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July 29, 2016
Exhibit 99.1Exhibit 99.1
Business Update
July 2016
July 29, 2016
Exhibit 99.1
1
Forward-Looking Statements
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 regulatory
assets related to San Onofre;
• decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities, including the
determinations of authorized rates of return or return on equity, outcome of San Onofre CPUC proceedings and
delays in regulatory actions;
• 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 technological
advancements in the generation, storage, transmission, distribution and use of electricity, and supported by public
policy, government regulations and incentives;
• risks inherent in the construction of transmission and distribution infrastructure replacement and expansion projects,
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 retirement and decommissioning of nuclear generating facilities.
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.
July 29, 2016
Exhibit 99.1
2
Page
New (N) or Updated (U) from
May 2016 Business Update
EIX Shareholder Value 3 U
SCE Highlights, Regulatory Model 4‐5
Capital Expenditures and Rate Base History and Outlook 6‐10 U
CPUC Cost of Capital 11 U
2016 Guidance 12 U
Growth Drivers Beyond 2017, Power Grid of the Future 13‐15 U
Distribution Resources Plan 16‐18
Key Regulatory Proceedings 19 U
SCE Bundled Revenue Requirement 20 U
Operational Excellence 21
EIX Responding to Industry Change 22
Edison Energy 23‐25 U
Annual Dividends Per Share 26
Appendix
2015 General Rate Case 28‐29 U
Historical Capital Expenditures 30
Energy Storage, Charge Ready Programs 31‐32 U
Residential Rate Reform 33‐34 U
Residential Solar Installations 35 U
SCE Customer Rates and Demand 36‐39 U,N
California Energy Policy 40‐41 U
Second Quarter 2016 Earnings Summary, Results of Operations 42‐44 N
Non‐GAAP Reconciliations 45‐47 N
Table of Contents
July 29, 2016
Exhibit 99.1
3
EIX Strategy Should Produce Superior Value
Sustainable
Earnings and Dividend Growth
Positioned for
Transformative Change
Rate Base and Core Earnings Growth
• 6-7% average annual rate base
growth through 2017
Constructive Regulatory Structure
• Decoupling
• Balancing accounts
• Forward-looking ratemaking
Sustainable Dividend Growth
• Target dividend growth at a higher
than industry growth rate within its
target payout ratio of 45-55% of SCE
earnings in steps over time
SCE Focus on Lower-Risk Energy
Delivery
• Wires assets represent over 90% of
utility plant as of December 31, 20151
SCE Growth Drivers
• Public safety and reliability
• California’s low-carbon environmental
policy objective
Edison Energy Group Competitive
Strategy
• Integrate emerging technologies and
business models to serve commercial
and industrial customers
• Pursue other infrastructure
opportunities, e.g. competitive
transmission and water resources
1. Includes assets classified as transmission, distribution and general plant
July 29, 2016
Exhibit 99.1
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 investments
• 1.4 million power poles
• 725,000 transformers
• 103,000 miles of distribution and transmission lines
• 3,100 MW owned generation
Above average annual rate base growth driven by
• Public safety and reliability
• California’s low-carbon policy objectives
‒ Distribution Resources Plan (DRP)
‒ Electric vehicle charging
‒ Energy storage
Limited Generation Exposure
• SCE owns less than 20% of its power generation needs
• Future generation’s needs via competitive market
SCE Highlights
July 29, 2016
Exhibit 99.1
5
SCE Decoupled Regulatory Model
Decoupling of Regulated
Revenues from Sales
Major Balancing Accounts
• Fuel
• Purchased power
• Energy efficiency
• Pension-related
contributions
Advanced Long-Term
Procurement Planning
Forward-looking Ratemaking
• SCE earnings are not affected by changes in retail electricity
sales
• Differences between amounts collected and authorized
levels are either billed or refunded to customers
• Promotes energy conservation
• Stabilizes revenues during economic cycles
• Trigger mechanism for fuel and purchased power
adjustments at 5% variance level
• Cost-recovery via balancing accounts represented more
than 55% of 2015 costs
• Sets prudent upfront standards allowing greater certainty of
cost recovery (subject to reasonableness review)
• Three-year rate case cycle
• Separate multi-year cost of capital proceeding
Regulatory Model Key Benefits
July 29, 2016
Exhibit 99.1
6
SCE Historical Rate Base and Core Earnings
Rate Base
Core Earnings
8%
7%
2010 – 2015 CAGR
($ billions)
Note: Recorded rate base, year-end basis. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. 2013-2015 rate base excludes SONGS
$16.8
$18.8
$21.0 $21.1
$23.3
$24.6
2010 2011 2012 2013 2014 2015
Core
EPS $4.68$3.01 $3.33 $4.10 $3.88 $4.20
July 29, 2016
Exhibit 99.1
7
Outlook - $3.8 $4.3
Range - $3.7 $4.2
Outlook - $4.1 $4.2
Range - $4.0 $4.1
SCE Capital Expenditure Forecast
Note: Forecasted capital spending subject to timely receipt of permitting, licensing, and regulatory approvals. Forecasted capital spending includes CPUC, FERC and other spending.
