June 21, 2017
Business Update
June 2017
Exhibit 99.1
June 21, 2017 1
Statements contained in this presentation about future performance, including, without limitation, operating results, capital
expenditures, rate base growth, dividend policy, financial outlook, and other statements that are not purely historical, are
forward-looking statements. These forward-looking statements reflect our current expectations; however, such statements
involve risks and uncertainties. Actual results could differ materially from current expectations. These forward-looking
statements represent our expectations only as of the date of this presentation, and Edison International assumes no duty to
update them to reflect new information, events or circumstances. Important factors that could cause different results include,
but are not limited to the:
• ability of SCE to recover its costs in a timely manner from its customers through regulated rates, including costs related to
San Onofre and proposed spending on grid modernization;
• decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities, including determinations of
authorized rates of return or return on equity, approval of proposed spending on grid modernization, the outcome of San
Onofre CPUC proceedings, and delays in regulatory actions;
• risks associated with cost allocation, including the potential movement of costs to certain customers, caused by the ability
of cities, counties and certain other public agencies to generate and/or purchase electricity for their local residents and
businesses, along with other possible customer bypass or departure due to increased adoption of distributed energy
resources or technological advancements in the generation, storage, transmission, distribution and use of electricity, and
supported by public policy, government regulations and incentives;
• risks inherent in SCE’s transmission and distribution infrastructure investment program, including those related to project
site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs
(payments due under power contracts in the event there is insufficient transmission to enable acceptance of power
delivery), and governmental approvals;
• ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and
to recover the costs of such insurance or in the absence of insurance the ability to recover uninsured losses; and
• risks associated with the decommissioning of San Onofre, including those related to public opposition, permitting,
governmental approvals, and cost overruns.
Other important factors are discussed under the headings “Risk Factors” and “Management’s Discussion and Analysis” in
Edison International’s Form 10-K, most recent Form 10-Q, and other reports filed with the Securities and Exchange
Commission, which are available on our website: www.edisoninvestor.com. These filings also provide additional information on
historical and other factual data contained in this presentation.
Forward-Looking Statements
June 21, 2017 2
Page
Updated (U) from
May 2017 Business Update for GRC
Rebuttal Testimony Only
EIX Shareholder Value 3 U
SCE Highlights, SCE Long‐Term Growth Drivers, Regulatory Model 4‐6 U
Capital Expenditures and Rate Base History and Forecast 7‐9 U
2018 GRC Overview 10‐12 U
CPUC Cost of Capital 13
Key Regulatory Proceedings 14
Distribution and Transmission Capital Expenditure Detail 15‐19 U
2017 Guidance 20
Operational Excellence 21
EIX Responding to Industry Change 22
Edison Energy 23
Annual Dividends Per Share 24
Appendix
EIX and SCE Tax Reform 26
Historical Capital Expenditures 27
Capital Expenditure and Rate Base Detailed Forecast 28 U
Power Grid of the Future, Grid Modernization 29‐32 U
SCE Customer Demand Trends 33
California Energy Policy 34
SCE Bundled Revenue Requirement, System Average Rate Historical Growth 35‐36
Residential Rate Reform and Other 37‐39
SCE Rates and Bills Comparison 40
First Quarter 2017 Earnings Summary, MHI Award Accounting, Results of Operations, Non‐GAAP Reconciliations 41‐47
Table of Contents
June 21, 2017 3
EIX Strategy Should Produce Superior Value
Sustained Earnings and Dividend
Growth Led by SCE
Positioned for
Transformative Change
SCE Rate Base Growth Drives Earnings
• 8.3% average annual rate base
growth through 2020 at request level
• SCE earnings should track rate base
growth
Constructive Regulatory Structure
• Decoupling of electricity sales
• Balancing accounts
• Forward-looking ratemaking
Sustainable Dividend Growth
• Target dividend growth at a higher
than industry average within target
payout ratio of 45-55% of SCE
earnings
Wires-Focused SCE Strategy
• Infrastructure replacement –safety and
reliability
• Grid modernization –California’s low-
carbon goals
• Operational excellence
Edison Energy Group Strategy
• Edison Energy - services for large
commercial and industrial customers -
capital light business model
• SoCore Energy – commercial and
community solar
June 21, 2017 4
One of the nation’s largest electric utilities
• 15 million residents in service territory
• 5 million customer accounts
• 50,000 square-mile service area
Significant infrastructure investment
• 1.4 million power poles
• 729,000 transformers
• 119,000 miles of distribution and transmission lines
• 3,200 MW owned generation
Above average rate base growth driven by
• Safety and reliability
• California’s low-carbon objectives
Grid modernization
Electric vehicle charging
Energy storage
Transportation electrification (proposed)
Limited Generation Exposure
• Own less than 20% of its power generation
• Future needs via competitive solicitations
SCE Highlights
June 21, 2017 5
SCE Long-Term Growth Drivers
Description Timeframe/Regulatory Process
Sustained level of infrastructure investment
required until equilibrium replacement rates
achieved and then maintained
• Ongoing - current and future GRCs
Accelerate circuit upgrades, automation,
communication, and analytics capabilities at
optimal locations to integrate distributed
energy resources
• 2017-2020 - $2.0 billion capital request in 2018
GRC application
• 2025 – CPUC target to complete grid
modernization but may take longer
Future transmission needs to meet 50%
renewables mandate in 2030 and to support
reliability
• 2017-2021 – Multiple projects approved by CAISO
in permitting and/or construction
• 2021-2030 – Future needs largely driven by CAISO
planning process already initiated
SCE owned investment opportunities under
existing CPUC proceedings
• Today – Most investments via contracts
• 2018-2020 - $60 million of capital requested in
2018 GRC application
• SCE’s storage portfolio is 210 MW as of 2016
Utility investment in programs to build and
support the expansion of transportation
electrification in passenger and light-,
medium- and heavy-duty vehicles and
potentially to support electrification of other
sectors of the economy
• 2016 – Charge Ready Phase I approved
