
    accounts. As a part of this
                                                  arrangements.                                 (c)(1) or (c)(2) of this section when it
    determination, a financial institution or
                                                     (f) Guidelines. Each financial             receives an address change notification,
    creditor must conduct a risk assessment
                                                  institution or creditor that is required to   before it receives a request for an
    to determine whether it offers or
                                                  implement a Program must consider the         additional or replacement card.
    maintains covered accounts described
                                                  guidelines in Appendix J of this part            (e) Form of notice. Any written or
    in paragraph (b)(3)(ii) of this section,
                                                  and include in its Program those              electronic notice that the card issuer
    taking into consideration:
                                                  guidelines that are appropriate.              provides under this paragraph must be
       (1) The methods it provides to open
    its accounts;                                 § 41.91 Duties of card issuers regarding      clear and conspicuous and provided
       (2) The methods it provides to access      changes of address.                           separately from its regular
    its accounts; and                               (a) Scope. This section applies to an       correspondence with the cardholder.
       (3) Its previous experiences with          issuer of a debit or credit card (card        Appendices D–I [Reserved]
    identity theft.                               issuer) that is a national bank, Federal
       (d) Establishment of an Identity Theft     branch or agency of a foreign bank, and       ■ 7. Add and reserve appendices D
    Prevention Program. (1) Program               any of their operating subsidiaries that      through I to part 41.
    requirement. Each financial institution       are not functionally regulated within the     ■ 8. Add Appendix J to part 41 to read
    or creditor that offers or maintains one      meaning of section 5(c)(5) of the Bank        as follows:
    or more covered accounts must develop         Holding Company Act of 1956, as
    and implement a written Identity Theft                                                      Appendix J to Part 41—Interagency
                                                  amended (12 U.S.C. 1844(c)(5)).
    Prevention Program (Program) that is                                                        Guidelines on Identity Theft Detection,
                                                     (b) Definitions. For purposes of this
    designed to detect, prevent, and mitigate                                                   Prevention, and Mitigation
                                                  section:
    identity theft in connection with the            (1) Cardholder means a consumer               Section 41.90 of this part requires each
    opening of a covered account or any           who has been issued a credit or debit         financial institution and creditor that offers
    existing covered account. The Program         card.                                         or maintains one or more covered accounts,
    must be appropriate to the size and              (2) Clear and conspicuous means            as defined in § 41.90(b)(3) of this part, to
    complexity of the financial institution                                                     develop and provide for the continued
                                                  reasonably understandable and
                                                                                                administration of a written Program to detect,
    or creditor and the nature and scope of       designed to call attention to the nature      prevent, and mitigate identity theft in
    its activities.                               and significance of the information           connection with the opening of a covered
       (2) Elements of the Program. The           presented.                                    account or any existing covered account.
    Program must include reasonable                  (c) Address validation requirements.       These guidelines are intended to assist
    policies and procedures to:                   A card issuer must establish and              financial institutions and creditors in the




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                    Federal Register / Vol. 72, No. 217 / Friday, November 9, 2007 / Rules and Regulations                                       63755

    formulation and maintenance of a Program           IV. Preventing and Mitigating Identity Theft       administration of its Program should report
    that satisfies the requirements of § 41.90 of         The Program’s policies and procedures           to the board of directors, an appropriate
    this part.                                         should provide for appropriate responses to        committee of the board, or a designated
    I. The Program                                     the Red Flags the financial institution or         employee at the level of senior management,
                                                       creditor has detected that are commensurate        at least annually, on compliance by the
       In designing its Program, a financial
    institution or creditor may incorporate, as        with the degree of risk posed. In determining      financial institution or creditor with § 41.90
    appropriate, its existing policies, procedures,    an appropriate response, a financial               of this part.
    and other arrangements that control                institution or creditor should consider               (2) Contents of report. The report should
    reasonably foreseeable risks to customers or       aggravating factors that may heighten the risk     address material matters related to the
    to the safety and soundness of the financial       of identity theft, such as a data security         Program and evaluate issues such as: the
    institution or creditor from identity theft.       incident that results in unauthorized access       effectiveness of the policies and procedures
                                                       to a customer’s account records held by the        of the financial institution or creditor in
    II. Identifying Relevant Red Flags                 financial institution, creditor, or third party,   addressing the risk of identity theft in
       (a) Risk Factors. A financial institution or    or notice that a customer has provided             connection with the opening of covered
    creditor should consider the following factors     information related to a covered account held      accounts and with respect to existing covered
    in identifying relevant Red Flags for covered      by the financial institution or creditor to        accounts; service provider arrangements;
    accounts, as appropriate:                          someone fraudulently claiming to represent         significant incidents involving identity theft
       (1) The types of covered accounts it offers     the financial institution or creditor or to a
    or maintains;                                                                                         and management’s response; and
                                                       fraudulent website. Appropriate responses
       (2) The methods it provides to open its                                                            recommendations for material changes to the
                                                       may include the following:
    covered accounts;                                     (a) Monitoring a covered account for            Program.
       (3) The methods it provides to access its       evidence of identity theft;                           (c) Oversight of service provider
    covered accounts; and                                 (b) Contacting the customer;                    arrangements. Whenever a financial
       (4) Its previous experiences with identity         (c) Changing any passwords, security            institution or creditor engages a service
    theft.                                             codes, or other security devices that permit       provider to perform an activity in connection
       (b) Sources of Red Flags. Financial             access to a covered account;                       with one or more covered accounts the
    institutions and creditors should incorporate         (d) Reopening a covered account with a          financial institution or creditor should take
    relevant Red Flags from sources such as:           new account number;                                steps to ensure that the activity of the service
       (1) Incidents of identity theft that the           (e) Not opening a new covered account;          provider is conducted in accordance with
    financial institution or creditor has                 (f) Closing an existing covered account;        reasonable policies and procedures designed
    experienced;                                          (g) Not attempting to collect on a covered      to detect, prevent, and mitigate the risk of
       (2) Methods of identity theft that the          account or not selling a covered account to        identity theft. For example, a financial
    financial institution or creditor has identified   a debt collector;                                  institution or creditor could require the
    that reflect changes in identity theft risks;         (h) Notifying law enforcement; or               service provider by contract to have policies
    and                                                   (i) Determining that no response is             and procedures to detect relevant Red Flags
       (3) Applicable supervisory guidance.            warranted under the particular                     that may arise in the performance of the
       (c) Categories of Red Flags. The Program        circumstances.
    should include relevant Red Flags from the                                                            service provider’s activities, and either report
    following categories, as appropriate.              V. Updating the Program                            the Red Flags to the financial institution or
    Examples of Red Flags from each of these              Financial institutions and creditors should     creditor, or to take appropriate steps to
    categories are appended as Supplement A to         update the Program (including the Red Flags        prevent or mitigate identity theft.
    this Appendix J.                                   determined to be relevant) periodically, to        VII. Other Applicable Legal Requirements
       (1) Alerts, notifications, or other warnings    reflect changes in risks to customers or to the
                                                                                                            Financial institutions and creditors should
    received from consumer reporting agencies or       safety and soundness of the financial
                                                       institution or creditor from identity theft,       be mindful of other related legal
    service providers, such as fraud detection
    services;                                          based on factors such as:                          requirements that may be applicable, such as:
       (2) The presentation of suspicious                 (a) The experiences of the financial              (a) For financial institutions and creditors
    documents;                                         institution or creditor with identity theft;       that are subject to 31 U.S.C. 5318(g), filing a
       (3) The presentation of suspicious personal        (b) Changes in methods of identity theft;       Suspicious Activity Report in accordance
    identifying information, such as a suspicious         (c) Changes in methods to detect, prevent,      with applicable law and regulation;
    address change;                                    and mitigate identity theft;                         (b) Implementing any requirements under
       (4) The unusual use of, or other suspicious        (d) Changes in the types of accounts that       15 U.S.C. 1681c–1(h) regarding the
    activity related to, a covered account; and        the financial institution or creditor offers or    circumstances under which credit may be
       (5) Notice from customers, victims of           maintains; and                                     extended when the financial institution or
    identity theft, law enforcement authorities, or       (e) Changes in the business arrangements        creditor detects a fraud or active duty alert;
    other persons regarding possible identity          of the financial institution or creditor,            (c) Implementing any requirements for
    theft in connection with covered accounts          including mergers, acquisitions, alliances,        furnishers of information to consumer
    held by the financial institution or creditor.     joint ventures, and service provider               reporting agencies under 15 U.S.C. 1681s–2,
    III. Detecting Red Flags                           arrangements.                                      for example, to correct or update inaccurate
       The Program’s policies and procedures           VI. Methods for Administering the Program          or incomplete information, and to not report
    should address the detection of Red Flags in          (a) Oversight of Program. Oversight by the      information that the furnisher has reasonable
    connection with the opening of covered             board of directors, an appropriate committee       cause to believe is inaccurate; and
    accounts and existing covered accounts, such       of the board, or a designated employee at the        (d) Complying with the prohibitions in 15
    as by:                                             level of senior management should include:         U.S.C. 1681m on the sale, transfer, and
       (a) Obtaining identifying information              (1) Assigning specific responsibility for the   placement for collection of certain debts
    about, and verifying the identity of, a person     Program’s implementation;                          resulting from identity theft.
    opening a covered account, for example,               (2) Reviewing reports prepared by staff         Supplement A to Appendix J
    using the policies and procedures regarding        regarding compliance by the financial
    identification and verification set forth in the   institution or creditor with § 41.90 of this          In addition to incorporating Red Flags from
    Customer Identification Program rules              part; and                                          the sources recommended in section II.b. of
    implementing 31 U.S.C. 5318(l) (31 CFR                (3) Approving material changes to the           the Guidelines in Appendix J of this part,
    103.121); and                                      Program as necessary to address changing           each financial institution or creditor may
       (b) Authenticating customers, monitoring        identity theft risks.                              consider incorporating into its Program,
    transactions, and verifying the validity of           (b) Reports. (1) In general. Staff of the       whether singly or in combination, Red Flags
    change of address requests, in the case of         financial institution or creditor responsible      from the following illustrative examples in
    existing covered accounts.                         for development, implementation, and               connection with covered accounts:




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    63756           Federal Register / Vol. 72, No. 217 / Friday, November 9, 2007 / Rules and Regulations

    Alerts, Notifications or Warnings from a          internal or third-party sources used by the          24. The financial institution or creditor is
    Consumer Reporting Agency                         financial institution or creditor. For example:   notified that the customer is not receiving
       1. A fraud or active duty alert is included       a. The address on an application is            paper account statements.
    with a consumer report.                           fictitious, a mail drop, or a prison; or             25. The financial institution or creditor is
       2. A consumer reporting agency provides a         b. The phone number is invalid, or is          notified of unauthorized charges or
    notice of credit freeze in response to a          associated with a pager or answering service.     transactions in connection with a customer’s
    request for a consumer report.                       14. The SSN provided is the same as that       covered account.
       3. A consumer reporting agency provides a      submitted by other persons opening an             Notice From Customers, Victims of Identity
    notice of address discrepancy, as defined in      account or other customers.                       Theft, Law Enforcement Authorities, or Other
    § 41.82(b) of this part.                             15. The address or telephone number            Persons Regarding Possible Identity Theft in
       4. A consumer report indicates a pattern of    provided is the same as or similar to the         Connection With Covered Accounts Held by
    activity that is inconsistent with the history    account number or telephone number                the Financial Institution or Creditor
    and usual pattern of activity of an applicant     submitted by an unusually large number of
                                                                                                           26. The financial institution or creditor is
    or customer, such as:                             other persons opening accounts or other           notified by a customer, a victim of identity
       a. A recent and significant increase in the    customers.                                        theft, a law enforcement authority, or any
    volume of inquiries;                                 16. The person opening the covered             other person that it has opened a fraudulent
       b. An unusual number of recently               account or the customer fails to provide all      account for a person engaged in identity
    established credit relationships;                 required personal identifying information on      theft.
       c. A material change in the use of credit,     an application or in response to notification
    especially with respect to recently               that the application is incomplete.               Board of Governors of the Federal
    established credit relationships; or                 17. Personal identifying information           Reserve System
       d. An account that was closed for cause or     provided is not consistent with personal
    identified for abuse of account privileges by     identifying information that is on file with        12 CFR Chapter II.
    a financial institution or creditor.              the financial institution or creditor.            Authority and Issuance
                                                         18. For financial institutions and creditors
    Suspicious Documents
                                                      that use challenge questions, the person          ■ For the reasons set forth in the joint
       5. Documents provided for identification       opening the covered account or the customer       preamble, part 222 of title 12, chapter II,
    appear to have been altered or forged.            cannot provide authenticating information         of the Code of Federal Regulations is
       6. The photograph or physical description      beyond that which generally would be
    on the identification is not consistent with
                                                                                                        amended as follows:
                                                      available from a wallet or consumer report.
    the appearance of the applicant or customer
    presenting the identification.
                                                      Unusual Use of, or Suspicious Activity            PART 222—FAIR CREDIT REPORTING
                                                      Related to, the Covered Account                   (REGULATION V)
       7. Other information on the identification
    is not consistent with information provided          19. Shortly following the notice of a change
                                                                                                        ■ 1. The authority citation for part 222
    by the person opening a new covered account       of address for a covered account, the
                                                      institution or creditor receives a request for    continues to read as follows:
    or customer presenting the identification.
       8. Other information on the identification     a new, additional, or replacement card or a         Authority: 15 U.S.C. 1681a, 1681b, 1681c,
    is not consistent with readily accessible         cell phone, or for the addition of authorized     1681m, 1681s, 1681s–2, 1681s–3, 1681t, and
    information that is on file with the financial    users on the account.                             1681w; Secs. 3 and 214, Pub. L. 108–159, 117
    institution or creditor, such as a signature         20. A new revolving credit account is used     Stat. 1952.
    card or a recent check.                           in a manner commonly associated with
       9. An application appears to have been         known patterns of fraud patterns. For             Subpart A—General Provisions
    altered or forged, or gives the appearance of     example:
    having been destroyed and reassembled.               a. The majority of available credit is used    ■ 2. Section 222.3 is amended by
                                                      for cash advances or merchandise that is          revising the introductory text to read as
    Suspicious Personal Identifying Information       easily convertible to cash (e.g., electronics     follows:
       10. Personal identifying information           equipment or jewelry); or
    provided is inconsistent when compared               b. The customer fails to make the first        § 222.3 Definitions.
    against external information sources used by      payment or makes an initial payment but no          For purposes of this part, unless
    the financial institution or creditor. For        subsequent payments.                              explicitly stated otherwise:
    example:                                             21. A covered account is used in a manner      *     *     *     *    *
       a. The address does not match any address      that is not consistent with established
                                                                                                        ■ 3. The heading for Subpart I is revised
    in the consumer report; or                        patterns of activity on the account. There is,
       b. The Social Security Number (SSN) has        for example:                                      to read as follows:
    not been issued, or is listed on the Social          a. Nonpayment when there is no history of
    Security Administration’s Death Master File.      late or missed payments;                          Subpart I—Duties of Users of
       11. Personal identifying information              b. A material increase in the use of           Consumer Reports Regarding Address
    provided by the customer is not consistent        available credit;                                 Discrepancies and Records Disposal
    with other personal identifying information          c. A material change in purchasing or
    provided by the customer. For example, there      spending patterns;                                ■ 4. A new § 222.82 is added to read as
    is a lack of correlation between the SSN             d. A material change in electronic fund        follows:
    range and date of birth.                          transfer patterns in connection with a deposit
       12. Personal identifying information           account; or                                       § 222.82 Duties of users regarding address
    provided is associated with known                    e. A material change in telephone call         discrepancies.
    fraudulent activity as indicated by internal or   patterns in connection with a cellular phone        (a) Scope. This section applies to a
    third-party sources used by the financial         account.                                          user of consumer reports (user) that
    institution or creditor. For example:                22. A covered account that has been            receives a notice of address discrepancy
       a. The address on an application is the        inactive for a reasonably lengthy period of       from a consumer reporting agency, and
    same as the address provided on a fraudulent      time is used (taking into consideration the       that is a member bank of the Federal
    application; or                                   type of account, the expected pattern of usage
                                                                                                        Reserve System (other than a national
       b. The phone number on an application is       and other relevant factors).
    the same as the number provided on a                 23. Mail sent to the customer is returned      bank) and its respective operating
    fraudulent application.                           repeatedly as undeliverable although              subsidiaries, a branch or agency of a
       13. Personal identifying information           transactions continue to be conducted in          foreign bank (other than a Federal
    provided is of a type commonly associated         connection with the customer’s covered            branch, Federal agency, or insured State
    with fraudulent activity as indicated by          account.                                          branch of a foreign bank), commercial




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       COM/CAB/tcg                                         Date of Issuance 2/5/2010



       BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

       Order Instituting Rulemaking on the                         FILED
       Commission’s Own Motion to address the          PUBLIC UTILITIES COMMISSION
       issue of customers’ electric and natural gas          FEBRUARY 4, 2010
       service disconnection.                          SAN FRANCISCO, CALIFORNIA
                                                          RULEMAKING 10-02-005




                           ORDER INSTITUTING RULEMAKING
                TO ESTABLISH WAYS TO IMPROVE CUSTOMER NOTIFICATION
                   AND EDUCATION TO DECREASE THE NUMBER OF GAS
                    AND ELECTRIC UTILITY SERVICE DISCONNECTIONS

       1. Summary
                We open this rulemaking to continue our efforts to reduce the number of
       residential gas and electric utility service disconnections due to nonpayment by
       improving customer notification and education. The economic crisis currently
       existing in California and a recent increase in utility service disconnections has
       led us to reexamine utility disconnection rules and practices. We want to
       identify more effective ways for the utilities to work with their customers and
       develop solutions that avoid unnecessary disconnections without placing an
       undue cost burden on other customers.
                In this rulemaking, we require Pacific Gas and Electric Company (PG&E),
       Southern California Edison Company (SCE), and San Diego Gas & Electric
       Company (SDG&E), and Southern California Gas Company (SoCalGas) to
       implement the following interim practices no later than five business days from
       the mailing of this order:



       414189                               -1-




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              1) All customer service representatives (CSRs) must inform any
                 customer that owes an arrearage on a utility bill that puts the
                 customer at risk for disconnection that the customer has right to
                 arrange for a bill payment plan extending a minimum of three
                 months in which to repay the arrearage. CSRs may exercise
                 discretion as to extending the three months up to twelve months1
                 depending on the particulars of a customer’s situation and ability
                 to repay the arrearage. CSRs may work with customers to
                 develop a shorter repayment plan, as long as the customer is
                 informed of the three-month option. Customers must keep
                 current on their utility bills while repaying the arrearage balance.
              2) Once a customer has established credit as a customer of that
                 utility, the utility must not require that customer to pay additional
                 reestablishment of credit deposits with the utility for either
                 slow-payment/no-payment of bills or following a disconnection.
              3) Each utility is authorized to file a Tier 1 advice letter to establish a
                 memorandum account to track any significant additional costs
                 associated with complying with the new practices initiated with
                 this rulemaking, including the operations and maintenance
                 charges associated with implementing the practices as well as any
                 uncollectables that are in excess of those projected in the utility’s
                 last general rate case. As part of this proceeding, the Commission
                 will consider the process for determining the categories and
                 amounts of costs in the memorandum account that should be
                 considered reasonable for recovery, as well as the appropriate
                 methods for recovery.
              The utilities and parties will have an opportunity to comment on these
        interim practices and their efficacies, as well as sunset provisions if appropriate,
        while the parties continue to explore and dialogue about other solutions to assist
        customers to pay their utility bills and avoid disconnection of service. The


        1Each utility may implement a repayment plan schedule that exceeds twelve months,
        but we are not currently requiring any utility to extend the schedule beyond three
        months.




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         Commission recognizes that each utility has been implementing its own
         respective program on outreach and education to reduce the number of
         unnecessary disconnections; however, there has been no consistency or
         uniformity across all utilities. The Commission is initiating this Rulemaking to
         incorporate the productive and effective practices that each utility can share so
         that all gas and electric utilities have the benefit of implementing best practices in
         this area.

         2. Background
               On June 19, 2009, The Utility Reform Network (TURN) filed a Petition to
         initiate a rulemaking (Petition) to address arrearage management and shutoff
         prevention for residential customers. (Petition (P.) 09-06-022.) In response to
         TURN’s Petition, a proposed decision issued on September 25, 2009, which
         examined the existing low-income programs that are available to low-income
         customers, evaluated whether the utilities are performing outreach and
         education on the availability of the low-income programs, and considered
         whether any additional programs are necessary at this time. Upon initial
         examination, the proposed decision determined that existing programs and
         outreach were sufficient and that a rulemaking was not needed at this time.
               On November 19, 2009, the Division of Ratepayer Advocates (DRA), who
         strongly supported TURN’s Petition, released a report, “Status Report on Energy
         Utility Service Disconnections,” that discussed data regarding service
         disconnections and reconnections from January 2006 through August 2009.
         Based on the data contained in DRA’s Report, President Peevey announced that
         the Commission would hold an en banc on December 17, 2009.
               Commissioners Peevey, Grueneich, Bohn and Simon participated in the
         en banc and listened to presentations from DRA, TURN, Greenling Institute and


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         R.10-02-005 COM/CAB/tcg


         the four major utilities. From the en banc discussion, the Commission learned
         that the disconnection rate was rapidly rising for low-income households. In
         addition, the utilities reported that a very high percentage of customers who are
         disconnected are reconnected within 48 hours.
                  Following the en banc, all four utilities agreed to a moratorium on service
         disconnections beginning December 21 and extending through January 5.2 The
         reasoning behind the moratorium was to enable customers and the utilities to
         have time to contact one another about arrearage repayment without fear of a
         disconnection during the holiday/winter period.
                  The Commission then held a workshop on January 5, 2010 to afford the
         utilities and other stakeholders an opportunity to discuss “best-practices” for
         customer outreach and education so that customers can address repayment of
         arrearages before they are disconnected. The emphasis by the Commission was
         on having the utilities work within their communities to get the word out that
         customers having difficulty paying their utility bill should immediately contact
         their electric or gas company to discuss how to best repay the arrearage, prevent
         disconnection, and see whether there are ways to decrease the monthly bill
         through assistance programs or energy efficiency efforts.




         2   SCE voluntarily extended their moratorium through January 21, 2010.




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         R.10-02-005 COM/CAB/tcg


               The Commission had envisioned that through the en banc and workshop
         efforts that the utilities could individually, or jointly, develop innovations to
         their current bill collection practices that would assure the Commission that bill
         arrearages and disconnections were being thoroughly addressed by the utilities
         resulting in fewer residential disconnections. However, the Commission now
         believes it is appropriate to open a rulemaking to gather input from the utilities
         and consumer groups on ways to decrease the number of household
         disconnections while at the same time not shifting the burden of non-paying
         customers to other ratepayers.

         3. Implementation of New Practices
               Following the en banc and workshop, the Commission has carefully
         considered the exchange of information between the utilities and the consumer
         advocates and has determined that there are some interim practices the
         Commission can implement immediately that are aimed at addressing the
         Commission’s primary focus: having the utilities work with their customers to
         address bill arrearages before disconnection. While we recognize that
         disconnections for non-payment of utility bills will never be completely
         obliterated, we find that the following procedures are intended to offer
         immediate help for customers to address bill arrearages and avoid
         disconnections. Therefore, we direct PG&E, SCE, SDG&E and SoCalGas to
         immediately implement the following practices no later than five business days
         after the mailing of this order:
               1) All CSRs must inform any customer that owes an arrearage on a
                  utility bill that puts them at risk for disconnection that the customer
                  has a right to arrange a bill payment plan extending a minimum of




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         R.10-02-005 COM/CAB/tcg


                  three months in which to repay the arrearage. CSRs may exercise
                  discretion as to extending the three months up to twelve months3
                  depending on the particulars of a customer’s situation and ability to
                  repay the arrearage. CSRs may work with customers to develop a
                  shorter re-payment plan, as long as the customer is informed of the
                  three-month option. Customers must keep current on their utility
                  bills while repaying the arrearage balance.
               2) Once a customer has established credit as a customer of that utility,
                  the utility must not require that customer to pay additional
                  reestablishment of credit deposits with the utility for either
                  slow-payment/no-payment of bills or following a disconnection.
               3) Each utility is authorized to file a Tier 1 advice letter to open a
                  memorandum account to track any significant additional costs
                  associated with complying with the new practices initiated with this
                  rulemaking, including the operations and maintenance charges
                  associated with implementing the practices as well as any
                  uncollectables that are in excess of those projected in the utility’s last
                  general rate case. As part of this proceeding, the Commission will
                  consider the process for determining the categories and amounts of
                  costs in the memorandum account that should be considered
                  reasonable for recovery, as well as the appropriate methods for
                  recovery.