Range case includes a 12% reduction of FERC expenditures in 2016 and 2017
1. There was no maximum amount applicable for 2015 or prior years
($ billions)
$3.8
$4.3
2015 (Recorded) 2016 2017
Distribution Transmission Generation
$3.9
C
u
r
r
e
n
t
P
r
i
o
r
• Reflects CPUC 2015 GRC decision; includes
up to 115% of capital spending for the pole
loading and deteriorated poles program for
2016 and 20171
• Includes $12 million for Charge Ready pilot
program in 2016
• Excludes future DRP including memorandum
account request and energy storage capital
spending
• Updated for deferral of transmission
spending mainly due to licensing delays
$7.9 – $8.1 Billion Capital Program
for 2016-2017
2018+ Capital Spending Outlook
• Will provide forecast through 2020 when
2018 GRC application is filed on September 1
• SCE anticipates long-term capital spending to
continue at least in the range of ~$4 billion
annually, although could result in higher
spending pending CPUC approval in future
GRCs
July 29, 2016
Exhibit 99.1
8
SCE Distribution System Investments
1. Excludes DRP and Energy Storage spending. Includes Mobile Home Park conversions
Distribution Trends
• 2015 GRC includes 94% increase in
infrastructure replacement, but power grid
not yet reaching equilibrium replacement
rate
• Distribution power grid requires more
automation and voltage management as
customer use of distributed energy resources
increases
• Does not include DRP capital spending which
is expected to become a larger portion of
spend beyond 2017
2016 – 2017 CPUC
Expenditures for Distribution Assets1
$6.1 Billion
Load
Growth
New Service
Connections
Infrastructure
Replacement
General Plant
Other
July 29, 2016
Exhibit 99.1
9
SCE Large Transmission Projects
Large Transmission Projects
Tehachapi 4-11
• $2.5 billion total project cost; remaining
investment $180 million
• 2016-17 in-service date
West of Devers
• $1.1 billion total project cost; remaining
investment $1.0 billion
• 2021 in-service date; majority of capital
spending post 2017
• Proposed decision pending; CPUC approval
expected in August 2016
Mesa Substation
• $600 million total project cost
• 2020 in-service date
Note: Total Project Costs are nominal direct expenditures, subject to CPUC and FERC cost recovery approval
FERC Cost of Capital
Comparable to CPUC 10.45% ROE which
includes:
• Base ROE = 9.30% + CAISO participation +
weighted average of individual project
incentives
• FERC Formula recovery mechanism in effect
through December 31, 2017
July 29, 2016
Exhibit 99.1
10
SCE Rate Base Forecast
• Incorporates 2015 GRC final decision with
bonus depreciation provision, except “rate
base offset” excluded because of write off
of regulatory asset related to 2012-2014
incremental tax repairs
• Includes incremental rate base for the pole
loading and deteriorated poles program
• Updated for deferral of transmission
spending mainly due to licensing delays
• FERC rate base includes Construction Work
in Progress (CWIP) and is approximately
22% of SCE’s rate base by 2017
• Excludes SONGS regulatory asset
($ billions)
Outlook
Range
Note: Weighted-average year basis, 2015-2017 CPUC rate base proposed decision and consolidation of CWIP projects. Rate base forecast range reflects capital expenditure forecast
range. Rate base calculated under current tax law. See 2015 GRC Decision for information on accounting impacts from rate base reduction on tax repairs
6-7% Average Annual Rate Base Growth
for 2015-2017
2018+ Rate Base Outlook
• Will provide forecast through 2020 when
2018 GRC application is filed on September 1
$24.9
$26.4
$23.3
$25.0
$26.6
2015 (Authorized) 2016 2017
Outlook - $25.1 $26.8
Range - $25.0 $26.6 P
r
i
o
r
July 29, 2016
Exhibit 99.1
11
CPUC Cost of Capital
3
4
5
6
7
10/1/12 10/1/13 10/1/14 10/1/15 10/1/16 10/1/17
R
a
t
e
(
%
)
CPUC Adjustment Mechanism
Moody’s Baa Utility Index Spot Rate
Moving Average (10/1/15 – 6/30/16) = 5.14%
100 basis point +/- Deadband
Starting Value – 5.00%
Return on Equity (ROE) adjustment mechanism extended
through 2017
• 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, 2012 – 5.00%
• CPUC extended Cost of Capital filing from April 2016 to April 2017
• CPUC approved the Joint Petition for Modification to suspend
adjustment mechanism through 2017 in February 2016
CPUC Authorized
Capital Structure Cost