• 2017 – Transportation Electrification plan filed
January 20
• 2017-2030 – Future Charge Ready Phase II and
other transportation electrification investments;
potential investments to support electrification of
other sectors of the economy
Infrastructure
Reliability
Grid Modernization
Electrification of
Transportation and
Other Sectors
Energy Storage
Transmission
June 21, 2017 6
SCE Decoupled Regulatory Model
Decoupling of Regulated
Revenues from Sales
Major Balancing Accounts
• Fuel
• Purchased power
• Energy efficiency
• Pension expense
Advanced Long-Term
Procurement Planning
Forward-looking Ratemaking
• SCE earnings not affected by variability of retail electricity
sales
• Differences between amounts collected and authorized
levels either billed or refunded
• Promotes energy conservation
• Stabilizes revenues during economic cycles
• Trigger mechanism for fuel and purchased power
adjustments at 5% variance level
• Cost-recovery related balancing accounts represented more
than 55% of costs
• Upfront prudent standards with greater certainty of cost
recovery (subject to compliance-related reasonableness
review)
• Three-year rate case cycle
• Separate cost of capital mechanism
Regulatory Model Key Benefits
June 21, 2017 7
SCE Historical Rate Base and Core Earnings
Rate Base
Core Earnings
7%
5%
2011 – 2016 CAGR
($ billions)
Note: Recorded rate base, year-end basis. See SCE Core EPS Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures. Since 2013, rate base excludes SONGS
$18.8
$21.0 $21.1
$23.3
$24.6 $25.9
2011 2012 2013 2014 2015 2016
$4.20$4.68$3.33 $4.10 $3.88
Core
EPS $4.22
June 21, 2017 8
SCE Capital Expenditure Forecast – Request Level
Note: Forecasted capital spending includes CPUC, FERC and other spending. 2018-2020 CPUC based on 2018 GRC request rebuttal testimony. See Capital Expenditure/Rate Base
Detailed Forecast for further information, including potential investment excluded in forecasts. SCE currently sees 2017 capital expenditures of $4.0 billion, reflecting the lack of
approval of a grid modernization memorandum account and minor delays on the start of construction for the Mesa Substation project. Totals may not foot due to rounding
($ billions)
$18.9 Billion Capital Program
for 2017-2020
• Capital expenditure forecast incorporates GRC, FERC and
non-GRC CPUC spending
Grid modernization spending of $2.0 billion during four-
year period
2017 traditional capital spending incorporates 2015 GRC
decision and FERC spending
Includes $289 million of non-GRC CPUC capital spending
for grid modernization and mobile home pilot program
and charge ready pilot in 2017
Excludes transportation electrification and Charge Ready
Phase II
• Authorized/Actual may differ from forecast
Since the 2009 GRC, CPUC has approved 81%, 89%, and
92% of capital requested, respectively
SCE has no prior approval experience on grid
modernization capital spending and, therefore, prior
results may not be predictive
Forecasted FERC capital spending subject to timely
receipt of permitting, licensing, and regulatory approvals
$3.5
$4.2
$4.9 $5.0 $4.9
2016 (Actual) 2017 2018 2019 2020
Distribution Transmission Generation
Traditional Capital Spending:
Grid Modernization Capital Spending:
Grid Modernization
Prior Forecast $4.2 $5.0 $5.1 $5.0
Delta - ($0.1) ($0.1) ($0.1)
June 21, 2017 9
SCE Rate Base Forecast – Request Level
CPUC
• Rate base based on request levels from
2018 GRC Rebuttal Testimony and 2018
positive true-up from authorized to
forecast 2017 rate base
FERC
• FERC rate base is approximately 19% of
SCE’s rate base by 2020; includes
Construction Work in Progress (CWIP)
Other
• No change from prior forecast
• Excludes SONGS regulatory asset
($ billions)
Note: Weighted-average year basis. 2016-2017 based on 2015 GRC decision. 2018-2020 CPUC based on 2018 GRC request rebuttal testimony, FERC based on latest forecast and
current tax law, except “rate-base offset” for the 2015 GRC decision excluded because of write off of regulatory asset related to 2012-2014 incremental tax repairs. As noted on the
SCE Capital Expenditures Forecast slide, the 2017 capital expenditure reduction to $4.0 billion is not reflected in rate base
4-year CAGR of 8.3%
$24.9
$26.2
$29.3
$31.8
$34.3
2016
(Authorized)
2017 2018 2019 2020
Traditional Grid Modernization
Prior Forecast $26.2 $29.3 $32.0 $34.6
Delta - - ($0.2) ($0.3)
June 21, 2017 10
• 2018 GRC Application (A. 16-09-001) filed September 1, 2016
• Addresses CPUC jurisdictional revenue requirement for 2018-2020
Includes operating costs and capital investment
Excludes CPUC jurisdictional costs such as fuel and purchased power, cost of capital and other
potential SCE capital projects (transportation electrification, Charge Ready, and storage outside of
the GRC)
Excludes FERC jurisdictional transmission
• SCE Rebuttal Testimony filed June 16th requests 2018 revenue requirement of $5.859 billion
$196 million increase over presently authorized base rates, a 2.5% increase over total rates
Requests post test year increases: $480 million in 2019 and $556 million in 2020, 3.8% and 5.1%
increases over presently authorized total rates, respectively
• GRC filing advances SCE strategy focusing on safety and reliability by continuing infrastructure
investment and beginning grid modernization investments, mitigating customer rate impacts through
lower operating costs
GRC
Application
Filed
Rebuttal Final
Decision
2016 2017
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Estimated
Intervenor
Testimony
Proposed
Decision
2018 SCE General Rate Case (GRC)
Evidentiary
Hearings
Note: Schedule was set by CPUC, but excludes timing of final decision. The schedule is subject to change over the course of the proceeding
June 21, 2017 11
• Capital expenditures of $1.8 billion for grid
modernization capital to support improved
safety and reliability and increased levels of
distributed energy resources (DER)
Requested approval to establish
memorandum account to facilitate $210
million of grid modernization capital
expenditures in 2016-2017; these
expenditures support 2018 GRC grid
modernization capital request
May need to evaluate grid modernization
capital plan if memorandum account not
approved
• Increased depreciation expense to reflect
updated cost of removal estimates1
Limiting cost of removal request to
mitigate customer rate impact beginning
with $84 million increase in 2018
Further increases will likely be required
over multiple GRC cycles
Items Carried Over from 2015 GRC New Items from 2018 GRC
• Requests continuation of Tax Accounting
Memorandum Account (TAMA) adjusting
revenues annually for over and
undercollection of specified tax items
• Forecasting over $85 million in 2018 O&M
savings from Operational Excellence
initiatives
• Requests recovery for short-term incentive
compensation plans for full-time employees
($41 million disallowance in 2015 GRC
decision)