               We recognize two important principles: (1) utility service is a matter of
         health and safety and we do not have the luxury of time to flush out fully best
         practices in a long proceeding before we take any action to address the current
         disconnection rate; and (2) we do not have a complete record to fully and finally
         determine if the above practices are sufficient to help the Commission meet its
         goal of reducing disconnections whenever some other method of bill payment



         3Each utility may implement a repayment plan schedule that exceeds twelve months,
         but we are not currently requiring any utility to extend the schedule beyond three
         months.




                                                 -6-




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        R.10-02-005 COM/CAB/tcg


        can be arranged. Therefore, we direct the utilities and the consumer groups to
        continue their dialogue and efforts to determine what are the best practices, and
        to assess whether the interim practices we are establishing today are ones that
        will ultimately further our goals.
              To ensure that the Commission and parties can fully evaluate the efficacy
        of these interim practices, and to assist the Commission in determining whether
        to maintain, expand, or modify these practices, and whether or if to sunset them,
        we will require the utilities to submit monthly reports of specific disconnection-
        related data including the number of disconnections experienced by each utility.
        Appendix A contains the additional data to be submitted on a monthly basis by
        each respondent investor-owned utility.
              In addition, it has come to our attention through reports on utility-
        sponsored focus groups that an anomaly occurs in the billing/accounting
        departments of the utilities when a customer owes both for an arrearage and a
        current bill. For illustration purposes, assume a customer owes an arrearage of
        $150, is on a 3-month re-payment plan whereby the customer pays $50 towards
        the arrearage, and the customer has a current monthly bill of $100. If the
        customer makes a payment of $150, representing the $50 arrearage payment and
        the $100 current bill payment, how does the utility ensure that the proper monies
        are credited to the appropriate accounts? If all $150 is applied to the arrearage,
        the customer is delinquent on the current bill, whereas if all $150 is applied to the
        current bill the customer has a credit, but is in default on the arrearage re-
        payment arrangement. We request that the utilities propose a uniform
        billing/accounting methodology that ensures that the customer receives proper
        credit for monies paid.




                                                 -7-




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         R.10-02-005 COM/CAB/tcg


         4. Preliminary Scoping Memo
               As required by Rule 7.1(d) of our Rules of Practice and Procedure (Rules),
         this order includes a preliminary scoping memo as set forth below. Unless a
         further Scoping Memo is deemed appropriate by the assigned Administrative
         Law Judge (ALJ) or the assigned Commissioner, the Preliminary Scope will be
         addressed in the first decision in this proceeding. As previously stated, the focus
         of this proceeding is to reduce the number of gas and electric utility service
         disconnections due to nonpayment by improving customer notification and
         education, including ways to help customers avoid disconnections while
         working with the utilities to pay arrearages and keep current on bills.
               In addition to the practices we are implementing with the issuance of this
         Rulemaking, we also ask parties to consider the following issues as part of the
         scope of the proceeding and inform the Commission of your comments on
         whether to adopt any of the following practices:
               • Best practices for contacting customers who are delinquent in
                 their bill payments, including methods such as bill inserts,
                 special colored-bills, individualized messages on a bill,
                 separate mailings, dropped-off notices, telephone calls
                 [including whether live-voice or recorded messages], e-mails,
                 text-messaging, third-party notification, etc.;
               • Language options and how a utility would know what
                 language would be appropriate for a particular household;
               • Outreach and education about customer assistance programs,
                 energy efficiency programs, bill management options,
                 balanced payment plans, etc.;
               • How customers are “targeted” for outreach and education
                 information, and whether the customer should be required to
                 initiate the first contact;




                                                 -8-




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            R.10-02-005 COM/CAB/tcg


                 • Whether CSRs should have “scripts” or be left to their own
                   discretion in how they communicate with each individual
                   customer;
                 • How should the utilities tailor their automated call and written
                   notices concerning disconnection so that customers who use
                   telephone relay services and sight-impaired customers are
                   receiving the notices;
                 • Should a utility charge a customer for a remote connection or
                   disconnection;
                 • Whether the reporting requirements included in this
                   rulemaking are sufficient or should they be eliminated or
                   expanded;
                 • Whether the Commission should set a benchmark for the
                   number of disconnections experienced and what such a
                   benchmark should be;
                 • If the utilities are not to collect post-service initiation deposits,
                   are there other ways for the utilities to reduce future revenue
                   losses from uncollectibles, such as financial institution
                   guarantees;
                 • How does a utility distinguish between a payment extension
                   and a payment installment plan and how is the difference
                   communicated to the customer;
                 • If a customer requests a monthly billing date that is different
                   from the date assigned by the utility, does the utility
                   accommodate this request, and if so, how is the customer
                   notified;
                 • How can the utilities strive to maintain the direct
                   communication and personal contact that customers associate
                   with in-person disconnection visits, when the utilities return
                   to remote disconnections;
                 • How can all utilities incorporate best practices, such as those
                   employed by SDG&E and SoCalGas, to work with community-
                   based-organizations (CBO) and faith-based organizations to
                   educated customers on the California Alternate Rates for
                   Energy (CARE) and other assistance programs; and


                                                    -9-




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         R.10-02-005 COM/CAB/tcg


               • Should the utilities utilize more data-sharing programs along
                 the lines used by SDG&E to partner with school districts and
                 use the program data as a screen to enroll additional families
                 in the CARE program, while protecting privacy issues.

         5. Emergency Fund
               Our regulated energy utilities have a unique opportunity to leverage
         available funds under the federal government’s American Recovery and
         Reinvestment Act (ARRA) to provide critical payment assistance to eligible
         low-income customers. Under ARRA, funds were appropriated for the
         Temporary Assistance to Needy Families (TANF) Emergency Contingency Fund
         (Emergency Fund) over fiscal years 2009 and 2010. This Emergency Fund is in
         addition to the regular TANF Contingency Fund that needy families in
         California can access through established agencies during the economic
         downturn. Through this provision of ARRA, every one dollar of local
         contributions will be matched with four dollars from the Emergency Fund.
         Through this one time program that will expire on September 30, 2010, eligible
         low-income customers who have experienced an uncontrollable or unforeseen
         hardship may receive an energy credit on their utility bill.
               To take advantage of this unique and fleeting opportunity, we direct
         respondent investor-owned utilities (IOUs) to file Tier 3 advice letters within
         30 days of the effective date of this order outlining their proposed program to
         take advantage of the Emergency Fund. We envision that respondent IOUs will
         continue to use their shareholder and employee funded charitable contribution
         for this purpose, but may also present a proposal to transfer some funds
         collected in the CARE balancing account for this effort to leverage as much
         available ARRA funds as possible. We also expect that IOUs will keep
         administrative costs to a minimum in order to provide the greatest benefit to


                                                - 10 -




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Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                C. Bill Delivery
Workpaper:               VARIOUS

Summary for Category: C. Bill Delivery

                                                             In 2009$ (000)
                                 Adjusted-Recorded                        Adjusted-Forecast
                                    2009                   2010               2011            2012
             Labor                          0                     0                   0                0
             Non-Labor                    930                890                  890                890
             NSE                         5,561              5,564               5,590            5,656
               Total                     6,491              6,454               6,480            6,546
               FTE                         0.0                0.0                    0.0             0.0

   Workpapers belonging to this Category:
    1OO003.000 BILL DELIVERY
         Labor                           0                       0                  0                   0
         Non-Labor                    930                     890                890                 890
         NSE                             0                       0                  0                   0
            Total                     930                     890                890                 890
            FTE                        0.0                     0.0                0.0                 0.0
     1OO003.001 BILL DELIVERY - POSTAGE
         Labor                         0                         0                  0                 0
         Non-Labor                     0                         0                  0                 0
         NSE                      5,561                     5,564              5,590             5,656
            Total                 5,561                     5,564              5,590             5,656
            FTE                      0.0                       0.0                0.0               0.0




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 236 of 375
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                  Beginning of Workpaper
                1OO003.000 - BILL DELIVERY




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                        Pages 237 of 375
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Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                C. Bill Delivery
Category-Sub             1. CS Operations-Remittance Processing
Workpaper:               1OO003.000 - BILL DELIVERY

Activity Description:
               This Data Distribution workgroup houses paper and envelope expenses.

Forecast Methodology:

        Labor - 5-YR Average
               Volumes in Data Distribution are driven by fluctuations in paper and envelopes. For these
               reasons it is logical to project the base future expense by using a five year historical average to
               encompass fluctuations in volumes over a reasonable timeframe.
        Non-Labor - 5-YR Average
              Volumes in Data Distribution are driven by fluctuations in paper and envelopes. For these
              reasons it is logical to project the base future expense by using a five year historical average to
              encompass fluctuations in volumes over a reasonable timeframe.
        NSE - 5-YR Average
               N/A


Summary of Results:

                                                                  In 2009$ (000)
                                         Adjusted-Recorded                                      Adjusted-Forecast
Years                     2005         2006        2007         2008        2009            2010        2011         2012
Labor                        0            0           0            0           0               0           0          0
Non-Labor                  916          861         872          871         930             890          890        890
NSE                           0            0           0            0           0               0            0        0
   Total                   916          861         872          871         930             890          890        890
   FTE                      0.0          0.0         0.0          0.0         0.0             0.0          0.0       0.0




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Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 C. Bill Delivery
Category-Sub:             1. CS Operations-Remittance Processing
Workpaper:                1OO003.000 - BILL DELIVERY

Forecast Summary:
                                                                      In 2009 $(000)
     Forecast Method                     Base Forecast                  Forecast Adjustments         Adjusted-Forecast
                                       2010        2011     2012       2010       2011    2012       2010    2011        2012
 Labor              5-YR Average         0             0         0            0     0          0       0         0         0
 Non-Labor          5-YR Average       890           890     890              0     0          0     890      890        890
 NSE                5-YR Average         0             0         0            0     0          0       0         0         0
 Total                                 890           890     890              0     0          0     890      890        890
 FTE                5-YR Average        0.0          0.0        0.0      0.0       0.0      0.0       0.0      0.0        0.0


Forecast Adjustment Details:
       Year/Expl.           Labor             NLbr         NSE        Total        FTE    Adj_Type

         2010 Total                0           0            0            0          0.0




         2011 Total                0           0            0            0          0.0




         2012 Total                0           0            0            0          0.0




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 239 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               C. Bill Delivery
Category-Sub:           1. CS Operations-Remittance Processing
Workpaper:              1OO003.000 - BILL DELIVERY

Determination of Adjusted-Recorded:
                                2005 ($000)              2006 ($000)         2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                                    0                    0                  0              0            0
     Non-Labor                             708                  696                821            872          930
     NSE                                      0                    0                  0              0            0
         Total                             708                  696                821            872          930
         FTE                                0.0                  0.0                0.0            0.0          0.0
  Adjustments (Nominal $) **
     Labor                                   0                     0                 0              0            0
     Non-Labor                              85                    85                 0              0            0
     NSE                                     0                     0                 0              0            0
         Total                              85                    85                 0              0            0
         FTE                               0.0                   0.0               0.0            0.0          0.0
  Recorded-Adjusted (Nominal $)
     Labor                                    0                    0                  0              0            0
     Non-Labor                             793                  781                821            872          930
     NSE                                      0                    0                  0              0            0
          Total                            793                  781                821            872          930
          FTE                               0.0                  0.0                0.0            0.0          0.0
  Vacation & Sick (Nominal $)
     Labor                                   0                     0                 0              0            0
     Non-Labor                               0                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
          Total                              0                     0                 0              0            0
          FTE                              0.0                   0.0               0.0            0.0          0.0
  Escalation to 2009$
     Labor                                    0                    0                 0              0            0
     Non-Labor                             123                    79                50             -1            0
     NSE                                      0                    0                 0              0            0
         Total                             123                    79                50             -1            0
         FTE                                0.0                  0.0               0.0            0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                                    0                    0                  0              0            0
     Non-Labor                             916                  861                872            871          930
     NSE                                      0                    0                  0              0            0
         Total                             916                  861                872            871          930
         FTE                                0.0                  0.0                0.0            0.0          0.0



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 240 of 375
                                              San Diego Gas & Electric Company
                                                 Test Year 2012 GRC - APP
                                               Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                C. Bill Delivery
Category-Sub:            1. CS Operations-Remittance Processing
Workpaper:               1OO003.000 - BILL DELIVERY


Summary of Adjustments to Recorded:

                                                                    In Nominal $ (000)
 Year                                     2005                  2006              2007           2008                2009
    Labor                                    0                     0                0                  0                0
    Non-Labor                               85                    85                0                  0                0
    NSE                                      0                     0                0                  0                0
        Total                               85                    85                0                  0                0
    FTE                                    0.0                   0.0               0.0                0.0             0.0


Detail of Adjustments to Recorded:

Year/Expl.       Labor         NLbr        NSE         FTE         Adj_Type      From CCtr                  RefID

2005                   0            85           0        0.0 CCTR Transf        From 2100-0026.000           SDALEY2009091
                                                                                                                 4135321620
   To align historical to forecast for software license

2005 Total             0            85           0        0.0



2006                   0            85           0        0.0 CCTR Transf        From 2100-0026.000           SDALEY2009091
                                                                                                                 4143930690
   To align historical to forecast for software license.

2006 Total             0            85           0        0.0



2007 Total             0              0          0        0.0



2008 Total             0              0          0        0.0



2009 Total             0              0          0        0.0




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 241 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                   Non-Shared Service Workpapers




                 Beginning of Workpaper
          1OO003.001 - BILL DELIVERY - POSTAGE




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 242 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                              Non-Shared Service Workpapers


Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               C. Bill Delivery
Category-Sub            2. CS Operations-Remittance Processing Postage
Workpaper:              1OO003.001 - BILL DELIVERY - POSTAGE

Activity Description:
               San Diego Bill Postage.

Forecast Methodology:

        Labor - Base YR Rec
               N/A

        Non-Labor - Base YR Rec
              N/A

        NSE - Base YR Rec
               Keeping up with the dynamics of the mailing environment, a responsive starting point would be
               Base Year 2009

Summary of Results:

                                                                In 2009$ (000)
                                         Adjusted-Recorded                                  Adjusted-Forecast
Years                    2005        2006        2007        2008        2009          2010        2011        2012
Labor                       0           0           0           0           0             0           0         0
Non-Labor                    0           0           0            0          0              0          0         0
NSE                     5,489       5,153       5,293        5,044      5,561          5,564      5,590        5,656
   Total                5,489       5,153       5,293        5,044      5,561          5,564      5,590        5,656
   FTE                     0.0         0.0         0.0          0.0        0.0            0.0        0.0        0.0




                    SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                            Pages 243 of 375
                                                  San Diego Gas & Electric Company
                                                     Test Year 2012 GRC - APP
                                                   Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                C. Bill Delivery
Category-Sub:            2. CS Operations-Remittance Processing Postage
Workpaper:               1OO003.001 - BILL DELIVERY - POSTAGE

Forecast Summary:
                                                                           In 2009 $(000)
     Forecast Method                       Base Forecast                     Forecast Adjustments             Adjusted-Forecast
                                       2010           2011       2012       2010       2011    2012          2010     2011        2012
 Labor              Base YR Rec            0             0            0            0     0          0           0         0         0
 Non-Labor          Base YR Rec            0             0            0            0     0          0           0         0         0
 NSE                Base YR Rec       5,561           5,561     5,561              3    29        95         5,564    5,590   5,656
 Total                                5,561           5,561     5,561              3    29        95         5,564    5,590   5,656
 FTE                Base YR Rec          0.0            0.0          0.0      0.0       0.0      0.0           0.0      0.0        0.0


Forecast Adjustment Details:
       Year/Expl.            Labor             NLbr            NSE         Total        FTE    Adj_Type

         2010                     0               0           149           149          0.0   1-Sided Adj

            Increase due to meter growth.

         2010                     0               0           -146         -146          0.0   1-Sided Adj

            Savings due to electronic billings.

         2010 Total               0               0             3             3          0.0




         2011                     0               0           239           239          0.0   1-Sided Adj

            Increase due to meter growth.

         2011                     0               0           -210         -210          0.0   1-Sided Adj

            Savings due to electronic billings.

         2011 Total               0               0            29            29          0.0




         2012                     0               0           353           353          0.0   1-Sided Adj

            Increase due to meter growth.

         2012                     0               0           -258         -258          0.0   1-Sided Adj

            Savings due to electronic billings.




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 244 of 375
                                        San Diego Gas & Electric Company
                                           Test Year 2012 GRC - APP
                                         Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             C. Bill Delivery
Category-Sub:         2. CS Operations-Remittance Processing Postage
Workpaper:            1OO003.001 - BILL DELIVERY - POSTAGE

      Year/Expl.        Labor         NLbr      NSE        Total       FTE   Adj Type

      2012 Total             0           0         95           95       0.0




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 245 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               C. Bill Delivery
Category-Sub:           2. CS Operations-Remittance Processing Postage
Workpaper:              1OO003.001 - BILL DELIVERY - POSTAGE

Determination of Adjusted-Recorded:
                                2005 ($000)              2006 ($000)         2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                                    0                    0                  0              0            0
     Non-Labor                           4,753                4,678              4,987          5,049        5,561
     NSE                                      0                    0                  0              0            0
         Total                           4,753                4,678              4,987          5,049        5,561
         FTE                                0.0                  0.0                0.0            0.0          0.0
  Adjustments (Nominal $) **
     Labor                                    0                     0                  0             0            0
     Non-Labor                          -4,753                -4,678             -4,987        -5,049       -5,561
     NSE                                 4,753                 4,678              4,987         5,049        5,561
         Total                                0                     0                  0             0            0
         FTE                                0.0                   0.0                0.0           0.0          0.0
  Recorded-Adjusted (Nominal $)
     Labor                                    0                    0                  0              0            0
     Non-Labor                                0                    0                  0              0            0
     NSE                                 4,753                4,678              4,987          5,049        5,561
          Total                          4,753                4,678              4,987          5,049        5,561
          FTE                               0.0                  0.0                0.0            0.0          0.0
  Vacation & Sick (Nominal $)
     Labor                                   0                     0                  0             0            0
     Non-Labor                               0                     0                  0             0            0
     NSE                                     0                     0                  0             0            0
          Total                              0                     0                  0             0            0
          FTE                              0.0                   0.0                0.0           0.0          0.0
  Escalation to 2009$
     Labor                                    0                    0                  0             0            0
     Non-Labor                                0                    0                  0             0            0
     NSE                                   735                  474                306             -5            0
         Total                             735                  474                306             -5            0
         FTE                                0.0                  0.0                0.0           0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                                    0                    0                  0              0            0
     Non-Labor                                0                    0                  0              0            0
     NSE                                 5,489                5,153              5,293          5,044        5,561
         Total                           5,489                5,153              5,293          5,044        5,561
         FTE                                0.0                  0.0                0.0            0.0          0.0



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 246 of 375
                                              San Diego Gas & Electric Company
                                                 Test Year 2012 GRC - APP
                                               Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               C. Bill Delivery
Category-Sub:           2. CS Operations-Remittance Processing Postage
Workpaper:              1OO003.001 - BILL DELIVERY - POSTAGE


Summary of Adjustments to Recorded:

                                                                In Nominal $ (000)
 Year                                     2005              2006              2007        2008             2009
    Labor                                    0                 0                   0         0                0
    Non-Labor                            -4,753         -4,678              -4,987       -5,049           -5,561
    NSE                                  4,753              4,678           4,987        5,049            5,561
        Total                                0                 0                   0         0                0
    FTE                                     0.0               0.0              0.0          0.0              0.0


Detail of Adjustments to Recorded:

Year/Expl.      Labor         NLbr          NSE       FTE      Adj_Type      From CCtr            RefID

2005                  0       -4,753              0   0.0 NSE Transfer       N/A                    SDALEY2010042
                                                                                                       6095452150
   Aligning history to forecasting postage with non standard escalation.

2005                  0              0      4,753     0.0 NSE Transfer       N/A                    SDALEY2010042
                                                                                                       6095452150
   Aligning history to forecasting postage with non standard escalation.

2005 Total            0       -4,753        4,753     0.0



2006                  0       -4,678              0   0.0 NSE Transfer       N/A                    SDALEY2010042
                                                                                                       6095605993
   Aligning history to forecasting postage with non standard escalation.

2006                  0              0      4,678     0.0 NSE Transfer       N/A                    SDALEY2010042
                                                                                                       6095605993
   Aligning history to forecasting postage with non standard escalation.

2006 Total            0       -4,678        4,678     0.0



2007                  0       -4,987              0   0.0 NSE Transfer       N/A                    SDALEY2010042
                                                                                                       6095703103
   Aligning history to forecasting postage with non standard escalation.

2007                  0              0      4,987     0.0 NSE Transfer       N/A                    SDALEY2010042
                                                                                                       6095703103
   Aligning history to forecasting postage with non standard escalation.

2007 Total            0       -4,987        4,987     0.0




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 247 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                              Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                C. Bill Delivery
Category-Sub:            2. CS Operations-Remittance Processing Postage
Workpaper:               1OO003.001 - BILL DELIVERY - POSTAGE


Year/Expl.       Labor         NLbr         NSE       FTE      Adj Type           From CCtr    RefID

2008                   0       -5,049          0     0.0 NSE Transfer       N/A               SDALEY2010042
                                                                                                 6095754243
    Aligning history to forecasting postage with non standard escalation.

2008                   0            0     5,049      0.0 NSE Transfer       N/A               SDALEY2010042
                                                                                                 6095754243
    Aligning history to forecasting postage with non standard escalation.

2008 Total             0       -5,049      5,049     0.0



2009                   0       -5,561          0     0.0 NSE Transfer       N/A               SDALEY2010042
                                                                                                 6095818480
    Aligning history to forecasting postage with non standard escalation.

2009                   0            0     5,561      0.0 NSE Transfer       N/A               SDALEY2010042
                                                                                                 6095818480
    Aligning history to forecasting postage with non standard escalation.

