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SCE Rate Update to the
Kern County Taxpayers Association
Russ Garwacki
Manager – Pricing Design and Research
February 9, 2012
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Revenue Requirement Components
- Overview
SCE Revenue Requirement (2011)
Conclusion
DWR Charges Generation
• Cost recovery on contracts • Investment and O&M for
entered into on behalf of IOUs utility owned generation Less than half of retail
during energy crisis (shifted to • Fuel and purchased power
SCE-Gen as of 1/1/12) rates fund generation-
costs
• SPVP Program related activities:
Public Purpose Programs
• Legislative mandates (energy
SCE spends 55% of
efficiency, RD&D, renewables rate revenue on
investment, etc.)
9.1% important non-
• CPUC programs (additional
energy efficiency, CARE 6.3%
generation services
program, etc.) such as distribution
5.3% and transmission
Transmission
• Investment and O&M system development
44.2%
in transmission and reliability, energy
(typically >220 kV) efficiency, demand
Distribution 35.0%
response, and low
• Investment in distribution: income assistance
poles, wires, substations, servic
programs
e centers, meters, etc.
• California Solar Initiative
• Demand Response Programs
• Edison SmartConnect
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2012 CPUC General Rate Case
- Phase 1 Update
 Application Status
– Evidentiary hearings took place July 25 – August 26
– Proposed decision expected 1st quarter 2012
– Final decision expected 2nd quarter 2012
 Reasons for Request
– Inspect, maintain and/or upgrade 1.5 million electric poles, 712,605 transformers
and 88,207 miles of distribution lines
– Increase grid security
– Add smart grid components to integrate more renewable energy
– Maintain a skilled work force to handle upcoming changes to the grid and related
customer service needs
 Current Status
– SCE proposed a revenue increase of $794 million for 2012, then $155 million for
2013 and $515 million for 2014. That translates to a 6.9% increase in 2012, 1.3%
in 2013, and 4.3% in 2014.
– Expecting a proposed decision in the next 1-2 months.
– GRC Phase 1 rates expected to be effective 2nd quarter 2012
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2012 FERC General Rate Case
Rate increase driven primarily by Renewable Portfolio Standard
– Requested increase of $135M from $636M to $771M (21%)
– Rates effective January 1, 2012, subject to refund.
Formula Rate Strategy
– The rate case model worked well for SCE when rate changes were
infrequent due to sales growth and limited transmission investment
– A formula rate approach used at FERC where specific formulas are used
to calculate the utility’s revenue requirement rather than litigating multiple
cases.
– About 75% of FERC-jurisdictional utilities have a formula rates (e.g.
SDG&E and APS, PG&E does not)
– If approved, formula rate changes may begin as early as October-2012
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Energy Resource Recovery Account (ERRA)
- includes Balancing Accounts
 ERRA Application
– Revenue requirements associated with fuel and power
purchases, year-end balancing account balances, and
miscellaneous expenses
– Filed August 1, 2011 with an update filed November 2011
– Two items are particularly noteworthy –
1. Calculations associated with DA customers’ Cost Responsibility
Surcharge (CRS) and specifically the Power Charge Indifference
Amount (PCIA) to be implemented. DA customers’ re-billed from
2011-forward.
2. ERRA balancing account is currently over-collected due to low
natural gas prices.
– Rates will likely be implemented in second Quarter 2012 and
possibly be consolidated with GRC Phase 1 rate changes
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Department of Water Resources (DWR)
 DWR Power Charge
– DWR Power Contracts were established in 2001
– Two DWR Power Contracts expired on September 30, 2011
– SCE’s last DWR Power contract expired on December 31, 2011
 DWR Bond Charge remains in effect
 DWR Power Credit (Reserves Refund)
– A portion of the historical DWR-Power payments funded these
reserves
– DWR will begin returning these reserves to which SCE will pass
through to Bundled Service customers on a separate fixed cents/kWh
line item credit (about 0.6 cents/kWh).
– DA customers will see benefit via our reduced portfolio price thus a
reduced CRS.