• Requests continuation of pole loading
capital recovery through balancing account
1. Cost of removal is the cost to remove existing equipment that is being replaced
2018 SCE GRC (cont.)
June 21, 2017 12
ORA submitted testimony on April 7, 2017 – Key elements
• Proposed no Grid Modernization capital expenditures and ~90% of traditional
capital expenditures
• Other items similar to ORA’s 2015 GRC testimony, including incentive
compensation and traditional capital expenditures such as 4kV Cutovers and
Overhead Conductor Program
TURN and other intervenors submitted testimony on May 2, 2017 – Key TURN
elements
• Proposed ~22% of Grid Modernization capital expenditures and ~85% of
traditional capital expenditures
• Proposed rate base adjustments of more than $700 million of historical capital
expenditures related to certain distribution infrastructure replacement programs
SCE Rebuttal filed June 16, 2017
General Rate Case Update – Intervenor Testimony
1. Includes $48 million one-time recovery of pre-2018 Balancing/Memorandum Accounts
2. Forecasting rate base considering the lower of ORA’s and TURN’s recommendations in each year would result in a lower rate base growth rate and revenue requirement
3. CAGR excluding rate base adjustments is 6.5%
Proposed Revenue Requirement Increases
2018
Increase
Post Test Year
2019 2020
SCE Rebuttal1 $196/2.5% 3.8% 5.1%
ORA $14/0.9% 2.7% 4.2%
TURN $129/1.9% -0.6% 3.4%
($ billions)
SCE Rate Base Forecast Comparison to ORA and TURN – 2017-20202
2016 2017 2018 2019 2020 CAGR
SCE’s Rebuttal Forecast $24.9 $26.2 $29.3 $31.8 $34.3 8.3%
SCE’s Request Level Forecast at ORA
Recommended Spending Levels $24.9 $26.2 $28.6 $30.4 $32.2 6.6%
Difference ($0.0) ($0.0) ($0.7) ($1.4) ($2.1)
SCE’s Request Level Forecast at TURN
Recommended Spending Levels and
Proposed Rate Base Adjustments3
$24.9 $26.2 $27.6 $29.4 $31.4 6.0%
Difference ($0.0) ($0.0) ($1.7) ($2.4) ($2.9)
June 21, 2017 13
3
4
5
6
7
10/1/12 10/1/13 10/1/14 10/1/15 10/1/16 10/1/17 10/1/18 10/1/19
R
a
t
e
(
%
)
CPUC Cost of Capital
CPUC Adjustment Mechanism
Moody’s Baa Utility Index Spot Rate
Moving Average (10/1/16 – 02/01/2017) = 4.60%
100 basis point +/- Deadband
Starting Value – 5.00%
Return on Equity (ROE) adjustment mechanism extended
through 2019 under proposed settlement
• ROE adjustment based on 12-month average of Moody’s Baa
utility bond rates, measured from October 1 to September 30
• If index exceeds 100 bps deadband from starting index value,
authorized ROE changes by half the difference
• Starting index value based on trailing 12 months of Moody’s
Baa index as of September 30– 5.00%
• Two year settlement awaiting CPUC approval
ROE set at 10.30%; 2018 true-up of cost of debt/preferred
CPUC Authorized
Settlement
Terms
Capital
Structure 2017 2018-2019
Common Equity 48% 10.45% 10.30%
Preferred 9% 5.79% TBD
Long-term Debt 43% 5.49% TBD
Weighted Average Cost of Capital 7.90% TBD
ROE fixed at
10.30%, for 2018
independent of
trigger mechanism
ROE fixed at
10.45%, for 2017
independent of
trigger mechanism
June 21, 2017 14
SCE Key Regulatory Proceedings
Proceeding Description Next Steps
Key CPUC Proceedings
2018 General Rate Case
(A. 16‐09‐001)
Set CPUC base revenue requirement, capital
expenditures and rate base for 2018‐2020
Ongoing workshops and data requests; awaiting
ALJ schedule; received ORA testimony; remaining
intervenor testimony due May 2, 2017
Cost of Capital
(A. 12‐04‐015)
CPUC capital structure, cost of capital, and
return on equity
CPUC withdrew proposed decision in April 2017;
awaiting new proposed decision
Distribution Resources Plan
OIR (R.14‐08‐013)
Power grid investments to integrate
distributed energy resources
Demo projects underway; Current focus is on
policy track, including Grid Mod, deferral
framework and DER forecasting
Integrated Distributed Energy
Resources OIR (R. 14‐10‐003)
Creating consistent framework for guidance,
planning and evaluation of DERs
Ongoing workshops, stakeholder review of utility
planning activities; utilities to file advice letter in
June 2017 proposing procurement of two (or more)
deferral projects
SONGS OII
(I.12‐10‐013)
OII resolved (December 2015); Proceeding
record reopened in May 2016
Three meet and confer sessions held; parties have
agreed to mediation and in April 2017 requested
extension to August 15, 2017 to report to the CPUC
on the results of the process
Charge Ready Program
(A.14‐10‐014)
Implementation program for charger
installations and market education
Phase 1 pilot program approved January 2016;
request for Phase 2 to be submitted after Phase 1
completion; plan to file Phase I report in May 2018
Alternative‐Fueled Vehicle OIR
(R. 13‐11‐007)
Scope broadened March 2016 to address SB
350 transportation electrification objectives
Utility project proposals filed January 2017; scoping
memo issued in April 2017
Key FERC Proceedings
FERC Formula Rates Transmission rate setting with annual updates Settlement in place through December 2017;
replacement rate to be filed in Q4 2017
June 21, 2017 15
SCE Distribution System Investments
1. Other includes GRC energy storage, Charge Ready Phase I and mobile home pilot programs
Distribution Trends
• Continued focus on safety and reliability with
infrastructure replacement representing 44% of total
distribution capital spend, but not yet reaching
equilibrium replacement rate
Includes pole loading replacement program and
overhead conductor replacements
• Distribution grid requires upgrades to circuit
capacity, automation, and control systems to
support reliability as use of distributed energy
resources increases
• Includes grid modernization capital which is
expected to become a larger portion of spend
beyond 2017
2017 – 2020 Capital Spending Forecast
for Distribution1 – Request Level
$14.5 Billion
2018-2020 Capital Spending Drivers
• Automation of over 850 distribution circuits
• Over 2,000 miles of cable replacements
• 4kV cutovers/removals
• Distribution preventive maintenance
• Overhead conductor replacements
• Circuit breaker replacements/upgrades
Load
Growth
New Service
Connections
Infrastructure
Replacement
General Plant
Grid
Modernization
Other
June 21, 2017 16
Energy Storage
Given counting rules, SCE has already met the aggregate
2016 targets
CPUC Energy Storage Program Requirements:
• Storage Rulemaking (R.10-12-007) established 1,325 MW target
for IOUs by 2024 (580 MW SCE share; spread as biennial targets
during 2014-20); ownership allowed up to 50% of total target (290
MW SCE share)
• Flexibility to transfer across categories, recently expanded in
Storage Rulemaking (R.15-03-011)
SCE Procurement Activities to Meet CPUC Requirements:
SCE’s storage portfolio includes resources procured through storage-
specific RFOs, broader solicitations (e.g., LCR RFO, PRP 2 RFO), SCE-
owned pilots and demonstrations, and customer programs
• SCE has procured 500 MW total, of which 424 MW is eligible to
count to the targets (note: all numbers rounded)
The 424 MW includes 60 MW from SCE’s Preferred Resources
Pilot 2 solicitation, currently pending approval
The 424 MW includes approximately 55 MW of Utility-owned
Storage
o 15 MW are previous pilots and demonstrations
o 40 MW sought cost recovery via the Aliso Canyon
application in Q1 2017
• SCE’s Energy Storage RFO is in progress and will close Q3 2017
New Legislation:
• CPUC approved the Energy Storage Track 2 decision to implement
AB 2868 and its requirement that the IOUs propose programs and
investments for up to 500 MW of distributed energy storage
systems. SCE’s portion is approximately 166 MW
Cost Recovery Mechanism for Storage
Utility-Owned Storage (“UOS”)
(except Aliso Canyon RFP)
Capital Expenditures – General
Rate Case
Third-Party Owned Storage Energy Resource Recovery
Account
Aliso Canyon UOS Application filed March 30
115
70
25
0
50
100
150
200
250
Transmission Distribution Customer
M
W
SCE 2017 Storage Portfolio
85 MW
excess may
offset T&D
targets
Eligible storage included in
approved 2016 Storage Plan
New procurement; some contracts
pending CPUC approval.