Common Equity 48% 10.45%
Preferred 9% 5.79%
Long-term Debt 43% 5.49%
Weighted Average Cost of Capital 7.90%
ROE set at 10.45%,
independent of
trigger mechanism
July 29, 2016
Exhibit 99.1
12
$4.09
$3.91
(0.18)
2016 SCE EPS Midpoint
Guidance
EIX Parent
& Other
2016 Core EIX EPS
Midpoint Guidance
As of May 2, 2016 As of July 28, 2016
Low Mid High Low Mid High
EIX Basic EPS $3.82 $3.92 $4.02 $3.82 $3.92 $4.02
Less: Non-Core Items1 0.01 0.01 0.01 0.01 0.01 0.01
EIX Core EPS2 $3.81 $3.91 $4.01 $3.81 $3.91 $4.01
• Revenues based on GRC final decision
• Energy efficiency earnings of $0.05 per
share
• Authorized CPUC capital structure –
48% equity; 10.45% ROE
• FERC ROE comparable to CPUC ROE
• No change in tax policy
• 325.8 million common shares
outstanding
• MHI arbitration decision not included
Key Assumptions2016 Earnings Guidance
2016 Earnings Guidance Reaffirmed
1. Non-core items recorded for the six months ended June 30, 2016
2. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix
2016 earnings guidance reaffirmed, though SCE will likely outperform and EIX
Parent & Other will likely underperform current guidance
July 29, 2016
Exhibit 99.1
13
SCE Growth Drivers Beyond 2017
Infrastructure Reliability Investment
• Sustained level of infrastructure investment required until equilibrium replacement rates are achieved and
then maintained - includes underground cable, poles, switches, and transformers1
Distribution Resources Plan
• Accelerate automation, communication, and analytics capabilities at optimal locations to integrate distributed
energy resources into planning and operations
• DRP required under AB 327 to identify optimal locations, additional spending, and barriers to deploying
distributed energy resources – filed July 1, 2015
• On July 13, 2016, requested Grid Modernization memorandum account for proposed early stage capital
expenditures
Transmission
• California ISO 2013-2014 Transmission Plan2 - approved Mesa Substation Project (system reliability post-
SONGS and renewables integration) with target in-service date of 2020
• West of Devers (2019-2021) incorporated from prior Transmission Plans with target in service date of 2021
• Future transmission needs to meet 50% renewables mandate in 2030 – CAISO planning process underway
Energy Storage
• 290 MW SCE owned investment opportunity through 2024
SCE Charge Ready Program
• If approved by CPUC, planned Phase 2 will deploy approximately 1/3 of charging infrastructure needed by
2020 to serve EVs at long-dwell time locations (other than single family residences)
Transportation Electrification
• Personal, mass transit, goods movement – CPUC Scoping Memo issued March 30, 2016
1. Source: A.13-11-0032015 GRC – SCE-01 Policy testimony; equilibrium replacement rate defined as equipment population divided by mean time to failure for type of equipment
2. Approved by the California ISO Board of Governors March 20, 2014
July 29, 2016
Exhibit 99.1
14
Distribution Power Grid of the Future
One-Way Electricity Flow
• System designed to generate
electricity from large central plant
• Very few distributed energy
resources
• Voltage relatively simple to maintain
• Limited situational awareness and
visualization tools for power grid
operators
Renewable Generation Mandates
Subsidized Residential Solar
Lack of Electric Vehicle Charging
Infrastructure
Variable, Two-Way Electricity Flow
• Distribution system at the center of
the power grid
• System designed to serve variable
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
July 29, 2016
Exhibit 99.1
15
Computing intelligence inside
electrical substations
Future circuit
designs integrate
Distributed
Energy Resources
& increase
flexibility
The 21st century
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
granular 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
Smart Grid Highlights
Legend
Remote Fault Indicator
High speed bandwidth field area network
(communication system)
Intelligent Remote Switches
Automated switched capacitor bank w/ voltage control
July 29, 2016
Exhibit 99.1
16
CPUC Distributed Energy Resources (DER) Proceedings
Expanded scope
• Competitive solicitation
framework: product definition,
rules, plans, standard contracts,
“review groups,” and valuation
methodology
• Electric power company roles,
business models, and financial