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Estimated 2012 Rate Changes –
Rate Group Averages and Tiered Residential Rates
Bundled Service Average Rates - ¢/kWh Bundled Service Average Rates - ¢/kWh
June 2011 2012 2nd Qtr* % change June 2011 2012 2nd Qtr* % change
(A) (C) C/B
Domestic 15.5 17.7 14.1% NON-CARE Energy Charge
Baseline 12.5 12.6 1.0%
GS-1 17.0 19.3 13.5% 101% - 130% of Baseline 14.8 15.5 5.0%
GS-2 15.5 16.6 6.9% 131% - 200% of Baseline 22.9 30.5 33.0%
201% - 300% of Baseline 26.4 34.0 28.6%
TC-1 15.4 17.3 13.0%
Over 300% of Baseline 29.9 37.5 25.3%
TOU-GS 13.4 14.3 7.0%
LSMP 15.2 16.6 9.1% NON-CARE Energy Charge
Baseline 8.5 8.5 0.0%
TOU-8-SEC 12.4 13.3 6.9% 101% - 130% of Baseline 10.7 10.7 0.0%
TOU-8-PRI 11.4 12.0 5.2% 131% - 200% of Baseline 17.5 20.0 14.3%
201% - 300% of Baseline 17.5 20.0 14.3%
TOU-8-SUB 7.1 7.0 -0.9%
Over 300% of Baseline 17.5 20.0 14.3%
Large Power 10.4 10.8 4.6%
PA-1 19.2 22.3 16.2%
PA-2 14.1 15.5 10.1%
TOU-AG 10.7 11.1 3.7%
TOU-PA-5 11.9 11.6 -2.5%
Ag & Pumping 11.9 12.7 6.1%
Streetlight 18.6 18.5 -0.3%
Total 14.1 15.6 10.3%
* These rate levels are estimated based on SCE’s latest forecast & are subject to change based on CPUC and FERC decisions
** Includes 2012 ERRA forecast and 2012 GRC Phase 1 at full request
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2012 GRC Phase 2
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2012 GRC Phase 2
 Overall Objective - Equitably Recover our Revenue Requirement while supporting
various State Energy Policy Objectives.
 Since 2001, SCE has successfully reversed the 2001 energy crisis surcharge
revenues to achieve an equitable inter-class revenue allocation and achieved
settlements in the 2003, 2006, and 2009 cases.
 Cost Studies and Revenue Allocation Process
– Each rate group’s share of SCE's authorized revenue requirements is based on marginal
costs for delivery services (distribution and customer costs), and generation (energy and
capacity) that are litigated in this proceeding. Transmission costs and their allocation is
established by FERC and are not at issue in this proceeding.
– SCE's marginal cost proposals generally follow precedent established in prior GRCs. We
apply marginal costs to customer, demand, and usage characteristics of each customer
group to determine the relative contribution of each rate group to our costs.
– We use SCE's current authorized revenue requirements to illustrate the effect of our
proposals. Actual results will incorporate whatever revenue requirement changes have
been adopted at the time we implement these changes.
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2012 GRC Phase 2 –
Revenue Allocation versus Rates
Revenue Allocation:
Revenue allocations are aligned relatively close to cost of service
Public policy allocations are primarily defined by statute or CPUC decisions
Commercial / Industrial Rates:
Structures are currently aligned with cost to serve principles
Dynamic pricing proposals expected to take effect in 2013
Residential Rates:
Structures are driven by legislation, not costs:
–Pre-1970’s oil-embargo rate structure had declining block cost-based rates
–Mildly inclining block rates introduced to send a conservation price signal (2-tier with maximum differential of 15%).
–2001 Energy Crisis brought 5-tier rates with baseline rate restrictions leading to current maximum tier differentials
of nearly 250%.
High use customers subsidize low use customers by over $600M annually.
CARE program subsidy exceeds $300M annually - paid by all remaining customers (res
and non-res) on an equal cents/kWh basis.
Bulk of $50M annual NEM subsidies caused from by-passing upper tier rates
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Residential Rate Equity – The Elephant in the Room
• Tiered rate structures are not cost-based.
• Higher usage customers (> 600 kWh/month) currently pay $600 M above cost annually.
At 7 cents/kWh, a 1200 kWh/month
Low usage customer pays $1,000/year above cost.
customers are
subsidized
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2012 GRC Phase 2 – Residential Rate Equity
 SCE has proposed modifications to the rate structure and baseline
allowances to mitigate the growing residential intra-class subsidies.
 Proposals to mitigate higher bills include:
– Elimination of Tier 5 (collapsing with Tier 4 reduces the highest rate)
– Overall reduction in baseline allowances to 50% of energy consumed.