Currently above targets
2016 Cumulative
Procurement Target
June 21, 2017 17
SCE Transportation Electrification Proposals
On January 20, 2017, SCE filed with the CPUC a wide-ranging plan to increase electrification of cars,
buses, medium- and heavy-duty trucks and industrial vehicles and equipment
• SCE proposed 6 near-term, priority-review projects and 2 longer-term, standard-review programs for a total
of $574 million of total costs (includes both O&M and capital expenditures)
• Proposal is not currently in capital expenditure and rate base forecast
SCE’s Charge Ready Program addresses approximately 1/3 of forecast 2020 non-single family
home charging demand in SCE territory and supports Governor’s 2012 zero-emission vehicle
Executive Order – 1.5 million EVs statewide by 2025
• Phase I ($22 million cost; $12 million rate base) approved by CPUC in January 2016 to support
approximately 1,500 chargers (2016-2017)
• Phase II request to be filed after completion of Phase I: proposal details TBD; likely to be filed in 2018
SCE 2017 Transportation Electrification Application Proposals
Program Name Category Timeframe Estimated Total Cost1
Residential Make-Ready Rebate Incentive Pilot Near-term $4
EV Drive Rideshare Reward Incentive Pilot Near-term $4
Urban Direct Current Fast Charge Clusters Infrastructure Pilot Near-term $4
Electric Transit Bus Make-Ready Infrastructure Pilot Near-term $4
Port of Long Beach (POLB) ITS Terminal Yard Tractor Infrastructure Pilot Near-term $0.5
POLB Rubber Tire Gantry Crane Electrification Infrastructure Pilot Near-term $3
Medium and Heavy-Duty Vehicle Charging Infrastructure Program Long-term $554
New Commercial Electric Vehicle Rate Proposal Rate Design Program Long-term N/A
1. Estimated Total Cost in $millions of constant dollars
June 21, 2017 18
Transportation Electrification Overview
California’s goals to reduce total GHG emissions by 40 percent
from 1990 levels by 2030 is 42% from current levels
• Recent Governor Order set a 2050 target of 80% below 1990 levels
Many of California's policies to date focused on electric power,
but other key areas need to be considered
• Including the refining process, GHG emissions from the
transportation sector is greater than 50% of the state’s emissions
Commercial and
Residential
9%
Electrical
Power
20%
Agriculture
8%
Industrial
21%
Transportation
36%
Other
6%
SCE is taking a leading role to ensure that transportation electrification plays a major part in reducing GHG
and criteria pollutant emissions in California
2014 California GHG Emissions
by Sector
Note: Data for both charts from California Air Resources Board
June 21, 2017 19
SCE Large Transmission Projects
1. CPUC approved
2. FEIR issued and revised costs are being developed, expected Q2
3. Morongo Transmission holds an option to invest up to $400 million, or half of the estimated cost of the transmission facilities only, at the in-service date. If the option is
exercised, SCE’s rate base would be offset by that amount
4. Total Costs are nominal direct expenditures, subject to CPUC and FERC cost recovery approval. SCE regularly evaluates the cost and schedule based on permitting processes,
given that SCE continues to see delays in securing project approvals
FERC Cost of Capital
10.5% ROE in 2017:
• Base ROE = 9.30% + CAISO participation +
weighted average of individual project incentives
• FERC Formula recovery mechanism in effect
through December 31, 2017
• Application for 2018 FERC Formula recovery
mechanism expected to be filed in Q4 of 2017
• Recent court decisions and lack of FERC quorum
could delay some decisions into 2018
Summary of Large Transmission Projects
Project Name Total Cost4 Remaining Investment(as of March 2017) In-Service Date
West of Devers1,3 $1.1 billion $1.01 billion 2021
Mesa Substation1 $608 million $577 million 2022
Alberhill System2 $397 million $360 million 2021
Riverside Transmission Reliability $233 million $227 million 2021
Eldorado-Lugo-Mohave Upgrade $269 million $264 million 2020
June 21, 2017 20
$4.05 $4.14(0.25)0.34
SCE 2017 EPS from
Rate Base Forecast
SCE Variances EIX Parent
& Other
EIX 2017 Core EPS
Midpoint Guidance
• O&M and
financing
benefits -
$0.31
• Energy
efficiency -
$0.03
2017 Core Earnings Per Share Guidance –
Building from SCE Rate Base
• SCE authorized rate base $26.2 billion
• Energy efficiency earnings $0.03 per
share
• Authorized CPUC capital structure - 48%
equity and 10.45% ROE
• FERC ROE of 10.5%
• No change in tax policy
• 325.8 million common shares
• Includes share-based tax benefits as
recorded in Q1 2017
• MHI arbitration decision not included –
$47 million pre-tax SCE recovery
recorded as regulatory liability due to
uncertainty - no earnings impact
• SONGS settlement continues to be
implemented as approved by the CPUC
Key Assumptions
• Holding
Company -
($0.17)
• Edison Energy
Group - ($0.08)
2017 Earnings Per Share Guidance
2017 EIX Earnings Per Share Guidance
As of
February 21, 2017
Reaffirmed As of
May 1, 2017
Low Mid High Low Mid High
EIX Basic EPS $4.04 $4.14 $4.24 $4.04 $4.14 $4.24
Less: Non-Core Items1 - - - - - -
EIX Core EPS2 $4.04 $4.14 $4.24 $4.04 $4.14 $4.24
1. There were no non-core items for the three months ended March 31, 2017
2. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix
It is early in the year and our normal practice is to wait until later in the year before formally updating
guidance. At the same time we recognize there is a bias to the upper half of the guidance range
June 21, 2017 21
SCE Operational Excellence
Top Quartile
• Safety
• Reliability
• Customer service
• Cost efficiency
Optimize
• Capital productivity
• Purchased power cost
High performing, continuous
improvement culture
Defining Excellence Measuring Excellence
• Employee and public safety
metrics
• System performance and
reliability (SAIDI, SAIFI,
MAIFI)
• J.D. Power customer
satisfaction
• O&M cost per customer
• Reduce system rate growth
with O&M / purchased
power cost reductions
Ongoing
Operational
Excellence
Efforts
June 21, 2017 22
Responding to Industry Change
• Public policy and large commercial
customers prioritizing sustainability
objectives
• Innovation facilitating conservation and
self-generation
• Regulation supporting new forms of
competition
• Flattening domestic demand for
electricity
• Power grid of the future will be more
complex and sophisticated to support
increasing use of distributed resources
and transportation electrification
SCE Strategy
• Invest in, build, and operate the next
generation electric power grid
• Operational and service excellence
• Enable California public policies
Edison Energy Group
• Position as an independent Energy
Advisor and Integrator for large