2009 Total             0       -5,561      5,561     0.0




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 248 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                   Non-Shared Service Workpapers




     Supplemental Workpapers for Workpaper 1OO003.001




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 249 of 375
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO003.001_Supp1.pdf




                                                                                                                                                              SDG&E Postage Calculation



                                                                                                                                2009          2010          2011          2012                       2009    2010     2011     2012
                                                                                           ► MPK
                                                                                                         Volume              16,303,608    16,469,825    16,712,982    17,027,484
                                                                                                         Postage             $5,541,654    $5,645,304    $5,728,650    $5,836,451                           $5,645   $5,729   $5,836
                                                                                                         Avg. Rate             $0.340        $0.343        $0.343        $0.343

                                                                                             Increment
                                                                                                         Volume                            166,217        243,157      314,502
                                                                                                         Postage                           $103,650       $83,346      $107,801           $294,797          $104      $83     $108
                                                                                                         Avg. Rate                          $0.003         $0.000       $0.000




                                                                                                                                                                                                                                       San Diego Gas & Electric Company
                                                                                                                                                                                                                                        Non-Shared Service Workpapers
                                                                                           ► XEROX
                                                                                                         Form Bills           417,088       481,329       485,326       489,847




                                                                                                                                                                                                                                          Test Year 2012 GRC - APP
                                                                                                         Postage              276,440       322,208       328,133       334,501                             $322     $328     $335
                                                                                                         Avg. Rate            $0.663        $0.669         $0.676        $0.683
                                  Pages 250 of 375




                                                                                             Increment
                                                                                                         Form Bills                          64,241        3,997        4,521
                                                                                                         Postage                            $45,768       $5,925        $6,368             $58,061           $46      $6       $6
                                                                                                         Avg. Rate                          $0.007        $0.007        $0.007
                                                                                                                                                                                          $352,858

                                                                                           ► Savings
                                                                                             1●          Suppressed Bills      3,230,483     3,573,252     3,737,052     3,865,452
                                                                                                         Postage              $1,069,478    $1,197,039    $1,251,912    $1,294,926                          $1,197   $1,252   $1,295
                                                                                                         Avg. Rate             $0.331       $0.335         $0.335        $0.335

                                                                                             Increment
                                                                                                         Volume                            342,769        163,800       128,400
                                                                                                         Postage                           $127,561       $54,873       $43,014           $225,448          $128      $55      $43
                                                                                                         Avg. Rate                          $0.004         $0.000        $0.000


                                                                                             2●          ChkFree's e-Bills      506,459       624,122       688,374       722,224
                                                                                                         Postage                $69,727       $88,034       $97,097      $101,872                            $88      $97     $102
                                                                                                         Avg. Rate            $0.138        $0.141        $0.141        $0.141

                                                                                             Increment
                                                                                                         Volume                             117,663       64,252        33,850
                                                                                                         Postage                            $18,307       $9,063        $4,775             $32,145           $18      $9       $5
                                                                                                         Avg. Rate                          $0.003        $0.000        $0.000
                                                                                                                                                                                          $257,593
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO003.001_Supp1.pdf




                                                                                                                       2009          2010        2011         2012                                   2009     2010     2011     2012
                                                                                           ► Net
                                                                                                         Form Bills   12,983,754   12,753,780   12,772,883   12,929,655
                                                                                                         Postage      $4,678,888   $4,682,438   $4,707,773   $4,774,154                             $4,679   $4,682   $4,708   $4,774
                                                                                                         Avg. Rate     $0.360      $0.367        $0.369       $0.369

                                                                                             Increment
                                                                                                         Form Bills                (229,974)    19,103       156,773
                                                                                                         Postage                    $3,550      $25,335      $66,380                  $95,265                 $4       $25      $66
                                                                                                         Avg. Rate                  $0.007       $0.001       $0.001



                                                                                                                                                                                 Net/1000       ►   $4,682   $4,678   $4,708   $4,774




                                                                                                                                                                                                                                        San Diego Gas & Electric Company
                                                                                                                                                               Y-E 2009 - SAP Includes Prefunds ►   $5,561




                                                                                                                                                                                                                                         Non-Shared Service Workpapers
                                                                                                                                                                                                                                           Test Year 2012 GRC - APP
                                                                                                                                                                            Estimated Prefunds ►      $882   $882     $882     $882

                                                                                                                                                                                     Net/1000 ►              $5,561   $5,590   $5,656
                                  Pages 251 of 375
                                               San Diego Gas & Electric Company
                                                  Test Year 2012 GRC - APP
                                                Non-Shared Service Workpapers




           FOR IMMEDIATE RELEASE                                                                          Media Contact: Joanne Veto
           July 6, 2010                                                                                            (O) 202-268-3118
                                                                                                                   (C) 301-325-1960
                                                                                                            joanne.m.veto@usps.gov

                                                                                                                       usps.com/news
                                                                                                                   Release No. 10-063

                                              Incentives Included in Price Filing
                                About 90 Percent of Proposed Price Changes Under 6 Percent
           WASHINGTON — Volume discounts and free additional weight are included in the proposed price changes the U.S.
           Postal Service filed with the Postal Regulatory Commission (PRC) today.

           Price changes for the majority of products and services fall between 4 percent and 6 percent. These products and
           services account for about 90 percent of Market Dominant revenue. The Postal Service Governors approved the
           recommendation for prices for all 18 Market Dominant products.

           Products outside the range include Periodicals (8 percent), Standard Mail Parcels (23 percent) and Media/Library Mail (7
           percent). The increases above the average are intended to improve the financial performance of products that currently
           do not cover costs while limiting the impact on customers.

           The filing includes two incentives designed to retain and grow profitable mail volume: “Reply Rides Free” and “Saturation
           Mail/High Density Incentive Program.”

           Reply Rides Free encourages the use of bill and statement mailings for marketing messages. For qualifying customers, a
           1.2-ounce piece is charged the 1-ounce price if a reply envelope or card is included in the mailing.

           The Saturation Mail/High Density Incentive Program provides rebates for volume growth for Standard Mail and Nonprofit
           Mail letters and flats. A minimum of six Saturation/High Density mailings in a Fiscal Year is required.

           If approved as proposed, the new prices would take effect on Jan. 2, 2011 – almost two years since the Postal Service
           last raised rates.

           The proposed price changes would generate $2.3 billion for the last three quarters of the 2011 Fiscal Year (January to
           September) and an estimated $3 billion for the full 12 months of Fiscal Year 2012.

           Despite eliminating millions of work hours and reducing expenses by more than $1 billion every year since 2001, a budget
           gap remains. The proposed price increases will help close a $7 billion projected shortfall in FY 2011. The Postal Service
           would have needed to raise rates an average of 20 percent across all product lines to completely close that expected
           gap.

           “This proposal is moderate and reasonable and carefully evaluated for its effect on our customers,” said Maura
           Robinson, vice president, Pricing. “Increasing prices will help overcome some of the financial challenges faced by the
           Postal Service. We will continue to work with Congress and other stakeholders to implement long-term solutions.”

           Postmaster General John E. Potter identified in March a number of actions the Postal Service will pursue, including a
           change to delivery frequency, expanded access to products and services more convenient to customers and
           restructuring prepayment of retiree health benefits. Potter was clear at the time that customers would not be asked to
           close the entire budget gap.

           Innovations like Reply Rides Free and Saturation Mail incentive programs reinforce the value of mail, help retain volume
           and provide opportunities to grow the business. These products also have proven to cover their costs and contribute
           much needed revenue to the Postal Service. Still, greater product and pricing flexibility is needed if the Postal Service is
           to remain a vital driver of the American economy.

           “Future price increases can be greatly alleviated if the Postal Service is given the tools necessary to be a more flexible,



  1 of 2




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO003.001_Supp2.pdf
                                  Pages 252 of 375
                                                       San Diego Gas & Electric Company
                                                          Test Year 2012 GRC - APP
                                                        Non-Shared Service Workpapers




           market-oriented company,” Robinson said.

           Other highlights from the price filing include:

                   First-Class Mail stamps would increase to 46 cents. A new Forever Stamp image will be available in October.
                   First-Class Mail postcard prices would increase 2 cents to 30 cents.
                   Periodicals would receive an 8 percent increase.
                   Recommended increase for catalogs is 5.1 percent.
                   Standard Mail parcels would increase about 23 percent.

           This is the first time the Postal Service is requesting price increases above the rate of inflation, an action that is allowed
           under the 2006 Postal law as long as the Postal Service can demonstrate “exceptional or extraordinary circumstance.”

           An ongoing recession that has rocked the Postal Service business customer base, continued movement toward
           electronic alternatives and unprecedented volume loss have created a situation where the price cap of 0.6 percent,
           based on the Consumer Price Index, is insufficient to cover the extraordinary losses.

           The PRC has 90 days to review and make a final ruling on the filing (on or about Oct. 4). The PRC can accept or reject
           all price requests.

           The Postal Service receives no tax dollars for operating expenses, and relies on the sale of postage, products and
           services to fund its operations.

           More detailed information on the price filing is available at usps.com.

                                                                                     ###
           Please Note: For broadcast quality video and audio, photo stills and other media resources, visit the USPS Newsroom at
           www.usps.com/communications/newsroom/welcome.htm.

           A self-supporting government enterprise, the U.S. Postal Service is the only delivery service that reaches every address in the nation, 150 million
           residences, businesses and Post Office Boxes. The Postal Service receives no direct support from taxpayers. With 36,000 retail locations and the most
           frequently visited website in the federal government, the Postal Service relies on the sale of postage, products and services to pay for operating expenses.
           Named the Most Trusted Government Agency five consecutive years and the sixth Most Trusted Business in the nation by the Ponemon Institute, the Postal
           Service has annual revenue of more than $68 billion and delivers nearly half the world’s mail. If it were a private sector company, the U.S. Postal Service
           would rank 28th in the 2009 Fortune 500.




  2 of 2




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO003.001_Supp2.pdf
                                  Pages 253 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                D. CS Technology Support
Workpaper:               1OO004.000

Summary for Category: D. CS Technology Support

                                                              In 2009$ (000)
                                  Adjusted-Recorded                        Adjusted-Forecast
                                     2009                   2010               2011            2012
             Labor                       450                  530                  690                690
             Non-Labor                   621                  164                  358                358
             NSE                             0                     0                   0                0
               Total                   1,071                  694                1,048            1,048
               FTE                          6.1                7.0                    9.0             9.0

   Workpapers belonging to this Category:
    1OO004.000 CS TECHNOLOGY SUPPORT
         Labor                         450                     530                690               690
         Non-Labor                     621                     164                358               358
         NSE                              0                       0                  0                 0
            Total                    1,071                     694              1,048             1,048
            FTE                         6.1                     7.0                9.0               9.0




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 254 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                   Non-Shared Service Workpapers




                Beginning of Workpaper
         1OO004.000 - CS TECHNOLOGY SUPPORT




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 255 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                              Non-Shared Service Workpapers


Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               D. CS Technology Support
Category-Sub            1. CS Operations-Customer Service Technology Support
Workpaper:              1OO004.000 - CS TECHNOLOGY SUPPORT

Activity Description:
               The STS-Field Systems SDG&E Team Supports the suite of SORT applications used by
               various functional areas to route and complete Customer and Company generated work
               orders. The Team staffs a help desk during regular business hours to resolve software and
               hardware issues that impact Customer Service Field safety, efficiency, and Customer
               satisfaction.
Forecast Methodology:

        Labor - 5-YR Average
               Year to year o&m expenses in Customer Services Systems & Technology can vary, up or
               down, due to charging capital & refundable programs and changes in staff. Utilizing a 5-year
               average neutralizes any fluctuations in expenses that occur in an exceptional year or years.
        Non-Labor - 5-YR Average
              Year to year o&m expenses in Customer Services Systems & Technology can vary, up or
              down, due to charging capital & refundable programs and changes in staff. Utilizing a 5-year
              average neutralizes any fluctuations in expenses that occur in an exceptional year or years.
        NSE - 5-YR Average
               N/A


Summary of Results:

                                                                In 2009$ (000)
                                        Adjusted-Recorded                                   Adjusted-Forecast
Years                    2005        2006        2007        2008        2009           2010        2011      2012
Labor                     373         415         331         245         450            530         690      690
Non-Labor                 248         290         274         361         621            164         358       358
NSE                          0           0           0           0           0              0           0       0
   Total                  621         705         605         606       1,071            694       1,048      1,048
   FTE                     5.2         5.5         4.8         4.1         6.1            7.0         9.0      9.0




                    SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                            Pages 256 of 375
                                                San Diego Gas & Electric Company
                                                   Test Year 2012 GRC - APP
                                                 Non-Shared Service Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 D. CS Technology Support
Category-Sub:             1. CS Operations-Customer Service Technology Support
Workpaper:                1OO004.000 - CS TECHNOLOGY SUPPORT

Forecast Summary:
                                                                       In 2009 $(000)
     Forecast Method                      Base Forecast                  Forecast Adjustments                Adjusted-Forecast
                                       2010          2011    2012       2010       2011      2012            2010    2011        2012
 Labor              5-YR Average        362          362         362     168       328        328            530      690        690
 Non-Labor          5-YR Average        358          358         358    -194          0          0           164      358        358
 NSE                5-YR Average          0            0           0           0      0          0             0         0         0
 Total                                  720          720         720      -26      328        328            694     1,048   1,048
 FTE                5-YR Average        5.1           5.1        5.1      1.9       3.9        3.9            7.0      9.0        9.0


Forecast Adjustment Details:
       Year/Expl.           Labor             NLbr          NSE        Total         FTE    Adj_Type

         2010                  168              0            0          168           0.0   1-Sided Adj

            Full Year adjustment to reflect actual current staffing levels and rates and related expenses.

         2010                      0            0            0            0           1.9   1-Sided Adj

            Full Year adjustment to reflect actual current staffing levels and rates and related expenses.

         2010                      0          -194           0         -194           0.0   1-Sided Adj

            Computer equipment, cell phones, new software leases and 2010 s/w lease paid in 2011.

         2010 Total            168            -194           0          -26           1.9




         2011                  160              0            0          160           0.0   1-Sided Adj

            Add 1 Business Systems Analyst and 1 Technical Advisor in 2011 to support increased O&M
            reporting functions and support of full implementation of major projects including Gridcom
            and Hard Drive Encryption.

         2011                      0            0            0            0           2.0   1-Sided Adj

            Add 1 Business Systems Analyst and 1 Technical Advisor in 2011 to support increased O&M
            reporting functions and support of full implementation of major projects including Gridcom
            and Hard Drive Encryption.

         2011                  168              0            0          168           0.0   1-Sided Adj

            Full Year adjustment to reflect actual current staffing levels and rates and related expenses.




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 257 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                            Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             D. CS Technology Support
Category-Sub:         1. CS Operations-Customer Service Technology Support
Workpaper:            1OO004.000 - CS TECHNOLOGY SUPPORT

      Year/Expl.        Labor           NLbr        NSE          Total         FTE    Adj Type

      2011                    0             0             0              0         1.9   1-Sided Adj

         Full Year adjustment to reflect actual current staffing levels and rates and related expenses.

      2011 Total            328             0             0         328            3.9




      2012                  160             0             0         160            0.0   1-Sided Adj

         Add 1 Business Systems Analyst and 1 Technical Advisor in 2011 to support increased O&M
         reporting functions and support of full implementation of major projects including Gridcom
         and Hard Drive Encryption.

      2012                    0             0             0              0         2.0   1-Sided Adj

         Add 1 Business Systems Analyst and 1 Technical Advisor in 2011 to support increased O&M
         reporting functions and support of full implementation of major projects including Gridcom
         and Hard Drive Encryption.

      2012                  168             0             0         168            0.0   1-Sided Adj

         Full Year adjustment to reflect actual current staffing levels and rates and related expenses.

      2012                    0             0             0              0         1.9   1-Sided Adj

         Full Year adjustment to reflect actual current staffing levels and rates and related expenses.

      2012 Total            328             0             0         328            3.9




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 258 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               D. CS Technology Support
Category-Sub:           1. CS Operations-Customer Service Technology Support
Workpaper:              1OO004.000 - CS TECHNOLOGY SUPPORT

Determination of Adjusted-Recorded:
                                2005 ($000)              2006 ($000)         2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                                   0                  241                271            205          390
     Non-Labor                               0                  164                258            362          621
     NSE                                     0                     0                  0              0            0
         Total                               0                  406                530            566        1,011
         FTE                               0.0                   3.6                4.1            3.5          5.2
  Adjustments (Nominal $) **
     Labor                                 291                    88                 0              0            0
     Non-Labor                             214                    99                 0              0            0
     NSE                                      0                    0                 0              0            0
         Total                             505                  187                  0              0            0
         FTE                                4.5                  1.1               0.0            0.0          0.0
  Recorded-Adjusted (Nominal $)
     Labor                                 291                  329                271            205          390
     Non-Labor                             214                  263                258            362          621
     NSE                                      0                    0                  0              0            0
          Total                            505                  592                530            566        1,011
          FTE                               4.5                  4.7                4.1            3.5          5.2
  Vacation & Sick (Nominal $)
     Labor                                  42                    53                41             34           60
     Non-Labor                               0                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
          Total                             42                    53                41             34           60
          FTE                              0.7                   0.8               0.7            0.6          0.9
  Escalation to 2009$
     Labor                                  40                    34                19              6            0
     Non-Labor                              33                    27                16              0            0
     NSE                                     0                     0                 0              0            0
         Total                              73                    60                35              6            0
         FTE                               0.0                   0.0               0.0            0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                                 373                  415                331            245          450
     Non-Labor                             248                  290                274            361          621
     NSE                                      0                    0                  0              0            0
         Total                             620                  705                605            606        1,071
         FTE                                5.2                  5.5                4.8            4.1          6.1



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 259 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               D. CS Technology Support
Category-Sub:           1. CS Operations-Customer Service Technology Support
Workpaper:              1OO004.000 - CS TECHNOLOGY SUPPORT


Summary of Adjustments to Recorded:

                                                              In Nominal $ (000)
 Year                                    2005             2006              2007               2008             2009
    Labor                                291                88                  0                 0                0
    Non-Labor                            214                99                  0                 0                0
    NSE                                    0                 0                  0                 0                0
        Total                            505               187                  0                 0                0
    FTE                                   4.5              1.1                0.0                0.0             0.0


Detail of Adjustments to Recorded:

Year/Expl.      Labor         NLbr        NSE       FTE      Adj_Type       From CCtr                  RefID

2005               294               0          0   0.0 CCTR Transf         From 2100-0038.000           SDALEY2009092
                                                                                                            1130924997
   To support a change in organizational structure by aligning history with TY2012 planning.
   2100-0038 (Customer Service Technology) was reorganized in 2006 and split between
   2100-0642 (Customer Operations Technology) and 2100-3584 (CST-SORT).
2005                  0          214            0   0.0 CCTR Transf         From 2100-0038.000           SDALEY2009092
                                                                                                            1131630037
   To support a change in organizational structure by aligning history with 2012 planning.

2005                  0              0          0   4.5 CCTR Transf         From 2100-0038.000           SDALEY2009092
                                                                                                            1131909023
   To support a change in organizational structure by aligning history with TY2012 planning.

2005                 -3              0          0   0.0 CCTR Transf         From 2100-0038.000           SDALEY2009092
                                                                                                            1142132800
   To support a change in organizational structure by aligning history with TY2012 planning.
   2100-0038 (Customer Service Technology) was reorganized in 2006 and split between
   2100-0642 (Customer Operations Technology) and 2100-3584 (CST-SORT).
2005 Total         291           214            0   4.5



2006                90               0          0   0.0 CCTR Transf         From 2100-0038.000           SDALEY2009092
                                                                                                            1132403590
   To support a change in organizational structure by aligning history with TY2012 planning.

2006                  0           99            0   0.0 CCTR Transf         From 2100-0038.000           SDALEY2009092
                                                                                                            1132825270
   To support a change in organizational structure by aligning history with TY2012 planning.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 260 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                D. CS Technology Support
Category-Sub:            1. CS Operations-Customer Service Technology Support
Workpaper:               1OO004.000 - CS TECHNOLOGY SUPPORT


Year/Expl.       Labor         NLbr        NSE       FTE      Adj Type            From CCtr       RefID

2006                  0             0         0      1.1 CCTR Transf        From 2100-0038.000   SDALEY2009092
                                                                                                    1133037537
    To support a change in organizational structure by aligning history with TY2012 planning.

2006                  0         0.040         0      0.0 CCTR Transf        From 2100-0038.000   SDALEY2009092
                                                                                                    1142755307
    To support a change in organizational structure by aligning history with TY2012 planning.

2006                 12             0         0      0.0 CCTR Transf        From 2100-0038.000   SDALEY2009092
                                                                                                    1143047683
    To support a change in organizational structure by aligning history with TY2012 planning.

2006                  0             0         0      0.2 CCTR Transf        From 2100-0038.000   SDALEY2009092
                                                                                                    1143951540
    To support a change in organizational structure by aligning history with TY2012 planning.

2006                -14             0         0      0.0 1-Sided Adj        N/A                  SDALEY2009102
                                                                                                    9082140273
    One time labor related to billable order 7016424 in support of Pacer at SCG not
    expected to recur.
2006                  0             0         0     -0.2 1-Sided Adj        N/A                  SDALEY2009102
                                                                                                    9082212743
    One time labor/FTE related to billable order 7016424 in support of Pacer at SCG not
    expected to recur.
2006 Total           88            99         0      1.1



2007 Total            0             0         0      0.0



2008 Total            0             0         0      0.0



2009 Total            0             0         0      0.0




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 261 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                            Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                E. CS Operations Other
Workpaper:               1OO005.000

Summary for Category: E. CS Operations Other

                                                             In 2009$ (000)
                                 Adjusted-Recorded                        Adjusted-Forecast
                                    2009                   2010               2011            2012
             Labor                    1,227                 1,199               1,199            2,043
             Non-Labor                  396                  265                  265                439
             NSE                           0                      0                  0                 0
               Total                  1,623                 1,464               1,464            2,482
               FTE                     11.3                  11.1                11.1                19.1

   Workpapers belonging to this Category:
    1OO005.000 CS OPERATIONS OTHER
         Labor                       1,227                  1,199              1,199             2,043
         Non-Labor                     396                    265                265               439
         NSE                             0                      0                  0                 0
            Total                    1,623                  1,464              1,464             2,482
            FTE                       11.3                   11.1               11.1              19.1




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 262 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                   Non-Shared Service Workpapers




                Beginning of Workpaper
           1OO005.000 - CS OPERATIONS OTHER




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 263 of 375
                                               San Diego Gas & Electric Company
                                                  Test Year 2012 GRC - APP
                                                Non-Shared Service Workpapers


Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                E. CS Operations Other
Category-Sub             1. CS Operations-Other
Workpaper:               1OO005.000 - CS OPERATIONS OTHER

Activity Description:
                This workgroup encompasses activities related to Residential Services, Budgeting and the VP
                groups.
Forecast Methodology:

        Labor - 5-YR Average
               The Residential Services, Budgeting and VP groups can experience fluctuations in levels of
               activity from year to year. To account for these fluctuations, it is logical to establish a base for
               future expense by using a five year historical average to encompass the increases and
               decreases in work flow volumes over a reasonable timeframe.
        Non-Labor - 5-YR Average
              The Residential Services, Budgeting and VP groups can experience fluctuations in levels of
              activity from year to year. To account for these fluctuations, it is logical to establish a base for
              future expense by using a five year historical average to encompass the increases and
              decreases in work flow volumes over a reasonable timeframe.
        NSE - 5-YR Average
               N/A


Summary of Results:

                                                                    In 2009$ (000)
                                          Adjusted-Recorded                                       Adjusted-Forecast
Years                      2005        2006         2007         2008         2009            2010         2011       2012
Labor                     1,174       1,199        1,149        1,247        1,227           1,199        1,199       2,043
Non-Labor                   238         111          152          356          396             265          265        439
NSE                           0           0            0            0            0               0            0         0
   Total                  1,412       1,310        1,301        1,603        1,623           1,464        1,464       2,482
   FTE                     10.7        11.0         10.3         12.0         11.3            11.1         11.1        19.1




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 264 of 375
                                                San Diego Gas & Electric Company
                                                   Test Year 2012 GRC - APP
                                                 Non-Shared Service Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 E. CS Operations Other
Category-Sub:             1. CS Operations-Other
Workpaper:                1OO005.000 - CS OPERATIONS OTHER

Forecast Summary:
                                                                        In 2009 $(000)
     Forecast Method                       Base Forecast                  Forecast Adjustments             Adjusted-Forecast
                                       2010          2011     2012       2010       2011    2012          2010     2011        2012
 Labor              5-YR Average       1,199         1,199   1,199              0     0      844          1,199    1,199   2,043
 Non-Labor          5-YR Average        250           250         250      15        15      189           265      265        439
 NSE                5-YR Average           0            0           0           0     0          0           0         0         0
 Total                                 1,449         1,449   1,449         15        15     1,033         1,464    1,464   2,482
 FTE                5-YR Average        11.1          11.1    11.1         0.0       0.0      8.0          11.1     11.1       19.1


Forecast Adjustment Details:
       Year/Expl.            Labor             NLbr          NSE        Total        FTE    Adj_Type

         2010                      0            10            0           10          0.0   1-Sided Adj

            Additional travel related to regulatory and other issues.

         2010                      0             5            0            5          0.0   1-Sided Adj

            Non labor increase associated with departmental re-organization.

         2010 Total                0            15            0           15          0.0




         2011                      0            10            0           10          0.0   1-Sided Adj

            Additional travel related to regulatory and other issues.

         2011                      0             5            0            5          0.0   1-Sided Adj

            Non Labor increase due to departmental reorganization.

         2011 Total                0            15            0           15          0.0




         2012                  844               0            0          844          0.0   1-Sided Adj

            8 FTE's to support Home Area Network (HAN) program management.

         2012                      0           174            0          174          0.0   1-Sided Adj

            Non labor expenses to support HAN program including employee expense, materials, and
            industry policy/standards development.