interests
• Consider localized DER
incentives
Scope elements
• Integration Hosting Capacity
• Locational Net Benefits
• Data Access
• Planning alignment
• Power Grid Modernization
Investments; integration into
General Rate Case
• Integration of DERs in planning and
operations
• Identification of optimal locations and
value of DERs
• Development of tools and
methodologies
• Field demonstrations
Distribution
Resource Plan
(Tracks 1 – 3 through
early 2017)
• Determine how DERs can meet system
needs
• Develop sourcing framework for DERs
• Align DER cost-effectiveness
frameworks
Integrated
Distributed Energy
Resources
(Phase 1 through
August 2016)
July 29, 2016
Exhibit 99.1
17
2015 - 2017 2018 - 2020 2021 – 2023 +
Implement foundational
information technology,
communication systems, and
system planning tools
Enhance automation and
improve interoperability with
Distributed Energy Resources
Optimize operation of
Distributed Energy Resources
and distribution market
operation
T
e
c
h
n
o
l
o
g
y
E
x
p
e
c
t
e
d
R
e
s
u
l
t
G
R
C
C
y
c
l
e
Align work management and develop workforce
strategy Ramp up resources and develop talent pipeline
Compliance, safety, and
reliability; preparation for future
smart grid state
New business opportunities
enabled; full deployment of
smart grid modernization
New distribution system
platform for distribution market
operations
P
e
o
p
l
e
a
n
d
P
r
oces
s
SCE is evolving its DRP timeline based on January 2016 scoping memo, July 2016
memorandum account request and finalization of the 2018 General Rate Case
Smart Grid Modernization Road Map
July 29, 2016
Exhibit 99.1
18
July 2015 SCE DRP Capital Expenditure Estimates
Time Period Capital Expenditures CPUC Approval Mechanism
2016-2017 Distribution Automation $40-70 million • Proposed memorandum
account to record
associated revenue
requirement until
expenditures are
authorized by CPUC
Substation Automation $30-60 million
Communications Systems $7-15 million
Technology Platforms and
Applications
$130-200 million
Power Grid Reinforcement $140-215 million
Total $347-560 million
2018-2020 Distribution Automation $185-320 million • Request recovery in 2018
GRCSubstation Automation $185-320 million
Communications Systems $270-470 million
Technology Platforms and
Applications
$215-375 million
Power Grid Reinforcement $550-1,100 million
Total $1,405-2,585 million
DRP capital spending estimates were provided July 2015 and are subject to change
Note: Totals for 2015-2017 and 2018-2020 include O&M spending of $20-30 million and $60-100 million, respectively
July 29, 2016
Exhibit 99.1
19
SCE Key Regulatory Proceedings
Proceeding Description Next Steps
Key SCE Proceedings
Cost of Capital CPUC capital structure, cost of capital, and
return on equity
CPUC approved the Joint Petition for Modification
to suspend adjustment mechanism through 2017;
Filing of 2018 application in April 2017
Distribution Resources Plan OIR
(R.14‐08‐013)
Power grid investments to integrate
distributed energy resources
SCE plan submitted July 2015; CPUC scoping memo
issued January 2016; three phases
Integrated Distributed Energy
Resources OIR (R. 14‐10‐003)
Creating consistent framework for
guidance, planning and evaluation of DERs
Florio Ruling comments and replies filed in May
2016; ongoing workshops and recommendations on
proceeding
SONGS OII
(I.12‐10‐013)
OII resolved (December 2015); Proceeding
reopened in May 2016
CPUC decisions on pending challenges to the
SONGS Settlement Agreement
Key FERC Proceedings
FERC Formula Rates Transmission rate setting with annual
updates
ROE moratorium expired July 2015; settlement in
place through December 2017
Other Proceedings
Energy Storage RFO
(A.15‐12‐003)
Solicitation for 16.3 MW launched
December 2014
Selection September 2015; Contracts submitted for
CPUC approval on December 2015
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
Alternative‐Fueled Vehicle OIR
(R. 13‐11‐007)
Scope originally focused on 1.5 million EV
target; scope broadened March 2016 to
address broader SB 350 transportation
electrification objectives
Q2 2016 workshops to be followed by Q3 2016
CPUC invitation for transportation electrification
applications
July 29, 2016
Exhibit 99.1
20
SCE 2016 Bundled Revenue Requirement
Note: Rates in effect as of June 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