commercial and industrial customers –
capital light business model
• Solar opportunities focused on
commercial and industrial customers, co-
operatives and community solar
programs
• Founding member of Grid AssuranceTM
Long-Term Industry Trends Strategy
June 21, 2017 23
• Edison Energy is an advisory and services
company with the capabilities to develop and
integrate an array of energy solutions to help
commercial and industrial customers improve
management of their energy costs and risks
in dealing with increasingly complex tariff
and technology choices
• Edison Energy was formed by Edison
International through the acquisition of three
companies in December 2015: Altenex,
Eneractive Solutions and Delta Energy
• Edison International investment $103 million
as of March 31, 2017
Edison Energy
Edison Energy Group Summary
SoCore Energy
• Provider of distributed solar solutions
focused on the following segments:
Commercial & Industrial
Electric Cooperatives & Municipalities
Community Solar
Advanced Energy Solutions - commercial
and distributed energy storage
• 98 MW of commercial-scale solar systems
constructed and in operation as of March 31,
2017
• Edison International investment $195 million
as of March 31, 2017
The Opportunity: Trusted Advisor and Solution Integrator
June 21, 2017 24
EIX Annual Dividends Per Share
$0.80
$1.00
$1.08
$1.16 $1.22
$1.24 $1.26 $1.28 $1.30
$1.35
$1.42
$1.67
$1.92
$2.17
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Note: See Use of Non-GAAP Financial Measures
Thirteen Years of Dividend Growth
Target dividend growth at a higher than industry average growth rate within its
target payout ratio of 45-55% of SCE earnings in steps over time
June 21, 2017 25
Appendix
June 21, 2017 26
Key Reform
Considerations
Impact on
Customer / Shareholder Comments
No interest deductibility Negative Negative
• Permanent increase in customer rates
(top concern)
• Costs passed through but lowers tax
shield
Lower tax rate (15%-20%) Positive
Negative at EIX
holding
company
• Lower customer rates
• Remeasurement of EIX holding
company tax assets and lower tax shield
100% capital expensing Mixed Mixed
• Timing benefit only
• Customer rates may be impacted by
treatment of property-related
deductions
Net Deferred Tax Liability / (Asset)
As of 12/31/2016; ($ in millions) SCE HoldCo
Property-related and other $9,798 ($165)
Operating loss / credit carryforward - (1,152)1
Net deferred tax liability / (asset) $9,798 ($1,317)1,2
1. Excludes $242 million of deferred tax assets allocated to third parties
2. Includes $58 million of state deferred tax assets
EIX and SCE Tax Reform
June 21, 2017 27
SCE Historical Capital Expenditures
($ billions)
$3.9
$3.5
$4.0 $3.9
$3.5
2012 2013 2014 2015 2016
June 21, 2017 28
Detailed Capital Expenditures at Request Level – 2016-2020
2016
(Actual) 2017 2018 2019 2020 Total
Core Distribution1,2 $2.9 $3.0 $3.2 $3.2 $3.1 $15.3
Mobile Home Pilot Program - 0.1 - - - 0.1
Grid Modernization - 0.2 0.5 0.7 0.6 2.0
Subtotal Distribution $2.9 $3.3 $3.7 $3.9 $3.7 $17.4
Transmission1 $0.4 $0.6 $0.9 $1.0 $1.0 $4.0
Generation1 $0.2 $0.2 $0.2 $0.2 $0.2 $1.0
Total $3.5 $4.2 $4.9 $5.0 $4.9 $22.4
Capital Expenditure/Rate Base Detailed Forecast
Detailed Rate Base at Request Level – 2016-2020
2016
(Actual) 2017 2018 2019 2020
Traditional Rate Base $24.9 $26.2 $29.0 $31.1 $33.1
Grid Modernization - - 0.3 0.7 1.2
Total $24.9 $26.2 $29.3 $31.8 $34.3
1. Includes allocated capitalized overheads and general plant
2. Includes $12 million Charge Ready Phase I (2017) and $60 million of GRC Energy Storage (2016-2020; average $12 million per year)
Note: Totals may not foot due to rounding
($ in billions)
June 21, 2017 29
Distribution Power Grid of the Future
One-Way Electricity Flow
• System designed to distribute
electricity from large central
generating plants
• Very few distributed energy
resources
• Voltage centrally maintained
• Limited situational awareness and
visualization tools for power grid
operators
Renewable Generation Mandates
Subsidized Residential Solar
Limited Electric Vehicle Charging
Infrastructure
Variable, Two-Way Electricity Flow
• Distribution system at the center of
the power grid
• System designed to manage
fluctuating resources and customer
demand
• Digital monitoring and control devices
and advanced communications
systems to manage two-way flows
• Improved data management and
power grid operations with cyber
mitigation
Maximize Distributed Resources and
Electric Vehicle Adoption
• Distribution power grid infrastructure
design supports customer choice and
greater resiliency
Current State Future State
June 21, 2017 30
Computing intelligence inside
electrical substations
Future circuit
designs integrate
Distributed
Energy Resources
and increase
flexibility
The distribution
system will require
transformative
technologies in
planning, design,
construction and
operation
Net benefits to
customers include
increased safety,
reliability, access to
affordable
programs, and
ability to adopt
new clean and
distributed
technologies
State of the art
operating tools
for utility
operators and
engineers
Remote sensors that collect
localized information about the grid
Devices that provide
more flexibility during
outage events
Devices that provide stable voltage and power quality
High speed wireless and
fiber communications
infrastructure
Smart meters that provide
information to facilitate
customer reliability and
affordability
Grid Modernization Highlights
Legend
Remote Fault Indicator
High speed bandwidth field area network
(communication system)
Intelligent Remote Switches
Automated switched capacitor bank w/ voltage control
June 21, 2017 31
$0.03
$0.18
$0.54
$0.65
$0.61
2016
(Actual)
2017 2018 2019 2020
Building next generation electric grid requires
accelerating traditional Transmission and
Distribution / Information Technology programs
and investing in new capabilities
• Increased capacity: Upgrade portions of the grid (such as
4kV system) to increase capacity, improve reliability, and
address technology obsolescence
• Advanced Capabilities: Automation to monitor and
control grid equipment in real-time
• Communication Networks: Expansion of fiber optic
network and field area network for real-time data transfer
• Technology Platforms: Foundational tools for forecasting
and planning; management systems to operate the
distribution grid
Capital will be deployed to achieve two primary
objectives
• Improving safety and reliability
Focus on worst performing circuits in conjunction with
traditional infrastructure replacement activities
• Increase DER integration and enable advanced operations
on circuits with high forecasted penetration or where
DERs can provide grid services