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 265 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             E. CS Operations Other
Category-Sub:         1. CS Operations-Other
Workpaper:            1OO005.000 - CS OPERATIONS OTHER

      Year/Expl.         Labor           NLbr       NSE          Total       FTE   Adj Type

      2012                     0             0            0              0     8.0   1-Sided Adj

         8 FTE's to support Home Area Network (HAN) program management.

      2012                     0            10            0            10      0.0   1-Sided Adj

         Additional travel related to regulatory and other issues.

      2012                     0             5            0              5     0.0   1-Sided Adj

         Non Labor increase due to departmental reorganization.

      2012 Total            844           189             0          1,033     8.0




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 266 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               E. CS Operations Other
Category-Sub:           1. CS Operations-Other
Workpaper:              1OO005.000 - CS OPERATIONS OTHER

Determination of Adjusted-Recorded:
                                2005 ($000)              2006 ($000)         2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                                 843                  981                817          1,046        1,148
     Non-Labor                               76                  85                121            155        1,220
     NSE                                      0                   0                   0             0             0
         Total                             920                1,067                938          1,201        2,368
         FTE                                8.5                10.2                 7.3          10.2           9.8
  Adjustments (Nominal $) **
     Labor                                   73                  -32               126              -2          -85
     Non-Labor                             130                    16                 22           201         -824
     NSE                                      0                    0                  0              0            0
         Total                             203                   -16               147            199         -909
         FTE                                0.7                 -0.8                1.5            0.0         -0.1
  Recorded-Adjusted (Nominal $)
     Labor                                 917                  950                943          1,044        1,063
     Non-Labor                             206                  101                143            356          396
     NSE                                      0                    0                  0             0             0
          Total                          1,123                1,051              1,085          1,400        1,459
          FTE                               9.2                  9.4                8.8          10.2           9.7
  Vacation & Sick (Nominal $)
     Labor                                 132                  153                141            172          164
     Non-Labor                                0                    0                  0              0            0
     NSE                                      0                    0                  0              0            0
          Total                            132                  153                141            172          164
          FTE                               1.5                  1.6                1.5            1.8          1.6
  Escalation to 2009$
     Labor                                 125                    97                65             31            0
     Non-Labor                               32                   10                 9              0            0
     NSE                                      0                    0                 0              0            0
         Total                             157                  107                 74             30            0
         FTE                                0.0                  0.0               0.0            0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                               1,174                1,199              1,149          1,247        1,227
     Non-Labor                             238                  111                152            356          396
     NSE                                     0                    0                  0              0            0
         Total                           1,413                1,311              1,300          1,602        1,623
         FTE                              10.7                 11.0               10.3           12.0         11.3



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 267 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                            Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               E. CS Operations Other
Category-Sub:           1. CS Operations-Other
Workpaper:              1OO005.000 - CS OPERATIONS OTHER


Summary of Adjustments to Recorded:

                                                             In Nominal $ (000)
 Year                                   2005             2006              2007           2008                2009
    Labor                                73               -32              126                  -2              -85
    Non-Labor                           130                16               22             201                 -824
    NSE                                   0                 0                0                  0                 0
        Total                           203               -16              147             199                 -909
    FTE                                  0.7             -0.8               1.5                0.0             -0.1


Detail of Adjustments to Recorded:

Year/Expl.      Labor        NLbr        NSE       FTE      Adj_Type      From CCtr                  RefID

2005                 0         128             0   0.0 CCTR Transf        From 2100-3446.000           CSCHRAMM2010
                                                                                                        0415212134773
   Customer Services Solutions function no longer exists as part of the Product & E
   Services CCTR -Transfer non-labor purchased services for the Customer Care Project
   from Wk Gp 1IN000 NSS 2100-3446 Products & E Service Programs to Wk Gp
   1OO005 NSS 2100-0040 Customer Services Solutions.
2005               16               0          0   0.0 CCTR Transf        From 2100-3446.000           CSCHRAMM2010
                                                                                                        0415212223007
   Customer Services Solutions function no longer exists as part of the Product & E
   Services CCTR -Transfer labor for Customer Service Solutions from Wk Gp 1IN000
   NSS CCTR 2100-3446 Products & E Service Programs to Wk Gp 1OO005 NSS
   2100-0040 Customer Services Solutions.
2005                 0              0          0   0.2 CCTR Transf        From 2100-3446.000           CSCHRAMM2010
                                                                                                        0415212256693
   Customer Services Solutions function no longer exists as part of the Product & E
   Services CCTR -Transfer labor for Customer Service Solutions from Wk Gp 1IN000
   NSS CCTR 2100-3446 Products & E Service Programs to Wk Gp 1OO005 NSS
   2100-0040 Customer Services Solutions.
2005               84               0          0   0.0 CCTR Transfer      From 2100-0006.000           SDALEY2010041
                                                                                                          5123825257
   Residential Services Organization has been restructured. CS Operations Analysis
   employees' labor and non-labor should be moved from USS cost center 2100-0006 into
   USS cost center 2100-3593 CS Operations Analysis to align with current org.
2005                 0              2          0   0.0 CCTR Transfer      From 2100-0006.000           SDALEY2010041
                                                                                                          5123900117
   Residential Services Organization has been restructured. CS Operations Analysis
   employees' labor and non-labor should be moved from USS cost center 2100-0006 into
   USS cost center 2100-3593 CS Operations Analysis to align with current org.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 268 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                E. CS Operations Other
Category-Sub:            1. CS Operations-Other
Workpaper:               1OO005.000 - CS OPERATIONS OTHER


Year/Expl.       Labor        NLbr        NSE      FTE      Adj Type           From CCtr        RefID

2005                  0           0          0     1.0 CCTR Transfer     From 2100-0006.000   SDALEY2010041
                                                                                                 5123928540
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2005                 -8           0          0     0.0 CCTR Transfer     To 2100-0006.000     SDALEY2010041
                                                                                                 5125846257
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2005                  0           0          0    -0.2 CCTR Transfer     To 2100-0006.000     SDALEY2010041
                                                                                                 5125919337
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2005                -19           0          0     0.0 CCTR Transfer     To 2100-0027.000     SDALEY2010041
                                                                                                 5130810197
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2005                  0       -0.056         0     0.0 CCTR Transfer     To 2100-0027.000     SDALEY2010041
                                                                                                 5133613367
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2005                  0           0          0    -0.3 CCTR Transfer     To 2100-0027.000     SDALEY2010041
                                                                                                 5133638727
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2005 Total          73          130          0     0.7



2006                70            0          0     0.0 CCTR Transf       From 2100-3446.000   CSCHRAMM2010
                                                                                               0415213201130
    Customer Services Solutions function no longer exists as part of the Product & E
    Services CCTR -Transfer labor for Customer Service Solutions from Wk Gp 1IN000
    NSS CCTR 2100-3446 Products & E Service Programs to Wk Gp 1OO005 NSS
    2100-0040 Customer Services Solutions.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 269 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                E. CS Operations Other
Category-Sub:            1. CS Operations-Other
Workpaper:               1OO005.000 - CS OPERATIONS OTHER


Year/Expl.       Labor        NLbr        NSE      FTE      Adj Type           From CCtr        RefID

2006                  0           0          0     1.0 CCTR Transf       From 2100-3446.000   CSCHRAMM2010
                                                                                               0415213349147
    Customer Services Solutions function no longer exists as part of the Product & E
    Services CCTR -Transfer labor for Customer Service Solutions from Wk Gp 1IN000
    NSS CCTR 2100-3446 Products & E Service Programs to Wk Gp 1OO005 NSS
    2100-0040 Customer Services Solutions.
2006                  0          17          0     0.0 CCTR Transf       From 2100-3446.000   CSCHRAMM2010
                                                                                               0415214340540
    Customer Services Solutions function no longer exists as part of the Product & E
    Services CCTR -Transfer temporary agency labor and employee expenses for Customer
    Service Solutions from Wk Gp 1IN000 NSS CCTR 2100-3446 Products & E Service
    Programs to Wk Gp 1OO005 NSS 2100-0040 Customer Services Solutions.
2006                -37           0          0     0.0 CCTR Transfer     To 2100-0006.000     SDALEY2010041
                                                                                                 5130222087
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2006                  0       -0.252         0     0.0 CCTR Transfer     To 2100-0006.000     SDALEY2010041
                                                                                                 5130235507
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2006                  0           0          0    -0.8 CCTR Transfer     To 2100-0006.000     SDALEY2010041
                                                                                                 5130246523
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2006                -97           0          0     0.0 CCTR Transfer     To 2100-0027.000     SDALEY2010041
                                                                                                 5133819790
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2006                  0       -0.684         0     0.0 CCTR Transfer     To 2100-0027.000     SDALEY2010041
                                                                                                 5133846587
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 270 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                             Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                E. CS Operations Other
Category-Sub:            1. CS Operations-Other
Workpaper:               1OO005.000 - CS OPERATIONS OTHER


Year/Expl.       Labor         NLbr        NSE       FTE       Adj Type           From CCtr       RefID
2006                  0             0          0    -1.7 CCTR Transfer      To 2100-0027.000     SDALEY2010041
                                                                                                    5133906790
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2006                -34             0          0     0.0 CCTR Transfer      To 2100-3593.000     SDALEY2010041
                                                                                                    5134318900
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2006                 34             0          0     0.0 CCTR Transfer      From 2100-0040.000   SDALEY2010041
                                                                                                    5134318900
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2006                  0        -0.482          0     0.0 CCTR Transfer      To 2100-3593.000     SDALEY2010041
                                                                                                    5134353227
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2006                  0         0.482          0     0.0 CCTR Transfer      From 2100-0040.000   SDALEY2010041
                                                                                                    5134353227
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2006                  0             0          0    -0.4 CCTR Transfer      To 2100-3593.000     SDALEY2010041
                                                                                                    5134431070
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2006                  0             0          0     0.4 CCTR Transfer      From 2100-0040.000   SDALEY2010041
                                                                                                    5134431070
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2006                 31             0          0     0.0 CCTR Transf        From 2100-0027.000   SDALEY2010041
                                                                                                    9135400780
    Correction of Admin Assistant's labor that should remain in the Residential Services
    organization.
2006                  0             0          0     0.7 CCTR Transf        From 2100-0027.000   SDALEY2010041
                                                                                                    9135426093
    Correction of Admin Assistant's labor that should remain in the Residential Services
    organization.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 271 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                E. CS Operations Other
Category-Sub:            1. CS Operations-Other
Workpaper:               1OO005.000 - CS OPERATIONS OTHER


Year/Expl.       Labor        NLbr        NSE      FTE      Adj Type           From CCtr        RefID

2006 Total          -32          16          0    -0.8



2007               121            0          0     0.0 CCTR Transf       From 2100-3446.000   CSCHRAMM2010
                                                                                               0415214831087
    Customer Services Solutions function no longer exists as part of the Product & E
    Services CCTR -Transfer labor for Customer Service Solutions from Wk Gp 1IN000
    NSS CCTR 2100-3446 Products & E Service Programs to Wk Gp 1OO005 NSS
    2100-0040 Customer Services Solutions.
2007                  0          20          0     0.0 CCTR Transf       From 2100-3446.000   CSCHRAMM2010
                                                                                               0415215039490
    Customer Services Solutions function no longer exists as part of the Product & E
    Services CCTR -Transfer non-labor for Customer Service Solutions Wk Gp 1IN000 NSS
    2100-3446 Products & E Service Programs to Wk Gp 1OO005 NSS 2100-0040
    Customer Services Solutions.
2007                  0           0          0     1.7 CCTR Transf       From 2100-3446.000   CSCHRAMM2010
                                                                                               0416144011907
    Customer Services Solutions function no longer exists as part of the Product & E
    Services CCTR -Transfer labor for Customer Service Solutions from Wk Gp 1IN000
    NSS CCTR 2100-3446 Products & E Service Programs to Wk Gp 1OO005 NSS
    2100-0040 Customer Services Solutions.
2007                25            0          0     0.0 CCTR Transfer     From 2100-0006.000   SDALEY2010041
                                                                                                 5124317400
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2007                  0           3          0     0.0 CCTR Transfer     From 2100-0006.000   SDALEY2010041
                                                                                                 5124336493
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2007                  0           0          0     0.3 CCTR Transfer     From 2100-0006.000   SDALEY2010041
                                                                                                 5124406837
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2007                -21           0          0     0.0 CCTR Transfer     To 2100-0006.000     SDALEY2010041
                                                                                                 5130530947
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 272 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                E. CS Operations Other
Category-Sub:            1. CS Operations-Other
Workpaper:               1OO005.000 - CS OPERATIONS OTHER


Year/Expl.       Labor        NLbr        NSE      FTE      Adj Type           From CCtr       RefID

2007                  0       -0.513         0     0.0 CCTR Transfer     To 2100-0006.000     SDALEY2010041
                                                                                                 5130543070
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2007                  0           0          0    -0.5 CCTR Transfer     To 2100-0006.000     SDALEY2010041
                                                                                                 5130557040
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2007                  1           0          0     0.0 CCTR Transfer     To 2100-0027.000     SDALEY2010041
                                                                                                 5134125493
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2007                  0       -0.074         0     0.0 CCTR Transfer     To 2100-0027.000     SDALEY2010041
                                                                                                 5134151883
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2007                -74           0          0     0.0 CCTR Transfer     To 2100-3593.000     SDALEY2010041
                                                                                                 5134818617
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2007                74            0          0     0.0 CCTR Transfer     From 2100-0040.000   SDALEY2010041
                                                                                                 5134818617
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2007                  0           -4         0     0.0 CCTR Transfer     To 2100-3593.000     SDALEY2010041
                                                                                                 5134844383
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2007                  0           4          0     0.0 CCTR Transfer     From 2100-0040.000   SDALEY2010041
                                                                                                 5134844383
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 273 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                           Non-Shared Service Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               E. CS Operations Other
Category-Sub:           1. CS Operations-Other
Workpaper:              1OO005.000 - CS OPERATIONS OTHER


Year/Expl.      Labor        NLbr        NSE      FTE      Adj Type           From CCtr        RefID

2007                 0            0         0     0.9 CCTR Transfer     From 2100-0040.000   SDALEY2010041
                                                                                                5134906930
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2007                 0            0         0    -0.9 CCTR Transfer     To 2100-3593.000     SDALEY2010041
                                                                                                5134906930
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2007                 0       -0.461         0     0.0 1-Sided Adj       N/A                  SDALEY2010041
                                                                                                9145100063
    CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2007 Total         126           22         0     1.5



2008                 0          191         0     0.0 CCTR Transf       From 2100-3446.000   CSCHRAMM2010
                                                                                              0415215317647
    Customer Services Solutions function no longer exists as part of the Product & E
    Services CCTR -Transfer non-labor for Customer Service Solutions from Wk Gp 1IN000
    NSS 2100-3446 Products & E Service Programs to Wk Gp 1OO005 NSS 2100-0040
    Customer Services Solutions.
2008                 -2           0         0     0.0 CCTR Transfer     From 2100-0006.000   SDALEY2010041
                                                                                                5124536383
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2008                 0            1         0     0.0 CCTR Transfer     From 2100-0006.000   SDALEY2010041
                                                                                                5124552227
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2008                 0            9         0     0.0 CCTR Transfer     From 2100-0006.000   SDALEY2010041
                                                                                                5124942900
    Residential Services Organization has been restructured. Customer Segment
    purchased services dollars should be moved from USS cost center 2100-0006 into NSS
    cost center 2100-0040 CS Solutions to align with current org.
2008                 -1           0         0     0.0 CCTR Transfer     From 2100-0040.000   SDALEY2010041
                                                                                                5140130087
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 274 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                              Non-Shared Service Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                E. CS Operations Other
Category-Sub:            1. CS Operations-Other
Workpaper:               1OO005.000 - CS OPERATIONS OTHER


Year/Expl.       Labor         NLbr         NSE       FTE      Adj Type            From CCtr       RefID

2008                   1            0            0    0.0 CCTR Transfer      To 2100-3593.000     SDALEY2010041
                                                                                                     5140130087
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2008                   0        0.029            0    0.0 CCTR Transfer      From 2100-0040.000   SDALEY2010041
                                                                                                     5140154900
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2008                   0       -0.029            0    0.0 CCTR Transfer      To 2100-3593.000     SDALEY2010041
                                                                                                     5140154900
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from NSS cost center 2100-0040 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2008 Total            -2          201            0    0.0



2009                 -85            0            0    0.0 CCTR Transf        To 2100-3463.000     SDALEY2010031
                                                                                                     8140237627
    Transferring emergency preparedness expenses from Customer Service SVP to
    Regional Public Affairs due to a change in the reporting relationship for the management
    of this initiative.
2009                   0         -724            0    0.0 CCTR Transf        To 2100-3463.000     SDALEY2010031
                                                                                                     8140304830
    Transferring emergency preparedness expenses from Customer Service SVP to
    Regional Public Affairs due to a change in the reporting relationship for the management
    of this initiative.
2009                   0            0            0   -0.1 CCTR Transf        To 2100-3463.000     SDALEY2010031
                                                                                                     8140344750
    Transferring emergency preparedness FTE from Customer Service SVP to Regional
    Public Affairs due to a change in the reporting relationship for the management of this
    initiative.
2009                   0         -100            0    0.0 1-Sided Adj        N/A                  SDALEY2010041
                                                                                                     9112417733
    $100K training invoice paid twice in 2009.

2009 Total           -85         -824            0   -0.1




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 275 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                   Non-Shared Service Workpapers




     Supplemental Workpapers for Workpaper 1OO005.000




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 276 of 375
SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon - 1OO005.000_Supp1.pdf




                                                                                                       Home Area Network (HAN) Expense Summary

                                                                                           O&M EXPENSES                                          2012

                                                                                           O&M LABOR EXPENSES
                                                                                                            1         HAN Business Manager              134,700
                                                                                                            1         Business Project Manager          119,100
                                                                                                            4         Program/Market Advisor            421,600




                                                                                                                                                                  San Diego Gas & Electric Company
                                                                                                                                                                   Non-Shared Service Workpapers
                                                                                                            1         Senior Business Analyst            93,400




                                                                                                                                                                     Test Year 2012 GRC - APP
                                                                                                            1         Business Analyst                   74,700
                                                                                           SUB-TOTAL LABOR                                              843,500
                                  Pages 277 of 375




                                                                                           NON-LABOR EXPENSES
                                                                                                         Training
                                                                                                         Employee Materials / Expenses (2)
                                                                                                         Industry policy/standards development

                                                                                           SUB-TOTAL NON-LABOR EXPENSES                                 174,375

                                                                                           GRAND TOTAL                                              1,017,875
                                       San Diego Gas & Electric Company
                                          Test Year 2012 GRC - APP
                                         Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve



Summary of Shared Services Workpapers:
                                                                In 2009 $ (000) "Book Expense"
                                                  Adjusted-
                                                                                Adjusted-Forecast
                                                  Recorded
Description                                         2009            2010                 2011        2012
A. SOX Project Management                                  53              72                   72          72
B. Director of CS Technology Support                  1,810           2,199                2,540       2,961
C. Business Planning & Budgets                             79              33                   33          33
D. Director of Market Services                             27              88                   88          88
E. Billed-in from SCG                                 1,017           1,493                1,509       1,509
Total                                                 2,986           3,885                4,242       4,663




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 278 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                             Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               A. SOX Project Management
Cost Center:            2100-3476.000

Summary for Category: A. SOX Project Management

                                                      In 2009$ (000) "Book Expense"
                                 Adjusted-Recorded                         Adjusted-Forecast
                                    2009                   2010               2011             2012
           Labor                           51                  71                    71               71
           Non-Labor                        2                     1                   1                1
           NSE                              0                     0                   0                0
               Total                       53                  72                    72               72
               FTE                         0.9                1.0                    1.0              1.0

    Cost Centers belonging to this Category:
     2100-3476.000 SOX PROJECT MANAGEMENT
           Labor                         51                    71                   71                 71
           Non-Labor                      2                     1                    1                  1
           NSE                            0                     0                    0                  0
             Total                       53                    72                   72                 72
             FTE                        0.9                   1.0                  1.0                1.0




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 279 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                    Shared Services Workpapers




                 Beginning of Workpaper
       2100-3476.000 - SOX PROJECT MANAGEMENT




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 280 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                               Shared Services Workpapers


Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               A. SOX Project Management
Category-Sub            1. SOX Project Management
Cost Center:            2100-3476.000 - SOX PROJECT MANAGEMENT

Activity Description:
               This Project Manager is the coordinator for SOX activities for both companies, the Bill
               Redesign project, climate zone and other billing related issues.
Forecast Methodology:

       Labor - 5-YR Average
              The 5 year average methodology is appropriate in this cost center, as it is a Project
              Management function largely unchanged in staff and function over the past five years.
       Non-Labor - 5-YR Average
             The 5 year average methodology is appropriate in this cost center, as it is a Project
             Management function largely unchanged in staff and function over the past five years.
       NSE - 5-YR Average
              N/A




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 281 of 375
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Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             A. SOX Project Management
Category-Sub          1. SOX Project Management
Cost Center:          2100-3476.000 - SOX PROJECT MANAGEMENT

Summary of Results:

                                                        In 2009$ (000)
                                  Adjusted-Recorded                                Adjusted-Forecast
Years                 2005      2006      2007        2008       2009           2010     2011      2012
                                                  Total Incurred (100% Level)
Labor                     0     134        116         94         101           101       101      101
Non-Labor                 6        1          2          1           4             2         2      2
NSE                       0        0          0          0           0             0         0      0
   Total                  6     135        118          95        105           103       103      103
   FTE                  0.0      1.5        1.3        1.1         0.9           1.0       1.0     1.0
                                                         Allocations Out
Labor                     0       60         57         47          50            30        30     30
Non-Labor                 0        0          1          0           2             1         1      1
NSE                       0        0          0          0           0             0         0      0
   Total                  0       60         58         47          52            31        31     31
   FTE                  0.0      0.0        0.0        0.0         0.0           0.0       0.0     0.0
                                                             Retained
Labor                     0       74         59         47          51            71        71     71
Non-Labor                 6        1          1          1           2             1         1      1
NSE                       0        0          0          0           0             0         0      0
   Total                  6       75         60         48          53            72        72     72
   FTE                  0.0      1.5        1.3        1.1         0.9           1.0       1.0     1.0
                                                         Allocations In
Labor                     0        0          0          0          0              0         0      0
Non-Labor                 0        0          0          0          0              0         0      0
NSE                       0        0          0          0          0              0         0      0
   Total                  0        0          0          0          0              0         0      0
   FTE                  0.0      0.0        0.0        0.0        0.0            0.0       0.0     0.0
                                                         Book Expense
Labor                     0       74         59         47        51              71        71     71
Non-Labor                 6        1          1          1         2               1         1      1
NSE                       0        0          0          0         0               0         0      0
   Total                  6       75         60         48        53              72        72     72
   FTE                  0.0      1.5        1.3        1.1       0.9             1.0       1.0     1.0




                 SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                         Pages 282 of 375
                                                  San Diego Gas & Electric Company
                                                     Test Year 2012 GRC - APP
                                                    Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 A. SOX Project Management
Category-Sub:             1. SOX Project Management
Cost Center:              2100-3476.000 - SOX PROJECT MANAGEMENT


Calculation of Book Expense:

                                          2009 Adjusted-Recorded                               2010 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total     FTE
  Directly Retained                 1          0        0         1      0.00           0          0        0         0      0.00
  Directly Allocated                0         0         0           0    0.00           0         0         0           0    0.00
  Subj. To % Alloc.            100            4         0          104   0.90      101            2         0       103      1.00
  % Allocation
       Retained             50.00%       50.00%                                 70.00%       70.00%
       SEU                  50.00%       50.00%                                 30.00%       30.00%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained                 50            2         0          52               71            1         0           72
       SEU                      50            2         0          52               30            1         0           31
       CORP                         0         0         0           0                   0         0         0           0
       Unreg                        0         0         0           0                   0         0         0           0
  Total Incurred               101            4         0          105   0.90      101             2        0       103      1.00
  Total Alloc. Out              50            2         0           52              30             1        0           31
  Total Retained                51            2         0           53              71             1        0           72
  Allocations In                    0         0         0            0                  0          0        0            0
  Book Expense                  51            2         0          53               71            1         0           72


                                          2011 Adjusted-Forecast                               2012 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total     FTE
  Directly Retained                 0         0         0           0    0.00           0         0         0           0    0.00
  Directly Allocated                0         0         0           0    0.00           0         0         0           0    0.00
  Subj. To % Alloc.            101            2         0          103   1.00      101            2         0       103      1.00
  % Allocation
       Retained             70.00%       70.00%                                 70.00%       70.00%
       SEU                  30.00%       30.00%                                 30.00%       30.00%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained                 71            1         0          72               71            1         0           72
       SEU                      30            1         0          31               30            1         0           31
       CORP                         0         0         0           0                   0         0         0           0
       Unreg                        0         0         0           0                   0         0         0           0
  Total Incurred               101            2         0          103   1.00      101             2        0       103      1.00
  Total Alloc. Out              30            1         0           31              30             1        0           31
  Total Retained                71            1         0           72              71             1        0           72
  Allocations In                    0         0         0            0                  0          0        0            0
  Book Expense                  71            1         0          72               71            1         0           72




                       SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                               Pages 283 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                             Shared Services Workpapers



Area:                  CS - OFFICE OPERATIONS
Witness:               Rahon, J Steve
Category:              A. SOX Project Management
Category-Sub:          1. SOX Project Management
Cost Center:           2100-3476.000 - SOX PROJECT MANAGEMENT



Cost Center Allocation Percentage Drivers/Methodology:

    Cost Center Allocation Percentage for 2009
          Both labor and non labor allocations are based on total FTE's supported by Project Manager involved
          in evaluating SOX related business processes. Calculations based on 74 FTE's involved in SOX
          testing and assessments. 37 at SDG&E and 37 at SCG.