• Reduced from 60% to 55% in our 2009 GRC Phase 2
• By billing more usage at upper tier rates, upper tier rates are reduced.
• Shifts some revenue to low and mid-usage customers.
– Separate and distinct baseline allowances for single-family and multi-family
residences.
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2012 GRC Phase 2 – Residential Rate Equity
Single and Multi-family Baseline Allowances
Improves cost allocation between Single and Multi-family dwellings
Establish separate baselines for Single and Multi-family dwellings
 Refinement in baseline allocations = improved cost allocation
 Very different needs
 Average Single-family home is 2,434 square feet vs. 1,249 square feet for average Multi-family home
 Average monthly Single-family home usage (kWh) is 690 kWh vs. 400 kWh for Multi-family homes
 Average number of occupants for Single-family homes is 3.2 vs. 2.3 for Multi-family homes
Current: Baseline Proposed: Baseline
Sing-family Multi-family Sing-family Multi-family
Tier 1 48% 65% Tier 1 52% 50%
Tier 2 11% 9% Tier 2 11% 10%
Tier 3 and above 41% 26% Tier 3 and above 37% 40%
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2012 GRC Phase 2 – Residential Rate Equity
Baseline Adjustments
Basic Customer Daily Allowance -- Summer
Current @ 55% Proposed at 50%
Baseline Regions Single Multi
5 9.1 11.0 4.9
6 9.2 11.1 6.3
8 10.2 12.3 6.9
9 13.9 15.1 9.5
10 16.0 17.0 11.7
13 18.6 18.6 14.2
14 16.1 16.1 11.7
15 43.9 45.8 26.9
16 11.5 11.9 9.3
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2012 GRC Phase 2 – Residential Rate Proposals
Collapse Tiers,
Baseline
Comparison of 2012 GRC Non-CARE Status Quo Design Modifications
Rates Structures June 2011 (Note 1) (Note 2)
Baseline Allowance => 55% 55% 50%
Tiers => 5 5 4
Baseline 12.5 12.4 12.4
101% - 130% of Baseline 14.8 14.8 14.8
131% - 200% of Baseline 22.9 24.5 23.0
200% - 300% of Baseline 26.4 28.0 27.0
Over 300% of Baseline 29.9 31.5 27.0
Single Family Basic Charge $/month 0.88 0.88 0.88
Comparison of 2012 GRC CARE Rates
Structures
Baseline 8.5 8.5 8.5
101% - 130% of Baseline 10.7 10.7 10.7
131% - 200% of Baseline 17.5 18.7 17.5
200% - 300% of Baseline 17.5 18.7 17.5
Over 300% of Baseline 17.5 18.7 17.5
Single Family Basic Charge $/month 0.70 0.70 0.70
Notes:
1) The status quo rate structure is defined as SCE’s existing rate structure, maintaining the existing customer charge,
baseline allocations, and $0.07/kWh differential between Tier 3 and Tier 5 rates.
2) The Proposed rate structure includes the adjustments to baseline allowances and a 4-Tier rate structure.
3) 2012 forecasted rates (columns 2-5), reflect updated cost allocations.
Note: Data above do NOT include impacts of all 2012 revenue requirements changes.
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2012 GRC Phase 2 – Residential Rate Equity
 KernTax was instrumental in getting several rate changes in PG&E’s
recent GRC.
– Reduced baseline allowances from 60% to 55% (SCE in 2009 GRC)
– Implemented a Tier 3 rate for CARE customers (SCE in 2003 GRC)
– Eliminated Tier 5 (SCE proposed in 2012 GRC)
– A new customer charge for PG&E was rejected by the CPUC on legal and
policy grounds (SCE in 1995 GRC)
 SCE’s proposals help, but significant improvements in rate equity will
require legislation.
– The single most significant rate change to improve equity is the ability to
implement a reasonable customer charge.
– Typical utility monthly customer charges range from $5-$10.
– If implemented, these new revenues would offset upper tier rate levels.