14.3 14.1 14.3 15.9 16.7 16.2
Fuel & Purchased Power
(43%)
Distribution
(39%)
Transmission (9%)
Generation
(10%)
Other (-1%)
2016 Bundled
Revenue
Requirement
$millions ¢/kWh
Fuel & Purchased Power – includes CDWR Bond Charge 4,928 6.7
Distribution – poles, wires, substations, service centers; Edison
SmartConnect®
4,185 5.7
Generation – owned generation investment and O&M 1,080 1.5
Transmission – greater than 220kV 978 1.3
Other – CPUC and legislative public purpose programs, system
reliability investments, nuclear decommissioning
(211) (0.3)
Total Bundled Revenue Requirement ($millions) $10,960
Bundled kWh (millions) 73,744
= Bundled Systemwide Average Rate (¢/kWh) 14.9¢
July 29, 2016
Exhibit 99.1
21
SCE Operational Excellence
Top Quartile
• Safety
• Cost efficiency
• Reliability
• Customer service
Optimize
• Capital productivity
• Purchased power cost
High performing, continuous
improvement culture
Defining Excellence Measuring Excellence
• Employee and public safety
metrics
• System 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
July 29, 2016
Exhibit 99.1
22
EIX is 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
EIX Competitive Strategy
• Edison Energy – Position as Integrator for
Energy-as-a-Service platform serving
large commercial and industrial
customers
• Edison Transmission – Competitive
opportunities outside SCE service
territory and founding member of Grid
AssuranceTM
• Edison Water Resources – Desalination of
brackish water and on-site wastewater
recycling initial areas of focus
Long-Term Industry Trends Strategy
July 29, 2016
Exhibit 99.1
23
• Create energy services that help simplify and optimize energy needs for large
commercial & industrial customers:
– Help customers better assess and capture the value of energy optimization, paving
the way for greater third-party energy services
– Help customers manage through technological / regulatory changes
Evolving customer needs and uncertainty around changing technologies, regulation
and business models create a business opportunity for a trusted advisor role
Changing Customer Needs
The Opportunity: Trusted Advisor and Solution Integrator
Edison Energy Focus: Commercial & Industrial
July 29, 2016
Exhibit 99.1
24
Edison Energy: Acquired Businesses Summary
• Provides comprehensive renewable energy advisory and procurement services to
leading Fortune 1000 companies, universities and municipalities
• Created a proprietary market access platform where it typically procures energy for
its clients by negotiating multiyear power purchase agreements that help control
energy costs and improve the environmental performance of their operations
• A leading provider of custom energy consulting services for large, multiple site,
commercial and industrial energy users with a focus on enabling them to achieve
significant energy cost savings and control
• Collaborates with clients to help them make strategic decisions to achieve their
overall business objectives, offering consulting services in energy procurement,
supply and energy asset management, utility bill payment and invoice auditing,
energy data management, energy price risk management, regulatory support,
renewable energy integration and energy efficiency/demand response
• A full-service energy consulting, engineering and project development firm
specializing in the analysis, design, development and installation of energy efficiency
projects, green initiatives for building systems, and power generation solutions for
optimization and environmental control
• Focused on building HVAC and controls, new energy technologies, renewable
energy, power plant environmental systems, and energy awareness and education
• Hundreds of solar solutions designed and installed across 16 states, SoCore offers
multisite retailers, REITs and industrial companies portfolio-wide solar solutions that
provide energy cost savings and carbon reduction opportunities
July 29, 2016
Exhibit 99.1
25
On May 9, 2016, six electric power companies announced the official launch of Grid Assurance, LLC,
an independent company providing transmission sparing solutions for critical electric transmission
equipment. The company is offering its subscribers a cost-effective way to enhance grid resiliency
and protect their customers from prolonged transmission outages.