    Cost Center Allocation Percentage for 2010
          Calculations based on FTE's involved in SOX testing and assessments. 37 at SDG&E and 37 at
          SCG. For 2010 and beyond, SDG&E projects outside of SOX Project Management such as climate
          zone, are a significant contibutor to the shift in the allocation percentage.


    Cost Center Allocation Percentage for 2011
          Calculations based on FTE's involved in SOX testing and assessments. 37 at SDG&E and 37 at
          SCG. For 2010 and beyond, SDG&E projects outside of SOX Project Management such as climate
          zone, are a significant contibutor to the shift in the allocation percentage.


    Cost Center Allocation Percentage for 2012
          Calculations based on FTE's involved in SOX testing and assessments. 37 at SDG&E and 37 at
          SCG. For 2010 and beyond, SDG&E projects outside of SOX Project Management such as climate
          zone, are a significant contibutor to the shift in the allocation percentage.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 284 of 375
                                               San Diego Gas & Electric Company
                                                  Test Year 2012 GRC - APP
                                                 Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 A. SOX Project Management
Category-Sub:             1. SOX Project Management
Cost Center:              2100-3476.000 - SOX PROJECT MANAGEMENT

Forecast Summary:
                                                            In 2009 $(000) "Incurred Costs"
     Forecast Method                      Base Forecast                Forecast Adjustments               Adjusted-Forecast
                                      2010         2011     2012       2010       2011       2012         2010    2011        2012
 Labor              5-YR Average         88          88         88       13         13         13         101      101        101
 Non-Labor          5-YR Average          2           2          2            0      0          0           2         2         2
 NSE                5-YR Average          0           0          0            0      0          0           0         0         0
 Total                                   90          90         90       13         13         13         103      103        103
 FTE                5-YR Average        1.0          1.0        1.0      0.0        0.0       0.0          1.0      1.0        1.0


Forecast Adjustment Details:
       Year/Expl.           Labor             NLbr         NSE        Total         FTE     Adj_Type

         2010                   13             0            0           13           0.0    1-Sided Adj

            Full year salary impact for Project Manager currently supporting SOX related activities.

         2010 Total             13             0            0           13           0.0




         2011                   13             0            0           13           0.0    1-Sided Adj

            Full year salary impact for Project Manager currently supporting SOX related activities.

         2011 Total             13             0            0           13           0.0




         2012                   13             0            0           13           0.0    1-Sided Adj

            Full year salary impact for Project Manager currently supporting SOX related activities.

         2012 Total             13             0            0           13           0.0




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 285 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                              Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               A. SOX Project Management
Category-Sub:           1. SOX Project Management
Cost Center:            2100-3476.000 - SOX PROJECT MANAGEMENT

Determination of Adjusted-Recorded (Incurred Costs):
                                2005 ($000)          2006 ($000)             2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                                   0                  106                 95             80           87
     Non-Labor                               5                     1                 2              1            4
     NSE                                     0                     0                 0              0            0
         Total                               5                  107                 97             81           91
         FTE                               0.0                   1.3               1.1            0.9          0.8
  Adjustments (Nominal $) **
     Labor                                   0                     0                 0              0            0
     Non-Labor                               0                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
         Total                               0                     0                 0              0            0
         FTE                               0.0                   0.0               0.0            0.0          0.0
  Recorded-Adjusted (Nominal $)
     Labor                                   0                  106                 95             80           87
     Non-Labor                               5                     1                 2              1            4
     NSE                                     0                     0                 0              0            0
          Total                              5                  107                 97             81           91
          FTE                              0.0                   1.3               1.1            0.9          0.8
  Vacation & Sick (Nominal $)
     Labor                                   0                    17                14             13           13
     Non-Labor                               0                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
          Total                              0                    17                14             13           13
          FTE                              0.0                   0.2               0.2            0.2          0.1
  Escalation to 2009$
     Labor                                   0                    11                 6              1            0
     Non-Labor                               1                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
         Total                               1                    11                 6              1            0
         FTE                               0.0                   0.0               0.0            0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                                   0                  134                116             94          101
     Non-Labor                               6                     1                  2             1             4
     NSE                                     0                     0                  0             0             0
         Total                               6                  135                118             95          105
         FTE                               0.0                   1.5                1.3           1.1           0.9



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 286 of 375
                                           San Diego Gas & Electric Company
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                                             Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               A. SOX Project Management
Category-Sub:           1. SOX Project Management
Cost Center:            2100-3476.000 - SOX PROJECT MANAGEMENT


Summary of Adjustments to Recorded:

                                                   In Nominal $ (000) "Incurred Costs"
 Year                                   2005           2006               2007           2008            2009
    Labor                                 0               0                   0            0                0
    Non-Labor                             0               0            -0.009              0                0
    NSE                                   0               0                   0            0                0
        Total                             0               0            -0.009              0                0
    FTE                                  0.0             0.0              0.0             0.0             0.0


Detail of Adjustments to Recorded:

Year/Expl.      Labor        NLbr        NSE       FTE    Adj_Type      From CCtr               RefID

2005 Total           0              0          0   0.0



2006 Total           0              0          0   0.0



2007                 0       -0.009            0   0.0 1-Sided Adj      N/A                       SDALEY2009092
                                                                                                     9071725037
   CEMA - To remove incremental firestorm costs requested in CEMA for recovery.

2007 Total           0       -0.009            0   0.0



2008 Total           0              0          0   0.0



2009 Total           0              0          0   0.0




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 287 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                              Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Cost Center:            VARIOUS

Summary for Category: B. Director of CS Technology Support

                                                         In 2009$ (000) "Book Expense"
                                  Adjusted-Recorded                           Adjusted-Forecast
                                     2009                      2010              2011             2012
           Labor                        1,778                  2,115                2,456            2,923
           Non-Labor                        32                    84                    84                38
           NSE                               0                        0                  0                 0
               Total                    1,810                  2,199                2,540            2,961
               FTE                       27.9                   32.0                 36.6                43.3

    Cost Centers belonging to this Category:
     2100-0027.000 DIRECTOR CS TECHNOLOGY SUPPORT
           Labor                        187                      180                 180                 180
           Non-Labor                       9                        9                   9                   9
           NSE                             0                        0                   0                   0
             Total                      196                      189                 189                 189
             FTE                         3.2                      3.0                 3.0                 3.0
     2100-0642.000 CS TECHNOLOGY MANAGER
           Labor                 1,590                         1,935               2,276             2,743
           Non-Labor                23                            75                  75                29
           NSE                       0                             0                   0                 0
             Total               1,613                         2,010               2,351             2,772
             FTE                  22.6                          26.8                31.5              37.3
     2100-3627.000 CS TECHNOLOGY FIELD SYSTEMS
           Labor                     1                              0                   0                  0
           Non-Labor                 0                              0                   0                  0
           NSE                       0                              0                   0                  0
             Total                   1                              0                   0                  0
             FTE                   2.1                            2.2                 2.1                3.0




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 288 of 375
                  San Diego Gas & Electric Company
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                    Shared Services Workpapers




                  Beginning of Workpaper
  2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 289 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                               Shared Services Workpapers


Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub            1. Director of CS Technology Support
Cost Center:            2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT

Activity Description:
               The Director of Customer Services Systems & Technology provides oversight and policy
               determination for all departments within the organization. The Sr. Business Analyst provides
               budget/financial support to the entire organization. The Administrative Assistant provides partial
               administrative support to both utilities.
Forecast Methodology:

       Labor - 5-YR Average
              Year to year o&m expenses in Customer Services Systems & Technology can vary, up or
              down, due to charging capital & refundable programs and changes in staff. Utilizing a 5-year
              average neutralizes any fluctuations in expenses that occur in an exceptional year or years.
       Non-Labor - 5-YR Average
             Year to year o&m expenses in Customer Services Systems & Technology can vary, up or
             down, due to charging capital & refundable programs and changes in staff. Utilizing a 5-year
             average neutralizes any fluctuations in expenses that occur in an exceptional year or years.
       NSE - 5-YR Average
              N/A




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 290 of 375
                                       San Diego Gas & Electric Company
                                          Test Year 2012 GRC - APP
                                         Shared Services Workpapers


Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Director of CS Technology Support
Category-Sub          1. Director of CS Technology Support
Cost Center:          2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT

Summary of Results:

                                                        In 2009$ (000)
                                  Adjusted-Recorded                                Adjusted-Forecast
Years                 2005      2006      2007        2008       2009           2010     2011      2012
                                                  Total Incurred (100% Level)
Labor                  219      308        311        309         312           299       299      299
Non-Labor                19       13         16         14          14            15        15      15
NSE                       0        0          0          0           0             0         0       0
   Total               238      321        327        323         326           314       314      314
   FTE                  2.1      3.4        3.2        3.1         3.2           3.0       3.0     3.0
                                                        Allocations Out
Labor                  111      139        142        143         125           119       119      119
Non-Labor                10        6          7          7           5             6         6      6
NSE                       0        0          0          0           0             0         0      0
   Total               121      145        149        150         130           125       125      125
   FTE                  0.0      0.0        0.0        0.0         0.0           0.0       0.0     0.0
                                                             Retained
Labor                  108      169        169        166          187          180       180      180
Non-Labor                 9        7          9          7           9             9         9      9
NSE                       0        0          0          0           0             0         0      0
   Total               117      176        178        173         196           189       189      189
   FTE                  2.1      3.4        3.2        3.1         3.2           3.0       3.0     3.0
                                                         Allocations In
Labor                     0        0          0          0          0              0         0      0
Non-Labor                 0        0          0          0          0              0         0      0
NSE                       0        0          0          0          0              0         0      0
   Total                  0        0          0          0          0              0         0      0
   FTE                  0.0      0.0        0.0        0.0        0.0            0.0       0.0     0.0
                                                         Book Expense
Labor                  108      169        169        166        187            180       180      180
Non-Labor                 9        7          9          7          9              9         9      9
NSE                       0        0          0          0          0              0         0      0
   Total               117      176        178        173        196            189       189      189
   FTE                  2.1      3.4        3.2        3.1        3.2            3.0       3.0     3.0




                 SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                         Pages 291 of 375
                                                  San Diego Gas & Electric Company
                                                     Test Year 2012 GRC - APP
                                                    Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 B. Director of CS Technology Support
Category-Sub:             1. Director of CS Technology Support
Cost Center:              2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT


Calculation of Book Expense:

                                          2009 Adjusted-Recorded                               2010 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total    FTE
  Directly Retained                 0          0        0         0      0.00           0          0        0         0     0.00
  Directly Allocated                0         0         0           0    0.00           0         0         0           0   0.00
  Subj. To % Alloc.            312           14         0          326   3.20      299           15         0       314     3.00
  % Allocation
       Retained             59.97%       59.98%                                 59.97%       59.97%
       SEU                  40.03%       40.02%                                 40.03%       40.03%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained                187            9         0          196             180            9         0       189
       SEU                     125            5         0          130             119            6         0       125
       CORP                         0         0         0           0                   0         0         0           0
       Unreg                        0         0         0           0                   0         0         0           0
  Total Incurred               312           14         0          326   3.20      299           15         0       314     3.00
  Total Alloc. Out             125            5         0          130             119             6        0       125
  Total Retained               187            9         0          196             180             9        0       189
  Allocations In                    0         0         0            0                  0          0        0           0
  Book Expense                 187            9         0          196             180            9         0       189


                                          2011 Adjusted-Forecast                               2012 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total    FTE
  Directly Retained                 0         0         0           0    0.00           0         0         0           0   0.00
  Directly Allocated                0         0         0           0    0.00           0         0         0           0   0.00
  Subj. To % Alloc.            299           15         0          314   3.00      299           15         0       314     3.00
  % Allocation
       Retained             59.97%       59.97%                                 59.97%       59.97%
       SEU                  40.03%       40.03%                                 40.03%       40.03%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained                180            9         0          189             180            9         0       189
       SEU                     119            6         0          125             119            6         0       125
       CORP                         0         0         0           0                   0         0         0           0
       Unreg                        0         0         0           0                   0         0         0           0
  Total Incurred               299           15         0          314   3.00      299           15         0       314     3.00
  Total Alloc. Out             119            6         0          125             119             6        0       125
  Total Retained               180            9         0          189             180             9        0       189
  Allocations In                    0         0         0            0                  0          0        0           0
  Book Expense                 180            9         0          189             180            9         0       189




                       SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                               Pages 292 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                              Shared Services Workpapers



Area:                  CS - OFFICE OPERATIONS
Witness:               Rahon, J Steve
Category:              B. Director of CS Technology Support
Category-Sub:          1. Director of CS Technology Support
Cost Center:           2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT



Cost Center Allocation Percentage Drivers/Methodology:

    Cost Center Allocation Percentage for 2009
          The shared service allocation percentage is based on the overall headcount of the Customer Services
          Systems/Technology Support (CS S/T S) organization. The Director, Sr. Business Analyst and
          Administrative Assistant provide support throughout the organization. The Director of CS S/T S
          oversees and manages the Customer Services Staff organization that supports customer service field
          operations. The Sr. Business Analyst provides financial/budgetary analysis for both entities, and the
          Administrative Assistant provides staff services to both utilities. Non labor expense allocation is based
          on the same percentage as labor, The Director's, Sr. Business Analyst's, and Administrative
          Assistant's time is allocated based on the overall FTE's of the CS S/T S organization.


    Cost Center Allocation Percentage for 2010
          The shared service allocation percentage is based on the overall headcount of the Customer Services
          Systems/Technology Support (CS S/T S) organization. The Director, Sr. Business Analyst and
          Administrative Assistant provide support throughout the organization. The Director of CS S/T S
          oversees and manages the Customer Services Staff organization that supports customer service field
          operations. The Sr. Business Analyst provides financial/budgetary analysis for both entities, and the
          Administrative Assistant provides staff services to both utilities. Non labor expense allocation is based
          on the same percentage as labor, The Director's, Sr. Business Analyst's, and Administrative
          Assistant's time is allocated based on the overall FTE's of the CS S/T S organization.


    Cost Center Allocation Percentage for 2011
          The shared service allocation percentage is based on the overall headcount of the Customer Services
          Systems/Technology Support (CS S/T S) organization. The Director, Sr. Business Analyst and
          Administrative Assistant provide support throughout the organization. The Director of CS S/T S
          oversees and manages the Customer Services Staff organization that supports customer service field
          operations. The Sr. Business Analyst provides financial/budgetary analysis for both entities, and the
          Administrative Assistant provides staff services to both utilities. Non labor expense allocation is based
          on the same percentage as labor, The Director's, Sr. Business Analyst's, and Administrative
          Assistant's time is allocated based on the overall FTE's of the CS S/T S organization.


    Cost Center Allocation Percentage for 2012
          The shared service allocation percentage is based on the overall headcount of the Customer Services
          Systems/Technology Support (CS S/T S) organization. The Director, Sr. Business Analyst and
          Administrative Assistant provide support throughout the organization. The Director of CS S/T S
          oversees and manages the Customer Services Staff organization that supports customer service field
          operations. The Sr. Business Analyst provides financial/budgetary analysis for both entities, and the
          Administrative Assistant provides staff services to both utilities. Non labor expense allocation is based
          on the same percentage as labor, The Director's, Sr. Business Analyst's, and Administrative
          Assistant's time is allocated based on the overall FTE's of the CS S/T S organization.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 293 of 375
                                               San Diego Gas & Electric Company
                                                  Test Year 2012 GRC - APP
                                                 Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 B. Director of CS Technology Support
Category-Sub:             1. Director of CS Technology Support
Cost Center:              2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT

Forecast Summary:
                                                            In 2009 $(000) "Incurred Costs"
     Forecast Method                     Base Forecast                 Forecast Adjustments             Adjusted-Forecast
                                       2010        2011     2012       2010       2011    2012          2010    2011        2012
 Labor              5-YR Average       291           291        291           8     8         8         299      299        299
 Non-Labor          5-YR Average        15            15         15           0     0         0          15       15         15
 NSE                5-YR Average         0             0          0           0     0         0           0         0         0
 Total                                 306           306        306           8     8         8         314      314        314
 FTE                5-YR Average        3.0          3.0        3.0      0.0       0.0      0.0          3.0      3.0        3.0


Forecast Adjustment Details:
       Year/Expl.           Labor             NLbr         NSE        Total        FTE    Adj_Type

         2010                      8           0            0            8          0.0   1-Sided Adj

            Adjustment to compensate for 2 FTE's in 2005 to 3 employees from 2006-2009.

         2010 Total                8           0            0            8          0.0




         2011                      8           0            0            8          0.0   1-Sided Adj

            Adjustment to compensate for 2 FTE's in 2005 to 3 employees from 2006-2009.

         2011 Total                8           0            0            8          0.0




         2012                      8           0            0            8          0.0   1-Sided Adj

            Adjustment to compensate for 2 FTE's in 2005 to 3 employees from 2006-2009.

         2012 Total                8           0            0            8          0.0




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 294 of 375
                                            San Diego Gas & Electric Company
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                                              Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub:           1. Director of CS Technology Support
Cost Center:            2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT

Determination of Adjusted-Recorded (Incurred Costs):
                                2005 ($000)          2006 ($000)             2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                                 151                  178                257            262          271
     Non-Labor                               17                   11                 15             14           14
     NSE                                      0                    0                  0              0            0
         Total                             168                  190                273            276          284
         FTE                                1.4                  1.9                2.7            2.6          2.7
  Adjustments (Nominal $) **
     Labor                                  19                    65                -1              0            0
     Non-Labor                               0                     1                 0              0            0
     NSE                                     0                     0                 0              0            0
         Total                              19                    66                -1              0            0
         FTE                               0.3                   1.0               0.0            0.0          0.0
  Recorded-Adjusted (Nominal $)
     Labor                                 170                  244                256            262          271
     Non-Labor                               17                   12                 15             14           14
     NSE                                      0                    0                  0              0            0
          Total                            187                  256                271            276          284
          FTE                               1.8                  2.9                2.7            2.6          2.7
  Vacation & Sick (Nominal $)
     Labor                                  25                    39                38             43           42
     Non-Labor                               0                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
          Total                             25                    39                38             43           42
          FTE                              0.3                   0.5               0.5            0.5          0.5
  Escalation to 2009$
     Labor                                  25                    25                16              4            0
     Non-Labor                               2                     1                 1              0            0
     NSE                                     0                     0                 0              0            0
         Total                              27                    26                17              4            0
         FTE                               0.0                   0.0               0.0            0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                                 219                  308                311            309          312
     Non-Labor                               19                   13                 16             14           14
     NSE                                      0                    0                  0              0            0
         Total                             238                  321                327            323          326
         FTE                                2.1                  3.4                3.2            3.1          3.2



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 295 of 375
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                                              Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub:           1. Director of CS Technology Support
Cost Center:            2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT


Summary of Adjustments to Recorded:

                                                    In Nominal $ (000) "Incurred Costs"
 Year                                   2005            2006               2007           2008               2009
    Labor                                 19                65              -1                 0                0
    Non-Labor                           0.056             0.684          0.074                 0                0
    NSE                                    0                 0               0                 0                0
        Total                             19                66              -1                 0                0
    FTE                                   0.3               1.0            0.0                0.0             0.0


Detail of Adjustments to Recorded:

Year/Expl.      Labor        NLbr         NSE       FTE      Adj_Type    From CCtr                  RefID

2005               19               0           0   0.0 CCTR Transfer    From 2100-0040.000           SDALEY2010041
                                                                                                         5130810197
   Residential Services Organization has been restructured. Senior Business Analyst &
   Administrative Assistant labor & non-labor dollars should be moved from NSS cost
   center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
   align with current org.
2005                 0        0.056             0   0.0 CCTR Transfer    From 2100-0040.000           SDALEY2010041
                                                                                                         5133613367
   Residential Services Organization has been restructured. Senior Business Analyst &
   Administrative Assistant labor & non-labor dollars should be moved from NSS cost
   center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
   align with current org.
2005                 0              0           0   0.3 CCTR Transfer    From 2100-0040.000           SDALEY2010041
                                                                                                         5133638727
   Residential Services Organization has been restructured. Senior Business Analyst &
   Administrative Assistant labor & non-labor dollars should be moved from NSS cost
   center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
   align with current org.
2005 Total          19        0.056             0   0.3



2006               97               0           0   0.0 CCTR Transfer    From 2100-0040.000           SDALEY2010041
                                                                                                         5133819790
   Residential Services Organization has been restructured. Senior Business Analyst &
   Administrative Assistant labor & non-labor dollars should be moved from NSS cost
   center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
   align with current org.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 296 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                              Shared Services Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                B. Director of CS Technology Support
Category-Sub:            1. Director of CS Technology Support
Cost Center:             2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT


Year/Expl.       Labor         NLbr        NSE       FTE       Adj Type           From CCtr       RefID

2006                  0         0.684          0     0.0 CCTR Transfer      From 2100-0040.000   SDALEY2010041
                                                                                                    5133846587
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2006                  0             0          0     1.7 CCTR Transfer      From 2100-0040.000   SDALEY2010041
                                                                                                    5133906790
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2006                -31             0          0     0.0 CCTR Transf        To 2100-0040.000     SDALEY2010041
                                                                                                    9135400780
    Correction of Admin Assistant's labor that should remain in the Residential Services
    organization.
2006                  0             0          0    -0.7 CCTR Transf        To 2100-0040.000     SDALEY2010041
                                                                                                    9135426093
    Correction of Admin Assistant's labor that should remain in the Residential Services
    organization.
2006 Total           65         0.684          0     1.0



2007                  -1            0          0     0.0 CCTR Transfer      From 2100-0040.000   SDALEY2010041
                                                                                                    5134125493
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2007                  0         0.074          0     0.0 CCTR Transfer      From 2100-0040.000   SDALEY2010041
                                                                                                    5134151883
    Residential Services Organization has been restructured. Senior Business Analyst &
    Administrative Assistant labor & non-labor dollars should be moved from NSS cost
    center 2100-0040 into USS cost center 2100-0027 Director Customer Service & Staff to
    align with current org.
2007 Total            -1        0.074          0     0.0



2008 Total            0             0          0     0.0




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 297 of 375
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Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub:           1. Director of CS Technology Support
Cost Center:            2100-0027.000 - DIRECTOR CS TECHNOLOGY SUPPORT


Year/Expl.      Labor        NLbr     NSE     FTE    Adj Type        From CCtr   RefID