1. 2018-2020 CPUC based on 2018 GRC request rebuttal testimony; conceded grid modernization capital expenditures are expected to be requested in future GRC applications
2. Forecast excludes capitalized overheads
3. Pending approval of memorandum account for 2016 and 2017 forecast and 2018 GRC decision for 2018-2020 forecast
SCE Grid Modernization – Request Level1
($ billions)
$2.0 Billion Capital Request for 2017-20202,3
Prior Forecast $0.18 $0.64 $0.75 $0.71
Delta - ($0.10) ($0.10) ($0.10)
June 21, 2017 32
Distributed Energy Resources (DER) Proceedings
2017 Activities
• Utility incentive pilot, including
a competitive solicitation
framework and consultation
with a stakeholder Distribution
Planning Advisory Group
• Regulatory approval of
proposed pilot projects
• Societal Cost Test
• A societal cost based
Greenhouse Gas Adder for use
in cost-effectiveness of Energy
Efficiency and other DERs
2017 Activities
• DER Hosting Capacity analysis
• Locational Net Benefits
• Data Access
• Forecasting and planning
alignment
• Power Grid and integration
into General Rate Case
• Deferral framework
•Integration of DERs in distribution planning and
operations
•Development of tools and methodologies,
including optimal locations & value of DERs
•Framework for Grid Modernization
•Field demonstrations
Distribution
Resource Plan (DRP)
Proceeding’s Scope
Elements
•Define DER products & grid services
•Sourcing DERs for grid need via competitive
procurement, programs, and tariffs
•DER cost-effectiveness methods
•Utility incentives to pursue DERs for grid need,
instead of traditional infrastructure
•Utility role in DER markets; utility business model
Integrated
Distributed Energy
Resources (IDER)
Proceeding’s Scope
Elements
June 21, 2017 33
2016
29,141
41,565
7,056
4,645
1,776
84,183
1,794
85,977
4,417,340
565,222
10,445
46,133
21,233
133
22
5,060,528
38,076
23,091
SCE Customer Demand Trends
Kilowatt-Hour Sales (millions of kWh)
Residential
Commercial
Industrial
Public authorities
Agricultural and other
Subtotal
Resale
Total Kilowatt-Hour Sales
Customers
Residential
Commercial
Industrial
Public authorities
Agricultural
Railroads and railways
Interdepartmental
Total Number of Customers
Number of New Connections
Area Peak Demand (MW)
2012
30,563
40,541
8,504
5,196
1,676
86,480
1,735
88,215
4,321,171
549,855
10,922
46,493
21,917
83
24
4,950,465
22,866
21,996
2013
29,889
40,649
8,472
5,012
1,885
85,907
1,490
87,397
4,344,429
554,592
10,584
46,323
21,679
99
23
4,977,729
27,370
22,534
Note: See 2015 Edison International Financial and Statistical Reports for further information
2014
30,115
42,127
8,417
4,990
2,025
87,674
1,312
88,986
4,368,897
557,957
10,782
46,234
21,404
105
22
5,005,401
29,879
23,055
2015
29,959
42,207
7,589
4,774
1,940
86,469
1,075
87,544
4,393,150
561,475
10,811
46,436
21,306
130
22
5,033,330
31,653
23,079
June 21, 2017 34
California’s Energy Policy
• On October 7, 2015, Governor Brown signed SB 350, which
requires that 50 percent of energy sales to customers come
from renewable power and a doubling of energy efficiency in
existing buildings for California by 2030
Also requires Transportation Electrification investments and
Integrated Resources Planning
To meet the 50% RPS requirement by 2030, SCE will need to
increase its renewable purchases by 17.7 billion kWh, or
85%1
• On September 8, 2016, Governor Brown sighed SB 32, which
requires statewide GHG emissions to be reduced to 40% below
the 1990 level by 2030
Renewables Transportation
Electrification
Energy
Efficiency
Legislative Action
• Emissions targets met through
optimization of renewables,
transportation electrification,
energy efficiency
Regulatory Approach: Company
participation through
infrastructure investment
• SCE Charge Ready Program
• Other medium and heavy duty
transportation electrification in
service territory
Continuation of company
programs and earnings incentive
mechanism
• SCE 2017 program budget:
$258 million2
• $0.03 per share earnings in 2016
Electric Power Company Roles
Solar 26%
Small Hydro
2%
Geothermal
37%
Wind 33%
2016 Preliminary Renewable Resources:
28.3% of SCE’s portfolio
Biomass 2%
1. Assumes constant customer load
2. Pending approval of Advice Letter; SCE 2016 program budget of $333 million is in effect until approved
June 21, 2017 35
SCE 2017 Bundled Revenue Requirement
Note: Rates in effect as of October 1, 2016. Represents bundled service which excludes Direct Access customers that do not receive generation services
SCE Systemwide Average Rate History (¢/kWh)
2010 2011 2012 2013 2014 2015 2016 2017
14.3 14.1 14.3 15.9 16.7 16.2 14.8 15.8
Fuel & Purchased Power
(45%)
Distribution
(39%)
Transmission (9%)
Generation
(9%)
Other (-2%)
2017 Bundled
Revenue
Requirement
$millions ¢/kWh
Fuel & Purchased Power – includes CDWR Bond Charge 5,130 7.1
Distribution – poles, wires, substations, service centers; Edison
SmartConnect®
4,386 6.1
Generation – owned generation investment and O&M 1,075 1.5
Transmission – greater than 220kV 1,064 1.5
Other – CPUC and legislative public purpose programs, system
reliability investments, nuclear decommissioning, and prior-
year over collections
(276) (0.3)
Total Bundled Revenue Requirement ($millions) $11,379
Bundled kWh (millions) 71,961
= Bundled Systemwide Average Rate (¢/kWh) 15.8¢
June 21, 2017 36
9.7¢
15.8¢
8.0¢
10.0¢
12.0¢
14.0¢
16.0¢
18.0¢
20.0¢
22.0¢
1990 1993 1996 1999 2002 2005 2008 2011 2014 2017
Energy Crisis and
return to normal
cost of service
rates
Higher gas prices post-Katrina leads to
higher rates with subsequent refund of
over collection
Delay in 2012 GRC leads
to shorter ramp-up of rate
increase
¢/kWh
Rates reduced from implementation of
1) the SONGS Settlement, including NEIL
insurance benefits, 2) lower fuel &
purchased power costs, and 3) a lower
2015 GRC revenue requirement that
includes flow-through tax benefits
System Average Rate Historical Growth
SCE’s system average rate has grown at slightly less inflation over the last 20 years
SCE System Average Rate
Los Angeles Area Inflation
Comparative System
Average Rates
% Delta
EIX – 15.8¢ --
PG&E – 18.8¢ 19%
SDG&E – 21.8¢ 38%
CAGR
20‐yr
('97‐’17)
10‐yr
('07‐'17)
5‐yr
('12‐'17)
2.4% 0.7% 0.5%
2.5% 0.8% 0.4%
June 21, 2017 37
Residential Rate Design OIR Decision
• CPUC Order Instituting Ratemaking R.12-06-013 comprehensively reviewed residential rate structure,
including a future transition to time of use (TOU) rates
• July 2015 CPUC Decision D.15-07-001 includes:
Transition to 2 tiered rates by 2019
“Super User Electric Surcharge” for usage 400% above baseline (~5% of current residential load)
Continue fixed charge at $0.94/month, allowing IOUs to re-file fixed charge requests as early as
2018.