• Grid Assurance will address potential high impact events on the bulk transmission systems:
- It will own critical equipment with long manufacturing lead times to account for risk beyond
what is covered by “operational spares”
- It will provide secure, off-site storage in strategic locations, and support transportation of
needed equipment to its subscribers
- Subscribers will pay a subscription fee based on Grid Assurance’s costs. Subscribers will have
access to inventory and will have the right to call on inventory following a “Qualifying Event”
such as physical attacks, electromagnetic pulses, solar storms, cyberattacks, earthquakes and
severe weather events
- Regulatory construct will provide subscribers cost certainty as subscription fees will be
calculated in a manner similar to FERC formula rates for transmission assets
- Subscription to the sparing service will be available to all transmission owning entities
• Grid Assurance is currently meeting with potential subscribers and identifying entities that will
subscribe to the service; it expects to begin identifying inventory in 2016
Grid Assurance™ Overview
Edison Transmission is one of the companies developing Grid Assurance
July 29, 2016
Exhibit 99.1
26
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
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Note: See use of Non-GAAP Financial Measures in Appendix
Twelve Years of Dividend Growth
Target dividend growth at a higher than industry growth rate within its target
payout ratio of 45-55% of SCE earnings in steps over time
July 29, 2016
Exhibit 99.1
27
Appendix
July 29, 2016
Exhibit 99.1
28
Tax Repair Accounting
• As a result of the rate base offset, SCE wrote down $382 million of regulatory assets associated
with deferred income taxes related to 2012-2014 incremental tax repair deductions
Because this rate base offset will be implemented at SCE through the regulatory asset write
down, no rate base offset is needed for future earnings forecasts
• Any differences between the forecasted tax repair deductions and actual repair deductions for
2015-2017 will be adjusted annually through customer rates
On November 5, 2015, the CPUC issued a final decision supportive of SCE strategy to increase
infrastructure reliability and safety investment while mitigating customer rate impacts through
productivity and operating efficiency
GRC Final Decision
2015 2016 2017
Revenue Requirement $5.182 $5.391 $5.663
Authorized Rate Base $17.3761 $18.7141 $20.1761
($ billions)
2015 General Rate Case Final Decision
1. The final decision included a rate base offset for tax repair deductions. For accounting purposes, EIX has not included the rate base offset in its rate base forecast. See language
above.
Tax Repair Ratemaking
• In SCE’s 2015 GRC final decision, the CPUC adopted a rate base offset associated with incremental
tax repair deductions during 2012-2014
– In 2015, the CPUC rate base offset is $324 million1 and amortizes on a straight line basis over 27
years
July 29, 2016
Exhibit 99.1
29
SCE Tax Memorandum Account
• 2015 GRC decision established tax accounting memorandum account (TAMA), which tracks 2015 –
2017 tax benefits or costs associated with following events:
- changes in tax accounting methods
- changes in tax laws and regulations impacting depreciation or tax repair
- changes in forecasted tax repairs deductions (actual vs. amounts authorized)
- changes to depreciation or tax repair deductions as a result of an audit
- any impact of a private letter ruling related to normalization
• Once a year, the aggregate over or undercollection will be calculated and refunded to or collected
from customers
• $42 million regulatory liability at June 30, 2016; in Q2 2016, $206 million was transferred to a
balancing account for refund to customers
Tax Repair Deductions
Bonus Depreciation
• No earnings impact associated with incremental tax repair
deductions (positive or negative)
• No rate base impact (positive or negative)
• Flow through rate making applies
• Earnings impacts occurs in the relevant year of the
extension rather than next GRC cycle
• Rate base impact from increase in deferred taxes offset by
an increase in working cash mainly in 2015
• Normalization rate making applies
Tax Policy Rate Base and Earnings Implications
July 29, 2016
Exhibit 99.1
30
SCE Historical Capital Expenditures
($ billions)
$3.8
$3.9 $3.9
$3.5
$4.0 $3.9
2010 2011 2012 2013 2014 2015
July 29, 2016
Exhibit 99.1
31
Energy Storage
SCE has already met the aggregate 2016 targets
• CPUC Energy Storage Program:
– 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)
• First storage-only RFO completed November 2015
– Three contracts for 16.3 MW were submitted for
CPUC approval in December 2015
• SCE filed its 2016 Storage Procurement Plan on March
1, 2016 detailing current portfolio and plans for
second Storage RFO in late 2016
• SCE’s storage portfolio also includes SCE-owned pilots
and demonstrations, customer programs, and storage
procured through various solicitations
• In response to CPUC Resolution E-4791, SCE recently
issued the Aliso Canyon Energy Storage RFO for 3rd
party-owned storage and a Request for Proposals
(RFP) for sellers to design, build, and transfer energy
storage facilities to SCE
July 29, 2016
Exhibit 99.1
32
SCE Charge Ready Program
• Electric vehicle Charge Ready Program Phase 1 pilot
approved by CPUC January 2016
− Authorizes spend of $22 million on pilot
implementation for charger installations and
Market Education Programs ($12 million rate base)
− Advice letter approval to spend funds granted April
2016
• Pro-active, two-phased program to support
installation of up to 30,000 EV charging stations to be
included in rate base
– Phase 1: pilot for 1,500 chargers and market
education program (2016 – 2017)
– Phase 2: 28,500 chargers (2018 – 2022)
• Addresses approximately 1/3 of forecast non-single
family home charging demand in SCE territory in 2020
• Request for Phase 2 to be filed with CPUC after
completion of Phase 1
− $225 million total rate base opportunity if Phase 2
follows Phase 1 approach
SCE’s Charge Ready Program supports Governor Brown’s 2012 zero-emission vehicle Executive
Order – 1.5 million EVs statewide by 2025
• Level 1 (120V) and Level 2 (240V) chargers (L2
with Demand Response capability)
• 10 chargers per site minimum
• Participants own / operate / maintain
chargers
• Capital cost per charging station: $11,200
July 29, 2016
Exhibit 99.1
33
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 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, but rejected requests for increased fixed charges allowing
IOUs to re-file fixed charge requests as early as 2018.