2009 Total          0            0       0    0.0




                 SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                         Pages 298 of 375
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                  Beginning of Workpaper
        2100-0642.000 - CS TECHNOLOGY MANAGER




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 299 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                              Shared Services Workpapers


Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub            1. Director of CS Technology Support
Cost Center:            2100-0642.000 - CS TECHNOLOGY MANAGER

Activity Description:
               The STS - South Team provides overall maintenance support for various business applications
               within the utilities. These applications are mission critical to the customer service line
               organizations and back office operations. Business clients rely on the functional support
               provided by the customer services applications for measuring gas consumption, billing, posting
               payments, collections, and service orders issued to utility customers.
Forecast Methodology:

       Labor - 5-YR Average
              Year to year o&m expenses in Customer Services Systems & Technology can vary, up or
              down, due to charging capital & refundable programs and changes in staff. Utilizing a 5-year
              average neutralizes any fluctuations in expenses that occur in an exceptional year or years.
       Non-Labor - 5-YR Average
             Year to year o&m expenses in Customer Services Systems & Technology can vary, up or
             down, due to charging capital & refundable programs and changes in staff. Utilizing a 5-year
             average neutralizes any fluctuations in expenses that occur in an exceptional year or years.
       NSE - 5-YR Average
              N/A




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 300 of 375
                                       San Diego Gas & Electric Company
                                          Test Year 2012 GRC - APP
                                         Shared Services Workpapers


Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Director of CS Technology Support
Category-Sub          1. Director of CS Technology Support
Cost Center:          2100-0642.000 - CS TECHNOLOGY MANAGER

Summary of Results:

                                                        In 2009$ (000)
                                  Adjusted-Recorded                               Adjusted-Forecast
Years                 2005      2006      2007        2008        2009        2010      2011      2012
                                                  Total Incurred (100% Level)
Labor                 1,656    1,721      1,726     1,466       1,628         1,980     2,329    2,807
Non-Labor                48       71         42          47          24         77         77      30
NSE                       0        0          0           0           0          0          0       0
   Total              1,704    1,792      1,768       1,513       1,652      2,057      2,406    2,837
   FTE                 23.2     24.4       24.4        20.8        22.6       26.8       31.5     37.3
                                                          Allocations Out
Labor                     0       29         38          72          38          45        53     64
Non-Labor                 0        1          1           2           1           2         2      1
NSE                       0        0          0           0           0           0         0      0
   Total                  0       30         39          74          39          47        55     65
   FTE                  0.0      0.0        0.0         0.0         0.0         0.0       0.0     0.0
                                                              Retained
Labor                 1,656    1,692      1,688       1,394       1,590      1,935      2,276    2,743
Non-Labor                48       70         41          45          23         75         75      29
NSE                       0        0          0           0           0          0          0       0
   Total              1,704    1,762      1,729       1,439       1,613      2,010      2,351    2,772
   FTE                 23.2     24.4       24.4        20.8        22.6       26.8       31.5     37.3
                                                          Allocations In
Labor                     0        0          0           0          0            0         0      0
Non-Labor                 0        0          0           0          0            0         0      0
NSE                       0        0          0           0          0            0         0      0
   Total                  0        0          0           0          0            0         0      0
   FTE                  0.0      0.0        0.0         0.0        0.0          0.0       0.0     0.0
                                                          Book Expense
Labor                 1,656    1,692      1,688       1,394     1,590        1,935      2,276    2,743
Non-Labor                48       70         41          45        23           75         75      29
NSE                       0        0          0           0         0            0          0       0
   Total              1,704    1,762      1,729       1,439     1,613        2,010      2,351    2,772
   FTE                 23.2     24.4       24.4        20.8      22.6         26.8       31.5     37.3




                 SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                         Pages 301 of 375
                                                  San Diego Gas & Electric Company
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Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 B. Director of CS Technology Support
Category-Sub:             1. Director of CS Technology Support
Cost Center:              2100-0642.000 - CS TECHNOLOGY MANAGER


Calculation of Book Expense:

                                          2009 Adjusted-Recorded                               2010 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total     FTE     Labor       Non-Labor     NSE      Total      FTE
  Directly Retained             69             0        0        69     0.80            0          0        0         0       0.20
  Directly Allocated                0         0         0          0     0.00           0         0         0           0     0.00
  Subj. To % Alloc.          1,559           24         0     1,583     21.80    1,980           77         0     2,057      26.60
  % Allocation
       Retained             97.57%       97.57%                                 97.73%       97.73%
       SEU                   2.43%        2.43%                                  2.27%        2.27%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained               1,521          23         0     1,544              1,935           75         0     2,010
       SEU                      38            1         0          39               45            2         0           47
       CORP                         0         0         0          0                    0         0         0           0
       Unreg                        0         0         0          0                    0         0         0           0
  Total Incurred             1,628           24         0      1,652    22.60     1,980          77         0      2,057     26.80
  Total Alloc. Out              38            1         0          39               45             2        0           47
  Total Retained             1,590           23         0      1,613              1,935          75         0      2,010
  Allocations In                    0         0         0           0                   0          0        0            0
  Book Expense               1,590           23         0     1,613              1,935           75         0     2,010


                                          2011 Adjusted-Forecast                               2012 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total      FTE
  Directly Retained                 0         0         0          0     0.20           0         0         0           0     0.20
  Directly Allocated                0         0         0          0     0.00           0         0         0           0     0.00
  Subj. To % Alloc.          2,329           77         0     2,406     31.30    2,807           30         0     2,837      37.10
  % Allocation
       Retained             97.73%       97.73%                                 97.73%       97.73%
       SEU                   2.27%        2.27%                                  2.27%        2.27%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained               2,276          75         0     2,351              2,743           29         0     2,772
       SEU                      53            2         0          55               64            1         0           65
       CORP                         0         0         0          0                    0         0         0           0
       Unreg                        0         0         0          0                    0         0         0           0
  Total Incurred             2,329           77         0      2,406    31.50     2,807          30         0      2,837     37.30
  Total Alloc. Out              53            2         0          55               64             1        0           65
  Total Retained             2,276           75         0      2,351              2,743          29         0      2,772
  Allocations In                    0         0         0           0                   0          0        0            0
  Book Expense               2,276           75         0     2,351              2,743           29         0     2,772




                       SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                               Pages 302 of 375
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Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Director of CS Technology Support
Category-Sub:         1. Director of CS Technology Support
Cost Center:          2100-0642.000 - CS TECHNOLOGY MANAGER



Cost Center Allocation Percentage Drivers/Methodology:

    Cost Center Allocation Percentage for 2009
          The STS - South Team primarily provides overall maintenance support for SDG&E applications
          except one FTE jointly supports the iAvenue software package for both companies. The cost center
          costs are allocated based on FTE count.


    Cost Center Allocation Percentage for 2010
          The STS - South Team primarily provides overall maintenance support for SDG&E applications
          except one FTE jointly supports the iAvenue software package. The cost center costs are allocated
          based on FTE count.


    Cost Center Allocation Percentage for 2011
          The STS - South Team primarily provides overall maintenance support for SDG&E applications
          except one FTE jointly supports the iAvenue software package. The cost center costs are allocated
          based on FTE count.


    Cost Center Allocation Percentage for 2012
          The STS - South Team primarily provides overall maintenance support for SDG&E applications
          except one FTE jointly supports the iAvenue software package. The cost center costs are allocated
          based on FTE count.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 303 of 375
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                                                  Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 B. Director of CS Technology Support
Category-Sub:             1. Director of CS Technology Support
Cost Center:              2100-0642.000 - CS TECHNOLOGY MANAGER

Forecast Summary:
                                                              In 2009 $(000) "Incurred Costs"
     Forecast Method                      Base Forecast                  Forecast Adjustments              Adjusted-Forecast
                                       2010          2011     2012      2010       2011      2012         2010     2011        2012
 Labor              5-YR Average       1,638         1,638   1,638       342       691      1,169         1,980    2,329   2,807
 Non-Labor          5-YR Average         46            46         46      31        31        -16           77       77         30
 NSE                5-YR Average          0             0          0           0      0          0           0         0         0
 Total                                 1,684         1,684   1,684       373       722      1,153         2,057    2,406   2,837
 FTE                5-YR Average        23.0          23.0    23.0        3.8       8.5      14.3          26.8     31.5       37.3


Forecast Adjustment Details:
       Year/Expl.           Labor              NLbr          NSE       Total        FTE     Adj_Type

         2010                      0           -16            0         -16          0.0    1-Sided Adj

           Tru up the 5 year average to the projected 2010 plan.

         2010                      0            0             0           0          3.3    1-Sided Adj

           Full year effect of current staff, pay equity increases, upgraded technical positions and
           employees returning from Capital/Refundable projects.

         2010                  38               0             0          38          0.0    1-Sided Adj

           1 Business Systems Analyst to support OpEx SVOC, Direct Access and
           MyAccount/Eservices increased functionality. Estimated start date 7/1/10.

         2010                      0            0             0           0          0.5    1-Sided Adj

           1 Business Systems Analyst to support OpEx SVOC, Direct Access and
           MyAccount/Eservices increased functionality. Estimated start date 7/1/10.

         2010                      0           47             0          47          0.0    1-Sided Adj

           Contract employee to fulfill impending work requests due to the DW database being updated
           to SQL server and a technical requirement for teh STS repoting server to be upgraded and
           reprogramming of over 60 reporting extracts due to the upgrade. The contract will begin on
           July 1st, 2010 and end on June 30, 2011.

         2010                  -18              0             0         -18          0.0    SSD_Type Transf

           Entire Cost Center subject to allocation.

         2010                  18               0             0          18          0.0    SSD_Type Transf

           Entire Cost Center subject to allocation.




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 304 of 375
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Area:                  CS - OFFICE OPERATIONS
Witness:               Rahon, J Steve
Category:              B. Director of CS Technology Support
Category-Sub:          1. Director of CS Technology Support
Cost Center:           2100-0642.000 - CS TECHNOLOGY MANAGER

      Year/Expl.         Labor            NLbr          NSE       Total         FTE   Adj Type

      2010                   304              0               0      304           0.0    1-Sided Adj

         Full year effect of current staff, pay equity increases, upgraded technical positions and
         employees returning from Capital/Refundable projects.

      2010 Total             342             31               0      373           3.8




      2011                     0            -16               0      -16           0.0    1-Sided Adj

         Tru up the 5 year average to the 2010 plan.

      2011                     0              0               0           0        3.3    1-Sided Adj

         Full year effect of current staff, pay equity increases, upgraded technical positions and
         employees returning from Capital/Refundable projects.

      2011                    75              0               0       75           0.0    1-Sided Adj

         Full year effect for 1 Business Systems Analyst to support OpEx SVOC, Direct Access and
         MyAccount/Eservices increased functionality.

      2011                     0              0               0           0        1.0    1-Sided Adj

         Full year effect for 1 Business Systems Analyst to support OpEx SVOC, Direct Access and
         MyAccount/Eservices increased functionality.

      2011                     0             47               0       47           0.0    1-Sided Adj

         Contract employee to fulfill impending work requests due to the DW database being updated
         to SQL server and a technical requirement for teh STS repoting server to be upgraded and
         reprogramming of over 60 reporting extracts due to the upgrade. The contract will begin on
         July 1st, 2010 and end on June 30, 2011.

      2011                   -18              0               0      -18           0.0    SSD_Type Transf

         Entire cost center is subject to allocation.

      2011                    18              0               0       18           0.0    SSD_Type Transf

         Entire cost center is subject to allocation.

      2011                   150              0               0      150           0.0    1-Sided Adj

         2 Business Systems analysts to support Direct Access & MyAccount / Eservices.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 305 of 375
                                            San Diego Gas & Electric Company
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Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Director of CS Technology Support
Category-Sub:         1. Director of CS Technology Support
Cost Center:          2100-0642.000 - CS TECHNOLOGY MANAGER

      Year/Expl.         Labor           NLbr       NSE          Total          FTE   Adj Type

      2011                     0             0            0              0         2.0    1-Sided Adj

         2 Business Systems analysts to support Direct Access & MyAccount / Eservices.

      2011                   87              0            0           87           0.0    1-Sided Adj

         2 Business Systems Analysts returning from Smart Meter capital/refundable on 6/1/2011 for
         ongoing maintenance & support to Data Warehouse - Smart Meter reporting, online bill
         presentment, measurement, service orders and new processes for customer billing.

      2011                     0             0            0              0         1.2    1-Sided Adj

         2 Business Systems Analysts returning from Smart Meter capital/refundable on 6/1/2011 for
         ongoing maintenance & support to Data Warehouse - Smart Meter reporting, online bill
         presentment, measurement, service orders and new processes for customer billing.

      2011                  304              0            0          304           0.0    1-Sided Adj

         Full year effect of current staff, pay equity increases, upgraded technical positions and
         employees returning from Capital/Refundable projects.

      2011                   75              0            0           75           0.0    1-Sided Adj

         1 Business Systems Analyst at $75K for support and maintenance of OpEx 20/20 CISCO
         applications.

      2011                     0             0            0              0         1.0    1-Sided Adj

         1 Business Systems Analyst at $75K for support and maintenance of OpEx 20/20 CISCO
         applications.

      2011 Total            691            31             0          722           8.5




      2012                     0           -16            0          -16           0.0    1-Sided Adj

         Tru up the 5 yr average to the projected 2010 plan.

      2012                     0             0            0              0         3.3    1-Sided Adj

         Full year effect of current staff, pay equity increases, upgraded technical positions and
         employees returning from Capital/Refundable projects.

      2012                   75              0            0           75           0.0    1-Sided Adj

         Full year effect for 1 Business Systems Analyst to support OpEx SVOC, Direct Access and
         MyAccount/Eservices increased functionality.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 306 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                               Shared Services Workpapers



Area:                  CS - OFFICE OPERATIONS
Witness:               Rahon, J Steve
Category:              B. Director of CS Technology Support
Category-Sub:          1. Director of CS Technology Support
Cost Center:           2100-0642.000 - CS TECHNOLOGY MANAGER

      Year/Expl.         Labor            NLbr          NSE       Total       FTE   Adj Type

      2012                     0              0               0           0     1.0   1-Sided Adj

         Full year effect for 1 Business Systems Analyst to support OpEx SVOC, Direct Access and
         MyAccount/Eservices increased functionality.

      2012                   -18              0               0      -18        0.0   SSD_Type Transf

         Entire cost center is subject to allocation.

      2012                    18              0               0       18        0.0   SSD_Type Transf

         Entire cost center is subject to allocation.

      2012                   150              0               0      150        0.0   1-Sided Adj

         2 Business Systems analysts to support Direct Access & MyAccount / Eservices.

      2012                     0              0               0           0     2.0   1-Sided Adj

         2 Business Systems analysts to support Direct Access & MyAccount / Eservices.

      2012                   150              0               0      150        0.0   1-Sided Adj

         Full year effect of 2 Business Systems Analysts returning from Smart Meter
         capital/refundable on 6/1/2011 for ongoing maintenance & support to Data Warehouse -
         Smart Meter reporting, online bill presentment, measurement, service orders and new
         processes for customer billing.

      2012                     0              0               0           0     2.0   1-Sided Adj

         Full year effect of 2 Business Systems Analysts returning from Smart Meter
         capital/refundable on 6/1/2011 for ongoing maintenance & support to Data Warehouse -
         Smart Meter reporting, online bill presentment, measurement, service orders and new
         processes for customer billing.

      2012                   385              0               0      385        0.0   1-Sided Adj

         1 Technical Advisor & 4 Business Systems Analysts returning from Smart Meter
         capital/refundable for ongoing maintenance support will be required to support both Smart
         Meter and non Smart Meter related processes. The complexity of various Smart Meter
         interfaces creates testing challenges for both enhancements and maintenance support.

      2012                     0              0               0           0     5.0   1-Sided Adj

         1 Technical Advisor & 4 Business Systems Analysts returning from Smart Meter
         capital/refundable for ongoing maintenance support will be required to support both Smart
         Meter and non Smart Meter related processes. The complexity of various Smart Meter
         interfaces creates testing challenges for both enhancements and maintenance support.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 307 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                              Shared Services Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Director of CS Technology Support
Category-Sub:         1. Director of CS Technology Support
Cost Center:          2100-0642.000 - CS TECHNOLOGY MANAGER

      Year/Expl.         Labor           NLbr       NSE          Total          FTE   Adj Type

      2012                  304              0            0          304           0.0    1-Sided Adj

         Full year effect of current staff, pay equity increases, upgraded technical positions and
         employees returning from Capital/Refundable projects.

      2012                   30              0            0           30           0.0    1-Sided Adj

         Salary differential as a result of the promotion of 3 Business Systems Analysts to Technical
         Advisors ($10K each)

      2012                   75              0            0           75           0.0    1-Sided Adj

         1 Business Systems Analyst at $75K for support and maintenance of OpEx 20/20 CISCO
         applications.

      2012                     0             0            0              0         1.0    1-Sided Adj

         1 Business Systems Analyst at $75K for support and maintenance of OpEx 20/20 CISCO
         applications.

      2012 Total          1,169            -16            0        1,153          14.3




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 308 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                              Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub:           1. Director of CS Technology Support
Cost Center:            2100-0642.000 - CS TECHNOLOGY MANAGER

Determination of Adjusted-Recorded (Incurred Costs):
                                2005 ($000)          2006 ($000)             2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                                 808                1,234              1,425          1,243        1,411
     Non-Labor                              19                   55                 40             47           24
     NSE                                     0                    0                  0              0            0
         Total                             826                1,289              1,464          1,290        1,435
         FTE                              12.9                 18.8               20.9           17.6         19.3
  Adjustments (Nominal $) **
     Labor                                 477                  128                 -2              0            0
     Non-Labor                               24                   10                 0              0            0
     NSE                                      0                    0                 0              0            0
         Total                             502                  139                 -2              0            0
         FTE                                7.0                  2.1               0.0            0.0          0.0
  Recorded-Adjusted (Nominal $)
     Labor                               1,285                1,362              1,423          1,243        1,411
     Non-Labor                              43                   66                 40             46           24
     NSE                                     0                    0                  0              0            0
          Total                          1,328                1,428              1,463          1,289        1,435
          FTE                             19.9                 20.9               20.9           17.6         19.4
  Vacation & Sick (Nominal $)
     Labor                                 185                  219                213            204          218
     Non-Labor                                0                    0                  0              0            0
     NSE                                      0                    0                  0              0            0
          Total                            185                  219                213            204          218
          FTE                               3.3                  3.5                3.5            3.2          3.2
  Escalation to 2009$
     Labor                                 185                  140                 91             19            0
     Non-Labor                                5                    6                 2              1            0
     NSE                                      0                    0                 0              0            0
         Total                             191                  146                 93             20            0
         FTE                                0.0                  0.0               0.0            0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                               1,656                1,721              1,727          1,466        1,629
     Non-Labor                              48                   71                 42             47           24
     NSE                                     0                    0                  0              0            0
         Total                           1,704                1,792              1,769          1,513        1,653
         FTE                              23.2                 24.4               24.4           20.8         22.6



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 309 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                             Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub:           1. Director of CS Technology Support
Cost Center:            2100-0642.000 - CS TECHNOLOGY MANAGER


Summary of Adjustments to Recorded:

                                                   In Nominal $ (000) "Incurred Costs"
 Year                                   2005           2006               2007            2008              2009
    Labor                               477              128               -2                 0                0
    Non-Labor                            24               10                0            -0.491                0
    NSE                                   0                0                0                 0                0
        Total                           502              139               -2            -0.491                0
    FTE                                  7.0             2.1              0.0                0.0             0.0


Detail of Adjustments to Recorded:

Year/Expl.      Labor        NLbr        NSE       FTE    Adj_Type      From CCtr                  RefID

2005              483               0          0   0.0 CCTR Transf      From 2100-0038.000           SDALEY2009092
                                                                                                        1130000940
   Cost center 2100-0038 (Customer Service Technology) was reorganized in 2006 and
   split between 2100-0642 (Customer Operations Technology) and 2100-3584
   (CST-SORT)
2005                 0          24             0   0.0 CCTR Transf      From 2100-0038.000           SDALEY2009092
                                                                                                        1131408517
   Cost center 2100-0038 (Customer Service Technology) was reorganized in 2006 and
   split between 2100-0642 (Customer Operations Technology) and 2100-3584
   (CST-SORT)
2005                 0              0          0   7.1 CCTR Transf      From 2100-0038.000           SDALEY2009092
                                                                                                        1131749443
   Cost center 2100-0038 (Customer Service Technology) was reorganized in 2006 and
   split between 2100-0642 (Customer Operations Technology) and 2100-3584
   (CST-SORT)
2005                -5              0          0   0.0 CCTR Transf      From 2100-0038.000           SDALEY2009092
                                                                                                        1141939123
   Cost center 2100-0038 (Customer Service Technology) was reorganized in 2006 and
   split between 2100-0642 (Customer Operations Technology) and 2100-3584
   (CST-SORT)
2005                 0              0          0   -0.1 CCTR Transf     From 2100-0038.000           SDALEY2009092
                                                                                                        1142254380
   Cost center 2100-0038 (Customer Service Technology) was reorganized in 2006 and
   split between 2100-0642 (Customer Operations Technology) and 2100-3584
   (CST-SORT)




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 310 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                             Shared Services Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                B. Director of CS Technology Support
Category-Sub:            1. Director of CS Technology Support
Cost Center:             2100-0642.000 - CS TECHNOLOGY MANAGER


Year/Expl.       Labor        NLbr        NSE       FTE      Adj Type         From CCtr       RefID
2005                  0        0.187          0     0.0 CCTR Transf     From 2100-0038.000   SDALEY2009092
                                                                                                1142411050
    Cost center 2100-0038 (Customer Service Technology) was reorganized in 2006 and
    split between 2100-0642 (Customer Operations Technology) and 2100-3584
    (CST-SORT)
2005                  0        0.002          0     0.0 CCTR Transf     From 2100-0038.000   SDALEY2009092
                                                                                                1142518570
    Cost center 2100-0038 (Customer Service Technology) was reorganized in 2006 and
    split between 2100-0642 (Customer Operations Technology) and 2100-3584
    (CST-SORT)
2005 Total          477           24          0     7.0



2006               128             0          0     0.0 CCTR Transf     From 2100-0038.000   SDALEY2009092
                                                                                                1132137870
    Cost center 2100-0038 (Customer Service Technology) was reorganized in 2006 and
    split between 2100-0642 (Customer Operations Technology) and 2100-3584
    (CST-SORT)
2006                  0           10          0     0.0 CCTR Transf     From 2100-0038.000   SDALEY2009092
                                                                                                1132710907
    Cost center 2100-0038 (Customer Service Technology) was reorganized in 2006 and
    split between 2100-0642 (Customer Operations Technology) and 2100-3584
    (CST-SORT)
2006                  0            0          0     2.1 CCTR Transf     From 2100-0038.000   SDALEY2009092
                                                                                                1132927300
    Cost center 2100-0038 (Customer Service Technology) was reorganized in 2006 and
    split between 2100-0642 (Customer Operations Technology) and 2100-3584
    (CST-SORT)
2006 Total          128           10          0     2.1



2007                 -2            0          0     0.0 1-Sided Adj     N/A                  SDALEY2009091
                                                                                                4133708650
    Refundable under I/O 7023420 - Ca. Solar Initiative D. 06-08-028

2007 Total           -2            0          0     0.0



2008                  0       -0.491          0     0.0 1-Sided Adj     N/A                  SDALEY2009092
                                                                                                9071945197
    CEMA - To remove incremental firestorm costs requested in CEMA for recovery.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 311 of 375
                                       San Diego Gas & Electric Company
                                          Test Year 2012 GRC - APP
                                         Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub:           1. Director of CS Technology Support
Cost Center:            2100-0642.000 - CS TECHNOLOGY MANAGER


Year/Expl.      Labor        NLbr     NSE     FTE    Adj Type        From CCtr   RefID

2008 Total          0        -0.491      0    0.0



2009 Total          0            0       0    0.0




                 SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                         Pages 312 of 375
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                 Beginning of Workpaper
     2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 313 of 375
                                             San Diego Gas & Electric Company
                                                Test Year 2012 GRC - APP
                                               Shared Services Workpapers


Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub            1. Director of CS Technology Support
Cost Center:            2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS

Activity Description:
               The Customer Service Technology Supervisors provide oversight and management to the CS
               Technology - Art and CST-PACER cost centers at SoCalGas and the Business Analyst
               oversees the operating budgets and provides project cost summaries for the following groups
               at SDG&E - CST SORT, Customer Services Field Systems & Projects and the following groups
               at SoCalGas - CST-PACER, Customer Operations Technology.
Forecast Methodology:

       Labor - 4-YR Average
              The four year historical average is appropriate, as it accurately reflects the support staff housed
              within and their level of activity on an ongoing basis.
       Non-Labor - 4-YR Average
             The four year historical average is appropriate, as it accurately reflects the support staff housed
             within and their level of activity on an ongoing basis.
       NSE - 4-YR Average
              N/A




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 314 of 375
                                       San Diego Gas & Electric Company
                                          Test Year 2012 GRC - APP
                                         Shared Services Workpapers


Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Director of CS Technology Support
Category-Sub          1. Director of CS Technology Support
Cost Center:          2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS

Summary of Results:

                                                        In 2009$ (000)
                                  Adjusted-Recorded                                Adjusted-Forecast
Years                 2005      2006      2007        2008       2009           2010     2011      2012
                                                  Total Incurred (100% Level)
Labor                     0       23       195        171         185           194       176      288
Non-Labor                 0        1         15         27           7             6         7      6
NSE                       0        0          0          0           0             0         0      0
   Total                  0       24       210        198         192           200       183      294
   FTE                  0.0      0.2        2.3        2.0         2.1           2.2       2.1     3.0
                                                         Allocations Out
Labor                     0        5       141        108          184          194       176      288
Non-Labor                 0        0         11         23            7            6         7      6
NSE                       0        0          0          0            0            0         0      0
   Total                  0        5       152        131          191          200       183      294
   FTE                  0.0      0.0        0.0        0.0          0.0          0.0       0.0     0.0
                                                             Retained
Labor                     0       18         54         63           1             0         0      0
Non-Labor                 0        1          4          4           0             0         0      0
NSE                       0        0          0          0           0             0         0      0
   Total                  0       19         58         67           1             0         0      0
   FTE                  0.0      0.2        2.3        2.0         2.1           2.2       2.1     3.0
                                                         Allocations In
Labor                     0        0          0          0          0              0         0      0
Non-Labor                 0        0          0          0          0              0         0      0
NSE                       0        0          0          0          0              0         0      0
   Total                  0        0          0          0          0              0         0      0
   FTE                  0.0      0.0        0.0        0.0        0.0            0.0       0.0     0.0
                                                         Book Expense
Labor                     0       18         54         63         1               0         0      0
Non-Labor                 0        1          4          4         0               0         0      0
NSE                       0        0          0          0         0               0         0      0
   Total                  0       19         58         67         1               0         0      0
   FTE                  0.0      0.2        2.3        2.0       2.1             2.2       2.1     3.0




                 SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                         Pages 315 of 375
                                                  San Diego Gas & Electric Company
                                                     Test Year 2012 GRC - APP
                                                    Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 B. Director of CS Technology Support
Category-Sub:             1. Director of CS Technology Support
Cost Center:              2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS


Calculation of Book Expense:

                                          2009 Adjusted-Recorded                               2010 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total    FTE
  Directly Retained                 0          0        0         0      0.00           0          0        0         0     0.00
  Directly Allocated                0         0         0           0    0.00           0         0         0           0   0.00
  Subj. To % Alloc.            185            7         0          192   2.10       194           6         0       200     2.20
  % Allocation
       Retained              0.45%        0.30%                                  0.00%        0.00%
       SEU                  99.55%       99.70%                                 100.00%     100.00%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained                     1         0         0           1                   0         0         0           0
       SEU                     184            7         0          191              194           6         0       200
       CORP                         0         0         0           0                   0         0         0           0
       Unreg                        0         0         0           0                   0         0         0           0
  Total Incurred               185            7         0          192   2.10       194            6        0       200     2.20
  Total Alloc. Out             184            7         0          191              194            6        0       200
  Total Retained                    1         0         0            1                  0          0        0           0
  Allocations In                    0         0         0            0                  0          0        0           0
  Book Expense                      1         0         0           1                   0         0         0           0


                                          2011 Adjusted-Forecast                               2012 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total    FTE
  Directly Retained                 0         0         0           0    0.00           0         0         0           0   0.00
  Directly Allocated                0         0         0           0    0.00           0         0         0           0   0.00
  Subj. To % Alloc.            176            7         0          183   2.10       288           6         0       294     3.00
  % Allocation
       Retained              0.00%        0.00%                                  0.00%        0.00%
       SEU                 100.00%      100.00%                                 100.00%     100.00%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained                     0         0         0           0                   0         0         0           0
       SEU                     176            7         0          183              288           6         0       294
       CORP                         0         0         0           0                   0         0         0           0
       Unreg                        0         0         0           0                   0         0         0           0
  Total Incurred               176            7         0          183   2.10       288            6        0       294     3.00
  Total Alloc. Out             176            7         0          183              288            6        0       294
  Total Retained                    0         0         0            0                  0          0        0           0
  Allocations In                    0         0         0            0                  0          0        0           0
  Book Expense                      0         0         0           0                   0         0         0           0




                       SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                               Pages 316 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                            Shared Services Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Director of CS Technology Support
Category-Sub:         1. Director of CS Technology Support
Cost Center:          2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS



Cost Center Allocation Percentage Drivers/Methodology:

    Cost Center Allocation Percentage for 2009
          The allocation percentage is based on the FTE's the CS Technology siupervisor and the CST PACER
          employee supporton a day to day basis. The CO Technology Supervisor is exclusively responsible for
          managing the entire staff and all associated activities related to in the CO Technology - ART cost
          center (2200-2255) at SCG. As a result, she is allocated at 100% to SCG. The CST PACER
          supervisor is exclusively assigned to in the CST PACER cost center (2200-0343) at SCG. As a result,
          both positions are 100% allocated to SCG.


    Cost Center Allocation Percentage for 2010
          The allocation percentage is based on the FTE's the CS Technology siupervisor and the CST PACER
          employee supporton a day to day basis. The CO Technology Supervisor is exclusively responsible for
          managing the entire staff and all associated activities related to in the CO Technology - ART cost
          center (2200-2255) at SCG. As a result, she is allocated at 100% to SCG. The CST PACER
          supervisor is exclusively assigned to in the CST PACER cost center (2200-0343) at SCG. As a result,
          both positions are 100% allocated to SCG.


    Cost Center Allocation Percentage for 2011
          The allocation percentage is based on the FTE's the CS Technology siupervisor and the CST PACER
          employee supporton a day to day basis. The CO Technology Supervisor is exclusively responsible for
          managing the entire staff and all associated activities related to in the CO Technology - ART cost
          center (2200-2255) at SCG. As a result, she is allocated at 100% to SCG. The CST PACER
          supervisor is exclusively assigned to in the CST PACER cost center (2200-0343) at SCG. As a result,
          both positions are 100% allocated to SCG.


    Cost Center Allocation Percentage for 2012
          The allocation percentage is based on the FTE's the CS Technology siupervisor and the CST PACER
          employee supporton a day to day basis. The CO Technology Supervisor is exclusively responsible for
          managing the entire staff and all associated activities related to in the CO Technology - ART cost
          center (2200-2255) at SCG. As a result, she is allocated at 100% to SCG. The CST PACER
          supervisor is exclusively assigned to in the CST PACER cost center (2200-0343) at SCG. As a result,
          both positions are 100% allocated to SCG.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 317 of 375
                                                  San Diego Gas & Electric Company
                                                     Test Year 2012 GRC - APP
                                                    Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 B. Director of CS Technology Support
Category-Sub:             1. Director of CS Technology Support
Cost Center:              2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS

Forecast Summary:
                                                               In 2009 $(000) "Incurred Costs"
     Forecast Method                      Base Forecast                   Forecast Adjustments             Adjusted-Forecast
                                       2010            2011    2012       2010       2011    2012          2010    2011        2012
 Labor              4-YR Average        143            143         143      51        33       145         194      176        288
 Non-Labor          4-YR Average         11             11          11       -5        -4          -5        6         7         6
 NSE                4-YR Average          0              0           0           0     0           0         0         0         0
 Total                                  154            154         154      46        29       140         200      183        294
 FTE                4-YR Average        1.7             1.7        1.7      0.5       0.4      1.3          2.2      2.1        3.0


Forecast Adjustment Details:
       Year/Expl.           Labor             NLbr            NSE        Total        FTE    Adj_Type

         2010                      0              -3           0            -3         0.0   SSD_Type Transf

            All expenses subject to allocation.

         2010                      0              3            0            3          0.0   SSD_Type Transf

            All expenses subject to allocation.

         2010                   33                0            0           33          0.0   1-Sided Adj

            Full Year adjustment to reflect actual current staffing levels and related expenses.

         2010                      0              0            0            0          0.3   1-Sided Adj

            Full Year adjustment to reflect actual current staffing levels and related expenses.

         2010                   18                0            0           18          0.0   1-Sided Adj

            Transfer of a Sup position previously budgeted and charged to c/c 2200-0343. The employee
            is as SDG&E employee from IT who will be supervising and fully assigned to 2200-0343. He
            will be allocated at 100% to SCG.

         2010                      0              0            0            0          0.2   1-Sided Adj

            Transfer of a Sup position previously budgeted and charged to c/c 2200-0343. The employee
            is as SDG&E employee from IT who will be supervising and fully assigned to 2200-0343. He
            will be allocated at 100% to SCG.

         2010                      0              -5           0            -5         0.0   1-Sided Adj

            Tru up of the 4 yr average to the 2010 plan.

         2010 Total             51                -5           0           46          0.5




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 318 of 375
                                               San Diego Gas & Electric Company
                                                  Test Year 2012 GRC - APP
                                                 Shared Services Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Director of CS Technology Support
Category-Sub:         1. Director of CS Technology Support
Cost Center:          2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS

      Year/Expl.        Labor            NLbr        NSE         Total         FTE    Adj Type



      2011                    0                -3          0             -3        0.0   SSD_Type Transf

         All expenses subject to allocation.

      2011                    0                3           0             3         0.0   SSD_Type Transf

         All expenses subject to allocation.

      2011                   33                0           0          33           0.0   1-Sided Adj

         Full Year adjustment to reflect actual current staffing levels and related expenses.

      2011                    0                0           0             0         0.4   1-Sided Adj

         Full Year adjustment to reflect actual current staffing levels and related expenses.

      2011                    0                -4          0             -4        0.0   1-Sided Adj

         Tru up of the 4 yr average to the 2010 plan.

      2011 Total             33                -4          0          29           0.4




      2012                    0                -3          0             -3        0.0   SSD_Type Transf

         All expenses subject to allocation.

      2012                    0                3           0             3         0.0   SSD_Type Transf

         All expenses subject to allocation.

      2012                   33                0           0          33           0.0   1-Sided Adj

         Full Year adjustment to reflect actual current staffing levels and related expenses.

      2012                    0                0           0             0         0.3   1-Sided Adj

         Full Year adjustment to reflect actual current staffing levels and related expenses.

      2012                  112                0           0        112            0.0   1-Sided Adj

         Transfer of a Sup position previously budgeted and charged to c/c 2200-0343. The employee
         is as SDG&E employee from IT who will be supervising and fully assigned to 2200-0343. He
         will be allocated 100% to SCG.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 319 of 375
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                                             Shared Services Workpapers



Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             B. Director of CS Technology Support
Category-Sub:         1. Director of CS Technology Support
Cost Center:          2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS

      Year/Expl.        Labor           NLbr       NSE       Total        FTE   Adj Type

      2012                    0             0            0           0       1.0   1-Sided Adj

         Transfer of a Sup position previously budgeted and charged to c/c 2200-0343. The employee
         is as SDG&E employee from IT who will be supervising and fully assigned to 2200-0343. He
         will be allocated 100% to SCG.

      2012                    0            -5            0           -5      0.0   1-Sided Adj

         Tru up of the 4 yr average to the 2010 plan.

      2012 Total            145            -5            0      140          1.3




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 320 of 375
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                                              Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub:           1. Director of CS Technology Support
Cost Center:            2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS

Determination of Adjusted-Recorded (Incurred Costs):
                                2005 ($000)          2006 ($000)             2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                                   0                    18               161            145          117
     Non-Labor                               0                     1                 14             26            6
     NSE                                     0                     0                  0              0            0
         Total                               0                    19               174            172          123
         FTE                               0.0                   0.2                2.0            1.7          1.1
  Adjustments (Nominal $) **
     Labor                                   0                     0                 0              0           43
     Non-Labor                               0                     0                 0              0            1
     NSE                                     0                     0                 0              0            0
         Total                               0                     0                 0              0           44
         FTE                               0.0                   0.0               0.0            0.0          0.7
  Recorded-Adjusted (Nominal $)
     Labor                                   0                    18               161            145          160
     Non-Labor                               0                     1                 14             26            7
     NSE                                     0                     0                  0              0            0
          Total                              0                    19               174            172          168
          FTE                              0.0                   0.2                2.0            1.7          1.8
  Vacation & Sick (Nominal $)
     Labor                                   0                     3                24             24           25
     Non-Labor                               0                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
          Total                              0                     3                24             24           25
          FTE                              0.0                   0.0               0.3            0.3          0.3
  Escalation to 2009$
     Labor                                   0                     2                10              2            0
     Non-Labor                               0                     0                 1              0            0
     NSE                                     0                     0                 0              0            0
         Total                               0                     2                11              3            0
         FTE                               0.0                   0.0               0.0            0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                                   0                    23               195            171          185
     Non-Labor                               0                     1                 15             27            7
     NSE                                     0                     0                  0              0            0
         Total                               0                    24               210            198          192
         FTE                               0.0                   0.2                2.3            2.0          2.1



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 321 of 375
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                                              Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               B. Director of CS Technology Support
Category-Sub:           1. Director of CS Technology Support
Cost Center:            2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS


Summary of Adjustments to Recorded:

                                                     In Nominal $ (000) "Incurred Costs"
 Year                                    2005            2006               2007             2008             2009
    Labor                                  0                0                 0                 0               43
    Non-Labor                              0                0                 0                 0            0.818
    NSE                                    0                0                 0                 0                0
        Total                              0                0                 0                 0               44
    FTE                                   0.0              0.0              0.0                0.0             0.7


Detail of Adjustments to Recorded:

Year/Expl.      Labor         NLbr        NSE        FTE    Adj_Type      From CCtr                  RefID

2005 Total            0              0          0    0.0



2006 Total            0              0          0    0.0



2007                -50              0          0    0.0 CCTR Transf      To 2100-3732.000             SDALEY2009100
                                                                                                          2172722727
   Labor transfer due to intradepartmental re-org.

2007                  0              0          0    -0.9 CCTR Transf     To 2100-3732.000             SDALEY2009100
                                                                                                          2172759527
   FTE transfer due to intradepartmental re-org.

2007                 50              0          0    0.0 CCTR Transf      From 2100-3732.000           SDALEY2010031
                                                                                                          5151641107
   Reorganization

2007                  0              0          0    0.9 CCTR Transf      From 2100-3732.000           SDALEY2010031
                                                                                                          5151840483
   Reorganization

2007 Total            0              0          0    0.0



2008                -51              0          0    0.0 CCTR Transf      To 2100-3732.000             SDALEY2009100
                                                                                                          2172845840
   Labor transfer due to intradepartmental re-org.

2008                  0              0          0    -0.8 CCTR Transf     To 2100-3732.000             SDALEY2009100
                                                                                                          2172918760
   FTE transfer due to intradepartmental re-org.




                    SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                            Pages 322 of 375
                                           San Diego Gas & Electric Company
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                                             Shared Services Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                B. Director of CS Technology Support
Category-Sub:            1. Director of CS Technology Support
Cost Center:             2100-3627.000 - CS TECHNOLOGY FIELD SYSTEMS


Year/Expl.       Labor         NLbr        NSE    FTE    Adj Type        From CCtr        RefID

2008                  51            0        0   0.0 CCTR Transf    From 2100-3732.000   SDALEY2010031
                                                                                            5151915500
    Reorganization

2008                   0            0        0   0.8 CCTR Transf    From 2100-3732.000   SDALEY2010031
                                                                                            5151935593
    Reorganization

2008 Total             0               0     0   0.0



2009                  43            0        0   0.0 CCTR Transf    From 2100-3732.000   SDALEY2010031
                                                                                            1111317897
    Transfer to cc 2100-3627 for re-org

2009                   0       0.818         0   0.0 CCTR Transf    From 2100-3732.000   SDALEY2010031
                                                                                            1111350553
    Transfer to 2100-3627 for re-org

2009                   0            0        0   0.7 CCTR Transf    From 2100-3732.000   SDALEY2010031
                                                                                            1111418053
    Transfer to 2100-3627 for re-org

2009 Total            43       0.818         0   0.7




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 323 of 375
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Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               C. Business Planning & Budgets
Cost Center:            2100-3461.000

Summary for Category: C. Business Planning & Budgets

                                                         In 2009$ (000) "Book Expense"
                                  Adjusted-Recorded                           Adjusted-Forecast
                                     2009                     2010               2011             2012
           Labor                            79                    33                    33               33
           Non-Labor                         0                       0                   0                0
           NSE                               0                       0                   0                0
               Total                        79                    33                    33               33
               FTE                          2.0                  2.3                    2.3              2.3

    Cost Centers belonging to this Category:
     2100-3461.000 BUSINESS PLANNING & BUDGETS
           Labor                         79                       33                   33                 33
           Non-Labor                      0                        0                    0                  0
           NSE                            0                        0                    0                  0
             Total                       79                       33                   33                 33
             FTE                        2.0                      2.3                  2.3                2.3




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 324 of 375
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                 Beginning of Workpaper
     2100-3461.000 - BUSINESS PLANNING & BUDGETS




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 325 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                              Shared Services Workpapers


Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               C. Business Planning & Budgets
Category-Sub            1. Business Planning & Budgets
Cost Center:            2100-3461.000 - BUSINESS PLANNING & BUDGETS

Activity Description:
               This USS cost center contains the costs associated with Budget Planning services provided by
               SDGE Employees (1-Prin Busn Analyst, and 1-Proj Mgr) to various VPs (Customer Solutions,
               HR-Diversity-Inclusion, Legal & External Affairs, and Gas Acquisition) in SCG. Activities
               include; data collection and creation of consolidated reports, analysis of the monthly results,
               and special project support as needed. This includes providing timely information and analysis
               that supports senior management decision making.
Forecast Methodology:

       Labor - 5-YR Average
              The 5 year average methodology is appropriate in this cost center, as it is a support function
              largely unchanged in staff and function over the past five years.
       Non-Labor - 5-YR Average
             The 5 year average methodology is appropriate in this cost center, as it is a support function
             largely unchanged in staff and function over the past five years.
       NSE - 5-YR Average
              N/A




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 326 of 375
                                        San Diego Gas & Electric Company
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                                          Shared Services Workpapers


Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             C. Business Planning & Budgets
Category-Sub          1. Business Planning & Budgets
Cost Center:          2100-3461.000 - BUSINESS PLANNING & BUDGETS

Summary of Results:

                                                        In 2009$ (000)
                                  Adjusted-Recorded                                 Adjusted-Forecast
Years                 2005      2006       2007       2008       2009            2010     2011      2012
                                                   Total Incurred (100% Level)
Labor                  278       238        192        197         201           221       221      221
Non-Labor                 5         5          2         2           1              3         3      3
NSE                       0         0          0         0           0              0         0      0
   Total               283       243        194       199         202            224       224      224
   FTE                  3.0       2.5        2.0       2.0         2.0            2.3       2.3     2.3
                                                        Allocations Out
Labor                  227       191        152       151         122            188       188      188
Non-Labor                 4         4          1         2           1              3         3      3
NSE                       0         0          0         0           0              0         0      0
   Total               231       195        153       153         123            191       191      191
   FTE                  0.0       0.0        0.0       0.0         0.0            0.0       0.0     0.0
                                                             Retained
Labor                    51       47          40        46          79             33        33     33
Non-Labor                 1        1           1         0           0              0         0      0
NSE                       0        0           0         0           0              0         0      0
   Total                 52       48          41        46          79             33        33     33
   FTE                  3.0      2.5         2.0       2.0         2.0            2.3       2.3     2.3
                                                         Allocations In
Labor                     0        0           0         0          0               0         0      0
Non-Labor                 0        0           0         0          0               0         0      0
NSE                       0        0           0         0          0               0         0      0
   Total                  0        0           0         0          0               0         0      0
   FTE                  0.0      0.0         0.0       0.0        0.0             0.0       0.0     0.0
                                                         Book Expense
Labor                    51       47          40        46        79               33        33     33
Non-Labor                 1        1           1         0         0                0         0      0
NSE                       0        0           0         0         0                0         0      0
   Total                 52       48          41        46        79               33        33     33
   FTE                  3.0      2.5         2.0       2.0       2.0              2.3       2.3     2.3




                 SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                         Pages 327 of 375
                                                  San Diego Gas & Electric Company
                                                     Test Year 2012 GRC - APP
                                                    Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 C. Business Planning & Budgets
Category-Sub:             1. Business Planning & Budgets
Cost Center:              2100-3461.000 - BUSINESS PLANNING & BUDGETS


Calculation of Book Expense:

                                          2009 Adjusted-Recorded                               2010 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total     FTE
  Directly Retained                 0          0        0         0      0.00           0          0        0         0      0.00
  Directly Allocated                0         0         0           0    0.00           0         0         0           0    0.00
  Subj. To % Alloc.            201            1         0          202   2.00      221            3         0       224      2.30
  % Allocation
       Retained             39.01%       39.01%                                 15.00%       15.00%
       SEU                  60.99%       60.99%                                 85.00%       85.00%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained                 79            0         0          79               33            0         0           33
       SEU                     122            1         0          123             188            3         0       191
       CORP                         0         0         0           0                   0         0         0           0
       Unreg                        0         0         0           0                   0         0         0           0
  Total Incurred               201            1         0          202   2.00      221             3        0       224      2.30
  Total Alloc. Out             122            1         0          123             188             3        0       191
  Total Retained                79            0         0           79              33             0        0           33
  Allocations In                    0         0         0            0                  0          0        0            0
  Book Expense                  79            0         0          79               33            0         0           33


                                          2011 Adjusted-Forecast                               2012 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total     FTE
  Directly Retained                 0         0         0           0    0.00           0         0         0           0    0.00
  Directly Allocated                0         0         0           0    0.00           0         0         0           0    0.00
  Subj. To % Alloc.            221            3         0          224   2.30      221            3         0       224      2.30
  % Allocation
       Retained             15.00%       15.00%                                 15.00%       15.00%
       SEU                  85.00%       85.00%                                 85.00%       85.00%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained                 33            0         0          33               33            0         0           33
       SEU                     188            3         0          191             188            3         0       191
       CORP                         0         0         0           0                   0         0         0           0
       Unreg                        0         0         0           0                   0         0         0           0
  Total Incurred               221            3         0          224   2.30      221             3        0       224      2.30
  Total Alloc. Out             188            3         0          191             188             3        0       191
  Total Retained                33            0         0           33              33             0        0           33
  Allocations In                    0         0         0            0                  0          0        0            0
  Book Expense                  33            0         0          33               33            0         0           33




                       SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                               Pages 328 of 375
                                            San Diego Gas & Electric Company
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                                              Shared Services Workpapers



Area:                  CS - OFFICE OPERATIONS
Witness:               Rahon, J Steve
Category:              C. Business Planning & Budgets
Category-Sub:          1. Business Planning & Budgets
Cost Center:           2100-3461.000 - BUSINESS PLANNING & BUDGETS



Cost Center Allocation Percentage Drivers/Methodology:

    Cost Center Allocation Percentage for 2009
          Used 2009 straight-time lbr budget for assigned clients as the method of support cost allocation.


    Cost Center Allocation Percentage for 2010
          Used 2009 straight-time recorded lbr for assigned clients as the method of support cost allocation.


    Cost Center Allocation Percentage for 2011
          Used 2009 straight-time recorded lbr for assigned clients as the method of support cost allocation.