Minimum bills up to $10/month, which would apply to delivery revenue only
Current Rates (non-CARE) –
January 2017
Future Rates (non-CARE) –
2019
Note: Graphs not to scale; 2019 rate levels are based on current revenue requirements. The baseline allowance varies by season and household. For this particular scenario, the baseline
region selected was 9. For the summer, the baseline allowance is 420 kWh and 380 kWh for a non-all-electric and an all-electric household, respectively. For the winter, the baseline
allowance is 322 kWh and 447 kWh for a non-all-electric and an all-electric household, respectively.
17.2¢
38.5¢
100% 101‐400% >400%
22.0¢
Usage Level (% of Baseline)
¢
/
k
W
h
Usage Level (% of Baseline)
16.3¢
24.9¢
31.4¢
100% 101‐400% >400%
¢
/
k
W
h
Fixed Charge: $0.94/month
Minimum Bill: $10.00/month
June 21, 2017 38
SCE Net Metering Rate Structure
NEM Rate Developments:
• NEM allows residential customers to receive full-retail rate credit
for exported generation and use these credits to offset energy
purchased from the electric power company, leading to a cost-shift
to non-NEM customers
Through tiered rate flattening, Residential Rate OIR decision is
expected to reduce subsidy by about 20%
• Current NEM tariff ends on July 1, 2017 or earlier if NEM
installations reach the 5% cap (2,240 MW for SCE)
Customers on current tariff grandfathered for 20 years
• In January 2016, CPUC voted (3-2) to adopt a successor to the
current NEM tariff
• PG&E, SDG&E, SCE, and TURN filed Applications for Re-hearing
(AFRs) on March 7, 2016; Solar Parties filed protest responses to the
AFRs on March 21, 2016; CPUC denied parties’ AFRs on September
22, 2016
SCE Net Energy Metering Statistics (March 2017):
• 220,392 combined residential and non-residential projects – 1,786
MW installed (of 2,240 MW cap)
99.7% solar
215,127 residential – 1,134 MW
5,265 non-residential – 652 MW
Approximately 3,407,113 MWh/year generated
7¢
22₵15₵
0
5
10
15
20
25
¢
/
k
W
h
Solar Subsidies
(Illustrative)
Avoided
Generation
(excludes RPS
Premium)
Subsidy Paid by
Residential
Ratepayers [1]
Equivalent
Solar Offset
1. Subsidy Paid by non-Residential Ratepayers estimated to be lower than that paid by Residential Ratepayers. For instance, the Equivalent Solar Offset, system-wide, is
approximately 15¢/kWh (a low ballpark figure), making the Subsidy Paid by non-NEM Ratepayers, system-wide, roughly 8¢/kWh. Exact figures pending analysis
June 21, 2017 39
Note: NEM solar installations in SCE service territory include projects with solar PV only less than 1 MW
Residential Solar Installations in SCE Territory
July 1, 2017
• NEM customers will be
required to take service under
mandatory Time-of-Use rate
• SCE is not expected to hit 5%
NEM cap (2,240MW SCE
share), prior to July 1, 2017
2019
• Commission to revisit NEM
Successor Tariff
Key Dates
Monthly Installations and MW Installed
0
5
10
15
20
25
30
35
40
0
1000
2000
3000
4000
5000
6000
7000
2010 2011 2012 2013 2014 2015 2016 2017
M
W
I
n
s
t
a
l
l
e
d
N
u
m
b
e
r
o
f
R
e
s
i
d
e
n
t
i
a
l
I
n
s
t
a
l
l
a
t
i
o
n
s
Installations MW
June 21, 2017 40
SCE Rates and Bills Comparison
SCE’s average residential rates are above national average,
but residential bills are below national average due to lower usage
• SCE’s residential rates are above national
average due, in part, to a cleaner fuel mix.
Costs for low carbon energy are higher than
those of high-carbon sources
• Average monthly residential bills are
substantially lower than national average.
Higher rate levels are offset by lower usage
Lower SCE residential customer usage
than national average, from mild climate
and higher energy efficiency building
standards
Key FactorsKey Factors
1. EIA's Form 826 Data Monthly Electric Utility Sales and Revenue Data for 12 months up through December 2016. https://www.eia.gov/electricity/data/eia861m/index.html