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Dynamic Pricing Deployment
 2009 GRC Phase 2 decision (D.09-08-028) ordered SCE to file an application
proposing:
– Mandatory TOU rates for all non-residential customers
– Default Critical Peak Pricing (CPP) rates for all commercial/industrial customers
< 200 kW and Ag/Pumping customers > 200 kW
– New rates to be effective January 1, 2012
 On September 1, 2010, SCE filed its Dynamic Pricing application proposing:
– Mandatory TOU rates for all non-residential customers
– Default CPP rates for all commercial/industrial customers < 200 kW and Ag/Pumping
customers > 200 kW
 ALJ Ruling directed SCE to include its Dynamic Pricing proposals in its 2012 GRC
Phase 2 Application
 In the 2012 GRC Phase 2 Application, SCE proposed to:
– Implement mandatory TOU rates for non-residential customers
– Offer CPP rates to all customer classes on an opt-in basis
– On-line customer rate analysis tool to be deployed late 2012 for rates to be effective
January 2013.
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SCE’s 2012 GRC Phase 2 – Current Schedule
SCE – Application and Service of Marginal
June 6, 2011
Cost (MC), Revenue Allocation (RA) and
Rate Design Testimony
DRA – MC, RA and Rate Design December 20, 2011
Testimony
Other Parties’ – MC, RA and Rate Design February 6, 2012
Testimony
Settlement Discussions February – April 2012
Public Participation Hearings February – April 2012
Rebuttal Testimony- All Parties April 23, 2012
Evidentiary Hearings May 14-18, 2012
Opening Briefs June 15, 2012
Reply Briefs July 6, 2012
ALJ Proposed Decision (PD) October 2012
Initial Comments on PD October 2012
Reply Comments on PD October 2012
CPUC - Final Decision November 2012
Rates Effective January 1, 2013
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Backup
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2012 GRC Phase 2 Bill Impacts: Oct 7th filing -
Non CARE
Residential NON-CARE (Bundled):
Annual Bill Impact (June 2011 Vs 2012 GRC)
35.0%
33.1%
30.0%
25.0%
20.8%
%Customer
20.0%
16.0%
15.0%
10.0% 8.2%
6.0%
5.0% 4.6%
5.0% 3.9%
1.6%
0.4% 0.3% 0.0%
0.0%
Below - < -10% to - < -5% to - < -3% to > 0% to > 3% to 5% >5% to > 10% to > 15% to > 20% to >30% to
10% 5% 3% 0% 3% 10% 15% 20% 30% 45% Above45%
% Impact
Percent
Average Rates - Impact - Average Monthly Bill
Impact Customer Customer Ratio Average ¢/kWh % -$
% % All Monthly $ Bill
% Numbe r % %Multi %Single % Multi Single % Ba s ic Ele ctric Bill da ys kW h J une 2011 GRC 2012 Ave ra ge Curre nt Propos e d Cha nge
Be low -10% 11,617 0.4% 0.0% 0.6% 0.0% 100.0% 0.6% 99.4% 328 974 18.9 16.5 -12.6% $184.2 $161.0 -$23.2
< -10% to -5% 613,013 20.8% 0.2% 30.2% 0.3% 99.7% 97.4% 2.6% 351 952 21.4 19.9 -7.1% $203.5 $189.0 -$14.5
< -5% to -3% 472,273 16.0% 0.1% 23.3% 0.2% 99.8% 98.8% 1.2% 351 802 18.5 17.8 -3.8% $148.3 $142.7 -$5.6
< -3% to 0% 974,102 33.1% 20.1% 39.0% 19.0% 81.0% 91.2% 8.8% 301 470 16.2 15.9 -1.8% $76.1 $74.8 -$1.3
> 0% to 3% 240,554 8.2% 12.3% 6.3% 47.2% 52.8% 81.9% 18.1% 322 531 16.3 16.4 0.6% $86.5 $87.0 $0.5
> 3% to 5% 46,856 1.6% 4.9% 0.1% 96.1% 3.9% 66.6% 33.4% 313 404 15.9 16.6 4.0% $64.3 $66.9 $2.6
>5% to 10% 115,818 3.9% 12.0% 0.3% 95.4% 4.6% 68.7% 31.3% 322 485 16.2 17.4 7.7% $78.4 $84.4 $6.0
> 10% to 15% 148,030 5.0% 15.7% 0.2% 97.3% 2.7% 76.0% 24.0% 326 545 16.0 18.0 12.7% $87.3 $98.3 $11.0
> 15% to 20% 176,244 6.0% 19.1% 0.0% 99.7% 0.3% 81.8% 18.2% 328 539 15.5 18.3 17.5% $83.8 $98.5 $14.6
> 20% to 30% 136,197 4.6% 14.8% 0.0% 100.0% 0.0% 86.6% 13.4% 323 489 14.7 18.0 22.2% $72.1 $88.1 $16.0
>30% to 45% 7,913 0.3% 0.9% 0.0% 100.0% 0.0% 0.7% 99.3% 327 887 14.1 19.0 34.6% $125.5 $168.8 $43.4
Above 45% 181 0.0% 0.0% 0.0% 100.0% 0.0% 0.0% 100.0% 43 824 13.3 19.7 47.6% $110.0 $162.3 $52.4
Group Tota l 2,942,798 100.0% 100.0% 100.0% 31.3% 68.7% 89.5% 10.5% 326 652 18.3 18.0 -1.8% $119.3 $117.2 -$2.1
Note: Customer Charge = $0.88; 4 Tiers; BL = 50% SOUTHERN CALIFORNIA EDISON®
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2012 Functional Revenue Allocation Factors
% of Marginal Cost Revenue Responsibility (MCRR)
Generation Percent of
Total Generation Generation System
(Bundled Energy Capacity Sales (incl.