    Cost Center Allocation Percentage for 2012
          Used 2009 straight-time recorded lbr for assigned clients as the method of support cost allocation.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 329 of 375
                                               San Diego Gas & Electric Company
                                                  Test Year 2012 GRC - APP
                                                 Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 C. Business Planning & Budgets
Category-Sub:             1. Business Planning & Budgets
Cost Center:              2100-3461.000 - BUSINESS PLANNING & BUDGETS

Forecast Summary:
                                                            In 2009 $(000) "Incurred Costs"
     Forecast Method                     Base Forecast                 Forecast Adjustments          Adjusted-Forecast
                                       2010        2011     2012       2010       2011    2012       2010    2011        2012
 Labor              5-YR Average       221           221     221              0     0         0      221      221        221
 Non-Labor          5-YR Average         3             3         3            0     0         0        3         3         3
 NSE                5-YR Average         0             0         0            0     0         0        0         0         0
 Total                                 224           224     224              0     0         0      224      224        224
 FTE                5-YR Average        2.3          2.3        2.3      0.0       0.0      0.0       2.3      2.3        2.3


Forecast Adjustment Details:
       Year/Expl.           Labor             NLbr         NSE        Total        FTE    Adj_Type

         2010 Total                0           0            0            0          0.0




         2011 Total                0           0            0            0          0.0




         2012 Total                0           0            0            0          0.0




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 330 of 375
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Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               C. Business Planning & Budgets
Category-Sub:           1. Business Planning & Budgets
Cost Center:            2100-3461.000 - BUSINESS PLANNING & BUDGETS

Determination of Adjusted-Recorded (Incurred Costs):
                                2005 ($000)          2006 ($000)             2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                                 216                  189                158            167          174
     Non-Labor                                5                    4                  2              2            1
     NSE                                      0                    0                  0              0            0
         Total                             221                  193                160            169          175
         FTE                                2.6                  2.1                1.7            1.7          1.7
  Adjustments (Nominal $) **
     Labor                                   0                     0                 0              0            0
     Non-Labor                               0                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
         Total                               0                     0                 0              0            0
         FTE                               0.0                   0.0               0.0            0.0          0.0
  Recorded-Adjusted (Nominal $)
     Labor                                 216                  189                158            167          174
     Non-Labor                                5                    4                  2              2            1
     NSE                                      0                    0                  0              0            0
          Total                            221                  193                160            169          175
          FTE                               2.6                  2.1                1.7            1.7          1.7
  Vacation & Sick (Nominal $)
     Labor                                  31                    30                24             27           27
     Non-Labor                               0                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
          Total                             31                    30                24             27           27
          FTE                              0.4                   0.4               0.3            0.3          0.3
  Escalation to 2009$
     Labor                                  31                    19                10              3            0
     Non-Labor                               1                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
         Total                              32                    20                10              3            0
         FTE                               0.0                   0.0               0.0            0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                                 279                  238                192            197          201
     Non-Labor                                5                    5                  2              2            1
     NSE                                      0                    0                  0              0            0
         Total                             284                  243                194            199          201
         FTE                                3.0                  2.5                2.0            2.0          2.0



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 331 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                             Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               C. Business Planning & Budgets
Category-Sub:           1. Business Planning & Budgets
Cost Center:            2100-3461.000 - BUSINESS PLANNING & BUDGETS


Summary of Adjustments to Recorded:

                                                   In Nominal $ (000) "Incurred Costs"
 Year                                   2005           2006               2007           2008           2009
    Labor                                 0               0                 0              0              0
    Non-Labor                             0               0                 0              0              0
    NSE                                   0               0                 0              0              0
        Total                             0               0                 0              0              0
    FTE                                  0.0             0.0              0.0             0.0            0.0


Detail of Adjustments to Recorded:

Year/Expl.      Labor        NLbr        NSE       FTE    Adj_Type      From CCtr               RefID

2005 Total           0              0          0   0.0



2006 Total           0              0          0   0.0



2007 Total           0              0          0   0.0



2008 Total           0              0          0   0.0



2009 Total           0              0          0   0.0




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 332 of 375
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Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               D. Director of Market Services
Cost Center:            2100-0006.000

Summary for Category: D. Director of Market Services

                                                         In 2009$ (000) "Book Expense"
                                  Adjusted-Recorded                           Adjusted-Forecast
                                      2009                    2010               2011             2012
           Labor                             25                   79                    79               79
           Non-Labor                          2                      9                   9                9
           NSE                                0                      0                   0                0
               Total                         27                   88                    88               88
               FTE                           1.2                 1.4                    1.4              1.4

    Cost Centers belonging to this Category:
     2100-0006.000 DIRECTOR OF MARKET SERVICES
           Labor                         25                       79                   79                 79
           Non-Labor                      2                        9                    9                  9
           NSE                            0                        0                    0                  0
             Total                       27                       88                   88                 88
             FTE                        1.2                      1.4                  1.4                1.4




                     SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                             Pages 333 of 375
                  San Diego Gas & Electric Company
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                 Beginning of Workpaper
     2100-0006.000 - DIRECTOR OF MARKET SERVICES




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 334 of 375
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                                               Shared Services Workpapers


Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               D. Director of Market Services
Category-Sub            1. Director of Market Services
Cost Center:            2100-0006.000 - DIRECTOR OF MARKET SERVICES

Activity Description:
               The cost center for the Director of Market Services, who provides oversight, guidance and
               direction for all cost centers within the department. Reviews policies and general functionality,
               and makes decisions on projects and initiatives. Interacts with other areas of SEU and takes
               the lead in specific matters related to Customer Service support.
Forecast Methodology:

       Labor - 5-YR Average
              The 5 year average methodology is appropriate in this cost center, as it is a leadership function
              largely unchanged in staff over the past five years.
       Non-Labor - 5-YR Average
             The 5 year average methodology is appropriate in this cost center, as it is a leadership function
             largely unchanged in staff over the past five years.
       NSE - 5-YR Average
              N/A




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 335 of 375
                                        San Diego Gas & Electric Company
                                           Test Year 2012 GRC - APP
                                          Shared Services Workpapers


Area:                 CS - OFFICE OPERATIONS
Witness:              Rahon, J Steve
Category:             D. Director of Market Services
Category-Sub          1. Director of Market Services
Cost Center:          2100-0006.000 - DIRECTOR OF MARKET SERVICES

Summary of Results:

                                                        In 2009$ (000)
                                  Adjusted-Recorded                                 Adjusted-Forecast
Years                 2005      2006       2007       2008       2009            2010     2011      2012
                                                   Total Incurred (100% Level)
Labor                  161       197        209        195         193           190       190      190
Non-Labor                22        17         20        23          20             19        19      19
NSE                       0         0          0         0           0              0         0       0
   Total               183       214        229       218         213            209       209      209
   FTE                  1.6       1.8        1.6       1.2         1.2            1.4       1.4     1.4
                                                         Allocations Out
Labor                    20      161        115       163          168           111       111      111
Non-Labor                 2        13         12        14           18            10        10      10
NSE                       0         0          0         0            0             0         0       0
   Total                 22      174        127       177          186           121       121      121
   FTE                  0.0       0.0        0.0       0.0          0.0           0.0       0.0     0.0
                                                             Retained
Labor                  141        36          94        32          25             79        79     79
Non-Labor                20        4           8         9           2              9         9      9
NSE                       0        0           0         0           0              0         0      0
   Total               161        40        102         41          27             88        88     88
   FTE                  1.6      1.8         1.6       0.7         0.6            1.2       1.2     1.2
                                                         Allocations In
Labor                     0        0           0         0          0               0         0      0
Non-Labor                 0        0           0         0          0               0         0      0
NSE                       0        0           0         0          0               0         0      0
   Total                  0        0           0         0          0               0         0      0
   FTE                  0.0      0.0         0.0       0.0        0.0             0.0       0.0     0.0
                                                         Book Expense
Labor                  141        36          94        32        25               79        79     79
Non-Labor                20        4           8         9         2                9         9      9
NSE                       0        0           0         0         0                0         0      0
   Total               161        40        102         41        27               88        88     88
   FTE                  1.6      1.8         1.6       0.7       0.6              1.2       1.2     1.2




                 SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                         Pages 336 of 375
                                                  San Diego Gas & Electric Company
                                                     Test Year 2012 GRC - APP
                                                    Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 D. Director of Market Services
Category-Sub:             1. Director of Market Services
Cost Center:              2100-0006.000 - DIRECTOR OF MARKET SERVICES


Calculation of Book Expense:

                                          2009 Adjusted-Recorded                               2010 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total     FTE
  Directly Retained                 3          0        0         3      0.00           3          1        0         4      0.00
  Directly Allocated            95           10         0          105   0.00       35            3         0           38   0.00
  Subj. To % Alloc.             95           10         0          105   0.60      152           15         0       167      1.20
  % Allocation
       Retained             23.31%       23.30%                                 50.00%       50.00%
       SEU                  76.69%       76.70%                                 50.00%       50.00%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained                 22            2         0          24               76            8         0           84
       SEU                      73            8         0          81               76            7         0           83
       CORP                         0         0         0           0                   0         0         0           0
       Unreg                        0         0         0           0                   0         0         0           0
  Total Incurred               193           20         0          213   0.60      190           19         0       209      1.20
  Total Alloc. Out             168           18         0          186             111           10         0       121
  Total Retained                25            2         0           27              79             9        0           88
  Allocations In                    0         0         0            0                  0          0        0            0
  Book Expense                  25            2         0          27               79            9         0           88


                                          2011 Adjusted-Forecast                               2012 Adjusted-Forecast
                            Labor       Non-Labor      NSE    Total      FTE    Labor       Non-Labor     NSE      Total     FTE
  Directly Retained                 3         1         0           4    0.00           3         1         0           4    0.00
  Directly Allocated            35            3         0          38    0.00       35            3         0           38   0.00
  Subj. To % Alloc.            152           15         0          167   1.20      152           15         0       167      1.20
  % Allocation
       Retained             50.00%       50.00%                                 50.00%       50.00%
       SEU                  50.00%       50.00%                                 50.00%       50.00%
       CORP                  0.00%        0.00%                                  0.00%        0.00%
       Unreg                 0.00%        0.00%                                  0.00%        0.00%
  $ Allocation
       Retained                 76            8         0          84               76            8         0           84
       SEU                      76            7         0          83               76            7         0           83
       CORP                         0         0         0           0                   0         0         0           0
       Unreg                        0         0         0           0                   0         0         0           0
  Total Incurred               190           19         0          209   1.20      190           19         0       209      1.20
  Total Alloc. Out             111           10         0          121             111           10         0       121
  Total Retained                79            9         0           88              79             9        0           88
  Allocations In                    0         0         0            0                  0          0        0            0
  Book Expense                  79            9         0          88               79            9         0           88




                       SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                               Pages 337 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                             Shared Services Workpapers



Area:                  CS - OFFICE OPERATIONS
Witness:               Rahon, J Steve
Category:              D. Director of Market Services
Category-Sub:          1. Director of Market Services
Cost Center:           2100-0006.000 - DIRECTOR OF MARKET SERVICES



Cost Center Allocation Percentage Drivers/Methodology:

    Cost Center Allocation Percentage for 2009
          Although the work is similar for both companies, the budget magnitude for the organizations
          supported best reflects the level of effort required for each company.


    Cost Center Allocation Percentage for 2010
          Organizational changes will cause a shift to a 50/50 split between time and resources committed to
          SCG and SDG&E.


    Cost Center Allocation Percentage for 2011
          Organizational changes will cause a shift to a 50/50 split between time and resources committed to
          SCG and SDG&E.


    Cost Center Allocation Percentage for 2012
          Organizational changes will cause a shift to a 50/50 split between time and resources committed to
          SCG and SDG&E.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 338 of 375
                                               San Diego Gas & Electric Company
                                                  Test Year 2012 GRC - APP
                                                 Shared Services Workpapers



Area:                     CS - OFFICE OPERATIONS
Witness:                  Rahon, J Steve
Category:                 D. Director of Market Services
Category-Sub:             1. Director of Market Services
Cost Center:              2100-0006.000 - DIRECTOR OF MARKET SERVICES

Forecast Summary:
                                                            In 2009 $(000) "Incurred Costs"
     Forecast Method                     Base Forecast                 Forecast Adjustments          Adjusted-Forecast
                                       2010        2011     2012       2010       2011    2012       2010    2011        2012
 Labor              5-YR Average       190           190     190              0     0         0      190      190        190
 Non-Labor          5-YR Average        19            19        19            0     0         0       19       19         19
 NSE                5-YR Average         0             0         0            0     0         0        0         0         0
 Total                                 209           209     209              0     0         0      209      209        209
 FTE                5-YR Average        1.4          1.4        1.4      0.0       0.0      0.0       1.4      1.4        1.4


Forecast Adjustment Details:
       Year/Expl.           Labor             NLbr         NSE        Total        FTE    Adj_Type

         2010 Total                0           0            0            0          0.0




         2011 Total                0           0            0            0          0.0




         2012 Total                0           0            0            0          0.0




                      SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                              Pages 339 of 375
                                            San Diego Gas & Electric Company
                                               Test Year 2012 GRC - APP
                                              Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               D. Director of Market Services
Category-Sub:           1. Director of Market Services
Cost Center:            2100-0006.000 - DIRECTOR OF MARKET SERVICES

Determination of Adjusted-Recorded (Incurred Costs):
                                2005 ($000)          2006 ($000)             2007 ($000)   2008 ($000)   2009 ($000)
  Recorded (Nominal $)*
     Labor                                 217                  120                176            162          168
     Non-Labor                               22                   15                 21             38           21
     NSE                                      0                    0                  0              0            0
         Total                             239                  134                197            200          188
         FTE                                2.6                  0.7                1.2            0.9          1.0
  Adjustments (Nominal $) **
     Labor                                  -93                   37                -3              2            0
     Non-Labor                               -2                    0                -2            -15            0
     NSE                                      0                    0                 0              0            0
         Total                              -95                   37                -5            -13            0
         FTE                               -1.1                  0.8               0.2            0.0          0.0
  Recorded-Adjusted (Nominal $)
     Labor                                 125                  156                172            164          168
     Non-Labor                               19                   15                 19             22           21
     NSE                                      0                    0                  0              0            0
          Total                            144                  171                191            187          188
          FTE                               1.4                  1.5                1.4            1.0          1.0
  Vacation & Sick (Nominal $)
     Labor                                  18                    25                26             27           26
     Non-Labor                               0                     0                 0              0            0
     NSE                                     0                     0                 0              0            0
          Total                             18                    25                26             27           26
          FTE                              0.2                   0.3               0.2            0.2          0.2
  Escalation to 2009$
     Labor                                  18                    16                11              3            0
     Non-Labor                               2                     1                 1              0            0
     NSE                                     0                     0                 0              0            0
         Total                              20                    17                12              3            0
         FTE                               0.0                   0.0               0.0            0.0          0.0
  Recorded-Adjusted (Constant 2009$)
     Labor                                 161                  197                209            194          193
     Non-Labor                               22                   16                 20             23           21
     NSE                                      0                    0                  0              0            0
         Total                             183                  213                229            216          214
         FTE                                1.6                  1.8                1.6            1.2          1.2



* After company-wide exclusions of Non-GRC costs
** Refer to "Detail of Adjustments to Recorded" page for line item adjustments




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 340 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                             Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               D. Director of Market Services
Category-Sub:           1. Director of Market Services
Cost Center:            2100-0006.000 - DIRECTOR OF MARKET SERVICES


Summary of Adjustments to Recorded:

                                                   In Nominal $ (000) "Incurred Costs"
 Year                                   2005           2006               2007             2008            2009
    Labor                                -93             37                -3                2                0
    Non-Labor                             -2          0.252                -2               -15               0
    NSE                                   0               0                 0                0                0
        Total                            -95             37                -5               -13               0
    FTE                                 -1.1             0.8              0.2               0.0             0.0


Detail of Adjustments to Recorded:

Year/Expl.      Labor        NLbr        NSE       FTE    Adj_Type      From CCtr                 RefID

2005               -17              0          0   0.0 CCTR Transf      To 2100-3547.000            KHART20090915
                                                                                                        082446220
   Residential Services Organization has been restructured. AMO Senior Business Analyst
   employee labor and non-labor should be moved from USS cost center 2100-0006 into
   NSS cost center 2100-3547 AMO Financial & Operations Support to align with current
   org.
2005                 0              0          0   -0.3 CCTR Transf     To 2100-3547.000            KHART20090915
                                                                                                        083301747
   Residential Services Organization has been restructured. AMO Senior Business Analyst
   employee labor and non-labor should be moved from USS cost center 2100-0006 into
   NSS cost center 2100-3547 AMO Financial & Operations Support to align with current
   org.
2005               -84              0          0   0.0 CCTR Transfer    To 2100-3593.000            SDALEY2010041
                                                                                                       5123825257
   Residential Services Organization has been restructured. CS Operations Analysis
   employees' labor and non-labor should be moved from USS cost center 2100-0006 into
   USS cost center 2100-3593 CS Operations Analysis to align with current org.
2005                 0           -2            0   0.0 CCTR Transfer    To 2100-3593.000            SDALEY2010041
                                                                                                       5123900117
   Residential Services Organization has been restructured. CS Operations Analysis
   employees' labor and non-labor should be moved from USS cost center 2100-0006 into
   USS cost center 2100-3593 CS Operations Analysis to align with current org.
2005                 0              0          0   -1.0 CCTR Transfer   To 2100-3593.000            SDALEY2010041
                                                                                                       5123928540
   Residential Services Organization has been restructured. CS Operations Analysis
   employees' labor and non-labor should be moved from USS cost center 2100-0006 into
   USS cost center 2100-3593 CS Operations Analysis to align with current org.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 341 of 375
                                          San Diego Gas & Electric Company
                                             Test Year 2012 GRC - APP
                                            Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               D. Director of Market Services
Category-Sub:           1. Director of Market Services
Cost Center:            2100-0006.000 - DIRECTOR OF MARKET SERVICES


Year/Expl.      Labor        NLbr        NSE      FTE      Adj Type           From CCtr       RefID

2005                 8            0         0     0.0 CCTR Transfer     From 2100-3593.000   SDALEY2010041
                                                                                                5125846257
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2005                 0            0         0     0.2 CCTR Transfer     From 2100-3593.000   SDALEY2010041
                                                                                                5125919337
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2005 Total         -93           -2         0    -1.1



2006                37            0         0     0.0 CCTR Transfer     From 2100-3593.000   SDALEY2010041
                                                                                                5130222087
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2006                 0        0.252         0     0.0 CCTR Transfer     From 2100-3593.000   SDALEY2010041
                                                                                                5130235507
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2006                 0            0         0     0.8 CCTR Transfer     From 2100-3593.000   SDALEY2010041
                                                                                                5130246523
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2006 Total          37        0.252         0     0.8



2007               -25            0         0     0.0 CCTR Transfer     To 2100-3593.000     SDALEY2010041
                                                                                                5124317400
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2007                 0           -3         0     0.0 CCTR Transfer     To 2100-3593.000     SDALEY2010041
                                                                                                5124336493
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.




                  SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                          Pages 342 of 375
                                           San Diego Gas & Electric Company
                                              Test Year 2012 GRC - APP
                                             Shared Services Workpapers



Area:                    CS - OFFICE OPERATIONS
Witness:                 Rahon, J Steve
Category:                D. Director of Market Services
Category-Sub:            1. Director of Market Services
Cost Center:             2100-0006.000 - DIRECTOR OF MARKET SERVICES


Year/Expl.       Labor        NLbr        NSE       FTE      Adj Type           From CCtr       RefID

2007                  0            0         0     -0.3 CCTR Transfer     To 2100-3593.000     SDALEY2010041
                                                                                                  5124406837
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2007                 21            0         0     0.0 CCTR Transfer      From 2100-3593.000   SDALEY2010041
                                                                                                  5130530947
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2007                  0        0.513         0     0.0 CCTR Transfer      From 2100-3593.000   SDALEY2010041
                                                                                                  5130543070
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2007                  0            0         0     0.5 CCTR Transfer      From 2100-3593.000   SDALEY2010041
                                                                                                  5130557040
    Residential Services Organization has been restructured. Administrative Assistant
    employee labor and non-labor should be moved from NSS cost center 2100-3593 into
    USS cost center 2100-0006 Director of CS Strategies to align with current org.
2007 Total           -3           -2         0     0.2



2008                  0           -6         0     0.0 CCTR Transf        To 2100-3456.000     KHART20090915
                                                                                                   083902767
    Residential Services Organization has been restructured. CS Field Staff miscellaneous
    non-labor should be moved from USS cost center 2100-0006 into USS cost center
    2100-3456 CS Field Staff to align with current org.
2008                  2            0         0     0.0 CCTR Transfer      To 2100-3593.000     SDALEY2010041
                                                                                                  5124536383
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2008                  0           -1         0     0.0 CCTR Transfer      To 2100-3593.000     SDALEY2010041
                                                                                                  5124552227
    Residential Services Organization has been restructured. CS Operations Analysis
    employees' labor and non-labor should be moved from USS cost center 2100-0006 into
    USS cost center 2100-3593 CS Operations Analysis to align with current org.
2008                  0           -9         0     0.0 CCTR Transfer      To 2100-0040.000     SDALEY2010041
                                                                                                  5124942900
    Residential Services Organization has been restructured. Customer Segment
    purchased services dollars should be moved from USS cost center 2100-0006 into NSS
    cost center 2100-0040 CS Solutions to align with current org.




                   SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                           Pages 343 of 375
                                        San Diego Gas & Electric Company
                                           Test Year 2012 GRC - APP
                                          Shared Services Workpapers



Area:                   CS - OFFICE OPERATIONS
Witness:                Rahon, J Steve
Category:               D. Director of Market Services
Category-Sub:           1. Director of Market Services
Cost Center:            2100-0006.000 - DIRECTOR OF MARKET SERVICES


Year/Expl.      Labor        NLbr      NSE     FTE    Adj Type        From CCtr   RefID

2008 Total          2           -15       0   0.0



2009 Total          0            0        0   0.0




                 SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                                         Pages 344 of 375
                  San Diego Gas & Electric Company
                     Test Year 2012 GRC - APP
                    Shared Services Workpapers




    Supplemental Workpapers for Workpaper 2100-0006.000




SDG&E/CS - OFFICE OPERATIONS/Exh No:SDG&E-14-WP/Witness: J. Rahon
                        Pages 345 of 375
                                                San Diego Gas & Electric Company
                                                   Test Year 2012 GRC - APP
                                                  Shared Services Workpapers




                                                                Revised    Cal. P.U.C. Sheet No.                      20140-E
             San Diego Gas & Electric Company
                   San Diego, California           Canceling    Revised    Cal. P.U.C. Sheet No.                      15695-E

                                                                RULE 9                                                Sheet 1
                                                RENDERING AND PAYMENT OF BILLS


        A.         Rendering of Bills

                   1.       Regular Bills. Bills for electric service will be rendered monthly or as may otherwise be                T
                            provided under applicable tariff schedules and will be based on the measured quantity of                 T
                            electricity delivered to the customer, except as provided in Section C below and as noted in             T
                            Rule 17, Meter Reading, Section C.                                                                       T
                   2.       Electronic Bills. At the mutual option of the customer and the Utility, the customer may elect           T, L
                            to receive, view and pay regular bills for service electronically and no longer receive paper
                            bills. All legal and mandated notices, and all charges that would have appeared on the
                            paper bill, will be provided with the electronic bill transmittal. Even if the Utility allows bill
                            payment using a bill aggregator by credit/debit card, responsibility for handling complaints
                            about the bill still resides with the Utility. All notices for termination of service for non-
                            payment will be delivered by a Utility visit or by U.S. mail. Either party may discontinue
                            electronic billing upon 30 days’ notice. The Utility will not release confidential information,
                            including financial information, to a third party without the customer’s consent. The
                            customer consent shall be provided to the Utility either in writing or electronically.

                   3.       Summary Billing. Summary Billing presents bills for customers with multiple accounts in a                T
                            summarized bill. A customer will receive one bill each month for such a group of accounts.               T
                            This option is available to both Residential and Non-residential customers.                              T