2. Average 2016 only residential rate (¢/kWh), calculated from SCE’s 2016 recorded data.
3. Average 2016 only residential bill ($/month), calculated from SCE’s 2016 recorded data.
12.6 ₵ [1]
16.2 ₵ [2]
US Average SCE
29%
Higher
2016 Average Residential Rates
(¢/kWh)
2016 Average Residential Bills
($ per Month)
$112 [1]
$91 [3]
US Average SCE
23%
Lower
June 21, 2017 41
Q1
2017
Q1
2016
Variance
Basic Earnings Per Share (EPS)1
SCE $1.07 $0.90 $0.17
EIX Parent & Other 0.04 (0.04) 0.08
Basic EPS $1.11 $0.86 $0.25
Less: Non-Core Items
SCE $ $ $
EIX Parent & Other2 0.01 (0.01)
Total Non-Core Items $ $0.01 $(0.01)
Core Earnings Per Share (EPS)1
SCE $1.07 $0.90 $0.17
EIX Parent & Other 0.04 (0.05) 0.09
Core EPS1 $1.11 $0.85 $0.26
Key SCE EPS Drivers
Revenue3,4 $0.12
- CPUC – Escalation 0.11
- CPUC – Other 0.01
Lower O&M 0.06
Higher depreciation (0.04)
Higher net financing costs (0.03)
Income tax3,4 0.06
Total core drivers $0.17
Non-core items −
Total $0.17
First Quarter Earnings Summary
Key EIX EPS Drivers
EIX parent – Tax benefits on stock option
exercises and other
$0.09
Total core drivers $0.09
Non-core items2 (0.01)
Total $0.08
1. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix
2. Impact includes hypothetical liquidation at book value (HLBV) for SoCore Energy projects
3. Excludes lower income tax benefits for incremental tax repair deductions and pole-loading program-based cost of removal of $0.06 per share
4. Excludes higher income tax benefits of $0.12 per share for the San Onofre tax abandonment in 2017
Note: First quarter 2016 earnings was updated to reflect the implementation of the accounting standard for share-based payments effective January 1, 2016. Diluted earnings were
$1.10 and $0.85 per share for the three months ended March 31, 2017 and 2016, respectively
June 21, 2017 42
MHI Award Accounting
• On March 13, 2017, a decision was received
from the International Chamber of
Commerce International Court (ICC)
regarding the MHI Arbitration
• $47.1 million net proceeds received by SCE
• CPUC will review the documentation of the
final resolution of the MHI dispute and the
legal costs incurred in pursuing claims
against MHI to ensure such costs are not
unreasonable in relation to the recovery
obtained
• Due to uncertainty associated with the
treatment of the proceeds, no gain recorded
• SONGS owners have elected not to appeal
the decision
MHI Arbitration Decision Calculation
Total Liability Under Contract $137.5
Additional Interest (to be paid by MHI) 33.7
Total MHI Proceeds $163.7
Prior Invoice Paid by MHI (45.4)
MHI Litigation Costs (to be paid by
claimants)
(58.1)
Remaining Proceeds $60.2
Co-participants Share (13.1)
SCE Cash Proceeds Received $47.1
($ millions)
June 21, 2017 43
$6,305
—
1,977
1,915
334
—
4,226
2,079
(525)
64
1,618
507
1,111
113
$998
$5,180
4,266
913
—
—
—
5,179
1
(1)
—
—
—
—
—
$—
$11,485
4,266
2,890
1,915
334
—
9,405
2,080
(526)
64
1,618
507
1,111
113
$998
(370)
$1,368
SCE Annual Results of Operations
• Earning activities – revenue authorized by CPUC and FERC to provide reasonable cost recovery and return on investment
• Cost-recovery activities – CPUC- and FERC-authorized balancing accounts to recover specific project or program costs, subject
to reasonableness review or compliance with upfront standards
Earning
Activities
Cost-
Recovery
Activities
Total
Consolidated
2016
Earning
Activities
Cost-
Recovery
Activities
Total
Consolidated
2015
Operating revenue
Purchased power and fuel
Operation and maintenance
Depreciation, decommissioning and amortization
Property and other taxes
Impairment and other charges
Total operating expenses
Operating income
Interest expense
Other income and expenses
Income before income taxes
Income tax expense
Net income
Preferred and preference stock dividend
requirements
Net income available for common stock
Less: Non-core earnings
Core Earnings
Note: See Use of Non-GAAP Financial Measures
($ millions)
$6,504
—
1,939
1,998
351
—
4,288
2,216
(540)
79
1,755
256
1,499
123
$1,376
$5,326
4,527
798
—
—
—
5,325
1
(1)
—
—
—
—
—
$—
$11,830
4,527
2,737
1,998
351
—
9,613
2,217
(541)
79
1,755
256
1,499
123
$1,376
—
$1,376
June 21, 2017 44
2016 Retrospectively Adjusted EPS by Quarter
20161 Q4 Q3 Q2 Q1
Earnings (loss) per share attributable
to Edison International
Continuing Operations
SCE $4.22 $1.01 $1.34 $0.98 $0.90
Edison International Parent & Other (0.23) (0.04) (0.05) (0.11) (0.04)
Discontinued Operations 0.03 0.04 (0.01)
Edison International $4.02 $1.01 $1.29 $0.86 $0.86
Less: Non-Core Items
SCE
Edison International Parent & Other 0.02 0.01 0.01
Discontinued Operations 0.03 0.04 (0.01)
Total Non-Core Items $0.05 $0.04 $0.01
Core Earnings (losses)
SCE 4.22 1.01 1.34 0.98 0.90
Edison International Parent & Other (0.25) (0.04) (0.05) (0.12) (0.05)
Edison International $3.97 $0.97 $1.29 $0.86 $0.85
1. As a result of rounding, the total of the four quarters does not always equal the amount for the year
Note: Edison International and SCE adopted an accounting standard in the fourth quarter of 2016, effective January 1, 2016, which resulted in all of the tax effects related to share
based payments being recorded through the income statement. Diluted EPS would have been, $1.00 for the fourth quarter of 2016, $1.27 for the third quarter of 2016, $0.85 for the
second quarter of 2016 and $0.85 for the first quarter of 2016
June 21, 2017 45
Earnings Non-GAAP Reconciliations
Note: See Use of Non-GAAP Financial Measures. First quarter 2016 earnings was updated to reflect the implementation of the accounting standard for share-based payments effective
January 1, 2016
($ millions)
Reconciliation of EIX GAAP Earnings to EIX Core Earnings
SCE
EIX Parent & Other
Discontinued Operations
Basic Earnings
Non-Core Items
SCE
EIX Parent & Other
Discontinued Operations
Total Non-Core
Core Earnings
SCE
EIX Parent & Other
Core Earnings
$295
(15)
1
$281
$ −
2
1
$3
$295
(17)
$278
$349
13
−
$362
$ –
–
–
$ −
$349
13
$362
Q1
2016
Q1
2017
Earnings Attributable to Edison International
June 21, 2017 46
SCE Core EPS Non-GAAP Reconciliations
Basic EPS
Non-Core Items
Regulatory and tax items
Write down, impairment and other charges
Insurance recoveries
Less: Total Non-Core Items
Core EPS
Reconciliation of SCE Basic Earnings Per Share to SCE Core Earnings Per Share
5%
5%
$3.33
—
—
—
—
$3.33
$4.81
0.71
—
—
0.71
$4.10
$2.76
—
(1.12)
—
(1.12)
$3.88
Note: See Use of Non-GAAP Financial Measures
$4.46
—
(0.22)
—
(0.22)
$4.68
$3.06
—
(1.18)
0.04
(1.14)
$4.20
Earnings Per Share Attributable to SCE CAGR2011 2012 2013 2014 2015
$4.22
—
—
—
—
$4.22
2016
June 21, 2017 47
Use of Non-GAAP Financial Measures
Edison International's earnings are prepared in accordance with generally accepted
accounting principles used in the United States. Management uses core earnings internally
for financial planning and for analysis of performance. Core earnings are also used when
communicating with investors and analysts regarding Edison International's earnings results
to facilitate comparisons of the Company's performance from period to period. Core
earnings are a non-GAAP financial measure and may not be comparable to those of other
companies. Core earnings (or losses) are defined as earnings or losses attributable to Edison
International shareholders less income or loss from discontinued operations and income or
loss from significant discrete items that management does not consider representative of
ongoing earnings, such as: exit activities, including sale of certain assets, and other activities
that are no longer continuing; asset impairments and certain tax, regulatory or legal
settlements or proceedings.
A reconciliation of Non-GAAP information to GAAP information is included either on the
slide where the information appears or on another slide referenced in this presentation.
EIX Investor Relations Contact
Sam Ramraj, Vice President (626) 302‐2540 sam.ramraj@edisonintl.com
Allison Bahen, Senior Manager (626) 302‐5493 allison.bahen@edisonintl.com