- Minimum bills up to $10/month which applies to delivery revenue only
Current Rates – June 2016
18.2¢
40.8¢
100% 101‐400% >400%
23.3¢
Usage Level (% of Baseline)
¢
/
k
W
h
Future Rates - 2019
Usage Level (% of Baseline)
15.7¢
22.9¢
29.2¢
100% 101‐200% 200‐400% >400%
¢
/
k
W
h
Fixed Charge: $0.94/month
Minimum Bill: $10.00/month
Fixed Charge: $0.94/month
Minimum Bill: $10.00/month
Note: Graphs not to scale. 2019 rate levels are based on current revenue requirements
July 29, 2016
Exhibit 99.1
34
SCE Net Metering Rate Structure
7¢
24¢17¢
0
5
10
15
20
25
30
¢
/
k
W
h
Solar Subsidies
(Illustrative)
Avoided
Generation
(excludes RPS
Premium)
Subsidy Paid by
Other Ratepayers
Equivalent
Solar Offset
NEM Rate Developments:
• NEM allows residential customers to receive full-retail 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.
SCE Net Energy Metering Statistics (June 2016):
• 186,329 combined residential and non-residential projects –
1,463 MW installed (of 2,240 MW cap)
– 99.8% solar
– 181,762 residential – 947 MW (4.21% penetration)
– 4,567 non-residential – 516 MW (0.66% penetration)
• Approximately 2,528,064 MWh/year generated
July 29, 2016
Exhibit 99.1
35
Note: NEM solar installations in SCE service territory include projects with solar PV only less than 1 MW
Residential Solar Installations in SCE Territory
10
20
30
40
50
60
1,000
2,000
3,000
4,000
5,000
6,000
7,000
2010 2011 2012 2013 2014 2015 2016
M
W
Installed
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
Number of Installations MW Installed
July 1, 2017
• NEM customers will be
required to take service under
mandatory Time-of-Use rate
2019
• Commission to revisit NEM
Successor Tariff
Key Dates
July 29, 2016
Exhibit 99.1
36
(0.3¢)
(0.5¢)
(1.4¢)
(0.1¢)
0.3¢
0.4¢
0.3¢
2015 SAR 2015 ERRA
Settlement
2015 GRC Expiration of
Prior Refunds
Other CPUC 2016 FERC 2016 ERRA
Changes
January 2016
SAR
FERC
Balancing
Account
June 2016
SAR
16.2¢
14.9¢
15.0¢
2016 System Average Rate
SCE’s system average rate, the lowest amongst California IOUs, declined from 16.2¢/kWh
to 15.0¢/kWh on January 1, 2016, an 8% decrease, with a further decline on June 1, 2016
to 14.9¢/kWh
(¢/kWh)
2
Comparative System
Average Rates1:
EIX – 14.9¢
PG&E – 18.2¢
SDG&E – 20.4¢
1. Rates as of June 30, 2016
2. Includes public purpose, 2016 SONGS revenue requirement and other
July 29, 2016
Exhibit 99.1
37
9.7¢
16.2¢
14.9¢
8.0¢
10.0¢
12.0¢
14.0¢
16.0¢
18.0¢
20.0¢
22.0¢
24.0¢
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016
Energy Crisis and
return to normal
Higher gas price forecast 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 due to the
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 inflation over the last 20 years
SCE System Average Rate
Los Angeles Area Inflation
July 29, 2016
Exhibit 99.1
38
SCE Rates and Bills Comparison
13.1
16.5
US Average SCE
26%
Higher
2015 Average Residential Rates
(¢/kWh)
2015 Average Residential Bills
($ per Month)
¢
¢
SCE’s average residential rates are above national average,
but residential bills are below national average due to lower energy usage
• SCE’s residential rates are above national
average due, in part, to a cleaner fuel mix –
cost for renewables are higher than high
carbon sources
• Average monthly residential bills are lower
than national average – higher rate levels
offset by lower usage
– 41% lower SCE residential customer usage
than national average, from mild climate
and higher energy efficiency building
standards
• Public policy mandates (33% RPS, AB32 GHG,
Once-through Cooling) and electric system
requirements will drive rates and bills higher
Key FactorsKey Factors
Source: EIA's Form 826 Data Monthly Electric Utility Sales and Revenue Data for 2015
$127
$94
US Average SCE
26%
Lower
July 29, 2016
Exhibit 99.1
39