Rate Class Distribution Sales) (Bundled Sales) (Bundled Sales) losses)
Total Residential 50.03% 41.49% 37.81% 47.77% 37.14%
GS-1 6.92% 6.55% 6.60% 6.46% 5.91%
TC-1 0.14% 0.07% 0.09% 0.05% 0.07%
GS-2 20.07% 19.55% 20.17% 18.49% 19.05%
TOU-GS-3 7.90% 8.42% 8.64% 8.04% 9.71%
Total LSMP 35.04% 34.60% 35.50% 33.05% 34.74%
TOU-8-SEC 6.39% 8.46% 8.99% 7.55% 9.74%
TOU-8-PRI 3.55% 4.79% 5.22% 4.05% 5.95%
TOU-8-SUB 0.97% 3.83% 4.37% 2.92% 5.68%
Total Large Power 10.92% 17.07% 18.57% 14.52% 21.37%
TOU-PA-2 1.88% 2.27% 2.50% 1.87% 2.07%
TOU-PA-3 0.84% 1.40% 1.66% 0.96% 1.31%
Total Ag.&Pump. 2.72% 3.67% 4.16% 2.83% 3.38%
Total Street Lights 0.27% 0.59% 0.93% 0.01% 0.55%
Standby-SEC 0.18% 0.23% 0.26% 0.19% 0.25%
Standby-PRI 0.58% 0.69% 0.79% 0.54% 0.77%
Standby-SUB 0.28% 1.65% 1.97% 1.10% 1.81%
Total Standby 1.04% 2.58% 3.02% 1.82% 2.83%
SYSTEM 100.00% 100.00% 100.00% 100.00% 100.00%
The allocation factors indicate the relative importance of various revenue requirement changes upon different rate
groups. For example, a “distribution” case (e.g. GRC Phase 1) has a larger impact on Residential customers versus
Large Power customers, who are more strongly affected by “generation” cases (e.g. ERRA).
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2012 GRC Phase 2 Class Average Rate Levels –
Average Rate Impacts at June 2011 Present Rate Revenue Levels
Current +Phase 1
% Change (June
June 2011 Proposed Proposed 11 vs.
(¢/kWh) % of SAR (¢/kWh) % of SAR % Change (¢/kWh) % of SAR Current+Phase 1)
Total Domestic 15.6 110% 15.9 113% 2.0% 17.3 114% 10.5%
GS-1 17.0 120% 15.7 111% -8.0% 16.8 111% -1.1%
TC-1 15.3 108% 16.2 114% 5.7% 17.6 116% 15.0%
GS-2 15.2 107% 14.8 105% -2.6% 15.9 104% 4.5%
TOU-GS-3 13.2 93% 13.6 96% 2.9% 14.5 95% 10.0%
Total LSMP 15.0 106% 14.6 104% -2.6% 15.7 103% 4.5%
TOU-8-SEC 12.4 88% 12.1 86% -2.6% 12.9 85% 3.7%
TOU-8-PRI 11.2 79% 11.0 78% -1.4% 11.7 77% 5.0%
TOU-8-SUB 7.1 50% 7.7 55% 9.3% 8.2 54% 15.6%
Total Large Power 10.8 76% 10.7 76% -0.4% 11.4 75% 6.0%
TOU-PA-2 13.0 92% 12.7 90% -2.1% 13.6 90% 4.9%
TOU-PA-3 10.2 72% 10.7 75% 4.7% 11.4 75% 11.6%
Total Ag.&Pumping 11.9 84% 11.9 84% 0.2% 12.7 84% 7.2%
Total Street Lighting 18.0 127% 18.3 130% 2.0% 18.8 123% 4.3%
Standby-SEC 11.5 81% 11.6 82% 0.5% 12.4 81% 7.4%
Standby-PRI 11.3 80% 11.5 81% 1.6% 12.3 81% 8.4%
Standby-SUB 8.1 57% 8.1 58% 0.5% 8.6 56% 5.6%
Total Standby 9.2 65% 9.3 66% 0.8% 9.8 65% 6.7%
Total System 14.2 100% 14.1 100% -0.1% 15.2 100% 7.3%
Note: Data above do NOT include impacts of all 2012 revenue requirements changes.
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Historical Class Average Rates
Southern California Edison Company
Historical Average Rates by Rate Group (¢/kWh)
Based on Recorded Revenue and Sales
– (¢/kWh) Bundled Service Bundled Service
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 1 2012 2
Domestic 11.4 11.4 11.5 13.0 13.5 12.8 12.5 12.9 15.7 15.3 15.0 15.2 15.5 15.5 15.9
GS-1 12.1 12.1 12.0 16.2 17.5 15.8 14.8 15.2 17.6 17.6 17.0 16.9 17.5 17.0 15.7
TC-1 7.3 7.4 7.4 10.3 13.5 12.4 12.0 11.5 13.4 13.5 13.8 14.5 15.8 15.5 16.2
GS-2 9.9 10.2 10.1 13.2 15.5 14.1 13.3 13.5 15.6 14.3 14.3 14.8 15.7 15.4 14.8
TOU-GS-3 9.7 8.9 10.2 13.1 14.7 13.0 11.8 10.8 13.6 14.2 14.1 14.3 13.7 13.4 13.6
Sm. and Medium Comm. 10.3 10.5 10.4 13.7 15.8 14.4 13.5 13.6 15.6 14.9 14.7 15.0 15.5 15.2 14.6
TOU-8-Sec 8.1 8.2 8.7 12.2 14.3 12.6 11.2 11.3 13.2 12.5 12.4 12.7 13.1 12.4 12.1
TOU-8-Pri 7.2 7.4 7.9 10.9 13.0 11.5 10.3 10.7 12.6 11.9 11.8 11.7 11.8 11.4 11.0
TOU-8-Sub 4.9 5.1 5.7 8.3 9.4 8.4 7.4 7.5 9.1 8.3 8.1 7.9 8.0 7.1 7.7
Large Power 6.8 7.1 7.7 10.6 12.6 11.2 9.9 10.0 11.8 11.1 10.9 10.9 11.1 10.4 10.7
TOU-8-Sec-Standby n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 11.6
TOU-8-Pri-Standby n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 11.5
TOU-8-Sub-Standby n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 8.1
Large Power-Standby n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 9.3
PA-1 12.8 12.1 12.1 14.3 15.3 14.9 14.0 15.1 18.2 16.9 17.5 17.8 19.4 19.2
12.7
PA-2 8.7 8.5 8.7 10.7 11.3 10.5 10.4 10.7 12.8 12.5 12.8 13.1 14.8 14.1
AG-TOU 7.4 6.9 7.5 9.4 10.1 9.0 8.5 8.5 10.0 9.6 9.7 9.9 10.9 10.7
10.7
TOU-PA-5 6.9 6.3 7.0 8.8 9.4 8.2 7.8 7.8 9.4 9.0 8.9 9.1 9.9 11.9
Ag. and Pumping 8.8 8.5 8.7 10.6 11.1 9.9 9.4 9.5 11.3 10.9 10.8 11.0 12.0 11.9 11.9
St. and Area Lighting 17.0 14.1 13.9 15.8 17.3 15.5 14.7 14.0 15.3 16.9 17.9 18.7 19.0 18.6 18.3
Total System 9.6 9.9 10.0 12.5 14.0 12.9 12.2 12.4 14.6 14.0 13.8 14.0 14.4 14.1 14.1
1
Based on June 2011 Proposed Rate Revenue (PRR) Rates
2 1 Based on June 2011 Proposed Rate Revenue (PRR )Rates
2012 GRC Proposed Rates
22012 GRC Proposed Rates with no revenue requirement change
3
2012 GRC Proposed Rate Group Change for Ag/Pumping Customers with Demand <Demands < 200 kW (PA-1andmapped to TOU-PA-2) to TOU-PA-2)
32012 GRC Proposed Rate Group Change for Ag/Pumping Customers with 200 kW (PA-1 and PA-2 will be PA-2 will be mapped
4 4
2012 GRC Proposed Rate Group Change for Ag/Pumping Customers with Demand >Demands > 200 kW (AG-TOU and TOU-PA-5 to TOU-PA-3) to TOU-PA-3
2012 GRC Proposed Rate Group Change for Ag/Pumping Customers with 200 kW (AG-TOU and TOU-PA-5 will be mapped will be mapped
22 SOUTHERN CALIFORNIA EDISON®

24. SM
Historical Percent of System Average Rates Southern California Edison Company
Historical Average Rates by Rate Group (¢/kWh)
– Bundled Service Based on Recorded Revenue and Sales
Bundled Service
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 1 2012 2
Domestic 118% 115% 114% 104% 96% 99% 103% 104% 108% 109% 109% 109% 108% 110% 113%
GS-1 125% 122% 120% 130% 125% 122% 121% 123% 121% 126% 123% 120% 122% 120% 111%
TC-1 76% 74% 74% 83% 96% 96% 99% 93% 92% 96% 100% 103% 110% 110% 115%
GS-2 103% 103% 100% 106% 110% 109% 109% 109% 107% 103% 104% 106% 110% 109% 105%
TOU-GS-3 100% 90% 102% 105% 105% 100% 97% 87% 94% 102% 102% 102% 95% 95% 96%
Sm. and Medium Comm. 107% 106% 104% 110% 113% 111% 111% 110% 107% 107% 107% 107% 108% 108% 104%
TOU-8-Sec 84% 83% 87% 98% 102% 98% 92% 92% 90% 90% 90% 91% 91% 88% 86%
TOU-8-Pri 75% 74% 79% 87% 92% 89% 84% 86% 86% 85% 86% 83% 82% 81% 78%
TOU-8-Sub 51% 52% 56% 67% 67% 65% 61% 61% 62% 60% 59% 56% 56% 50% 55%
Large Power 70% 72% 77% 85% 90% 87% 82% 81% 81% 79% 79% 78% 77% 73% 76%
TOU-8-Sec-Standby n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 82%
TOU-8-Pri-Standby n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 82%
TOU-8-Sub-Standby n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 57%
Large Power-Standby n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 66%
PA-1 133% 122% 120% 115% 109% 115% 115% 122% 125% 121% 127% 127% 135% 136%
90%
PA-2 90% 86% 87% 86% 80% 82% 86% 86% 88% 89% 93% 93% 103% 100%
AG-TOU 76% 69% 74% 75% 72% 69% 70% 69% 69% 69% 70% 71% 76% 76%
76%
TOU-PA-5 71% 63% 70% 70% 67% 64% 64% 63% 65% 65% 64% 65% 69% 84%
Ag. and Pumping 92% 85% 87% 85% 79% 76% 77% 77% 78% 78% 78% 79% 84% 85% 84%
St. and Area Lighting 176% 142% 138% 127% 123% 120% 121% 114% 105% 121% 130% 134% 132% 132% 130%
Total System 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
1 1
Based
Based on June 2011 Proposed Revenue (PRR) Rates )Rates
on June 2011 Proposed Rate Rate Revenue (PRR
2 2
2012 GRC Proposed Rates with no revenue requirement change
2012 GRC Proposed Rates
3 3
2012 GRC Proposed Rate Group Change for Ag/Pumping Customers with Demand < 200 kW (PA-1 and PA-2 will be mapped to TOU-PA-2) to TOU-PA-2)
2012 GRC Proposed Rate Group Change for Ag/Pumping Customers with Demands < 200 kW (PA-1and PA-2 will be mapped
4 42012 GRC Proposed Rate Group Change for Ag/Pumping Customers with Demands > 200 kW (AG-TOU and TOU-PA-5 will be mapped to TOU-PA-3
2012 GRC Proposed Rate Group Change for Ag/Pumping Customers with Demand > 200 kW (AG-TOU and TOU-PA-5 will be mapped to TOU-PA-3)
23 SOUTHERN CALIFORNIA EDISON®