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
2011
29,631
39,622
8,490
5,206
1,318
84,267
3,071
87,338
4,301,969
546,936
11,370
46,684
22,086
82
22
4,929,149
19,829
22,443
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
YTD 2016
12,960
19,926
3,618
2,230
776
39,510
623
40,133
4,406,167
564,056
10,596
46,487
21,317
132
22
5,048,777
19,016
N/A
July 29, 2016
Exhibit 99.1
40
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
• In order to meet the 50% RPS requirement by 2030,
SCE will need to increase its renewable purchases by
20.2 billion kWh, or 110%
Renewables Electric
Vehicles
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
• Distribution power grid
investments to meet EV impact
Continuation of company
programs and earnings incentive
mechanism
• SCE 2016 program budget:
$333 million
• $0.05 per share 2016 earnings
potential
Electric Power Company Role
Solar 26%
Small Hydro
2%
Geothermal
37%
Wind 33%
Actual 2015 Renewable Resources:
24.3% of SCE’s portfolio
Biomass 2%
July 29, 2016
Exhibit 99.1
41
AB32 Emissions
Reduction Programs
Cap & Trade
22%
Other
23%
Low Carbon
Fuel
Standard
19%
RPS
14%
Energy
Efficiency
15%
High GWP
Gases
7%
California Cap and Trade Program
• Assembly Bill 32 (2006) – reduces State
greenhouse gas (GHG) emissions to 1990 levels
by 2020 (~16% reduction)
• Cap and trade program basics:
– State-wide cap in 2013 – decreases over time
– Compliance met through allowances, offsets,
or emissions reductions
– Excess allowances sold, or “banked” for
future use
– Linkage with Quebec cap and trade program
in 2014, planned linkage with Ontario in 2018
• SCE received 31.4 million 2015 allowances vs. a
financial exposure to only 24.5 million metric
tons of GHG emissions that same year
• Allowances sold into quarterly auction and
bought back for compliance
– SB 1018 (2012) – auction revenues used for
rate relief for residential (~93%), small
business, and large industrial customers
July 29, 2016
Exhibit 99.1
42
Q2
2016
Q2
2015 Variance
Basic Earnings Per Share (EPS)
SCE $0.97 $1.18 $(0.21)
EIX Parent & Other (0.11) (0.02) (0.09)
Discontinued Operations (0.01) (0.01)
Basic EPS $0.85 $1.16 $(0.31)
Less: Non-Core Items
SCE $ $ $
EIX Parent & Other1 0.01 0.01
Discontinued Operations2 (0.01) (0.01)
Total Non-Core Items $ $ $
Core Earnings Per Share (EPS)3
SCE $0.97 $1.18 $(0.21)
EIX Parent & Other (0.12) (0.02) (0.10)
Core EPS3 $0.85 $1.16 $(0.31)
Key SCE EPS Drivers
Revenue4,5,6 $0.10
- CPUC – Escalation 0.09
- CPUC – Timing of GRC (0.06)
- CPUC – GRC return on pole loading rate base 0.03
- CPUC – Other 0.01
- FERC revenue and other 0.03
Higher depreciation (0.04)
Higher net financing costs (0.02)
Income taxes5,6 (0.27)
- 2015 change in uncertain tax positions (0.31)
- Higher tax benefits 0.04
Other items 0.02
Total $(0.21)
Second Quarter Earnings Summary
Key EIX EPS Drivers
EIX parent – Higher corporate expenses $(0.02)
EMG – Sold portfolio in 2015 (0.03)
EEG – Buyout of an earn-out provision, higher
operating and development costs (0.05)
Non-core items1,2 -
Total $(0.10)
1. Impact of hypothetical liquidation at book value (HLBV) accounting method
2. Discontinued Operations: Legacy tax matter related to EME
3. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix
4. Excludes San Onofre revenue of $0.02 and interest expense of $0.01 which were offset by income taxes of $(0.03)
5. Excludes revenue and income taxes for 2016 incremental tax repair deductions and pole loading program-based cost of removal of $0.04
6. Excludes $0.24 of refunds to customers for incremental tax benefits related to 2012 - 2014 repair deductions
Note: Diluted Earnings were $0.84 and $1.15 per share for the three months ended June 30, 2016 and 2015, respectively
July 29, 2016
Exhibit 99.1
43
YTD
2016
YTD
2015 Variance
Basic Earnings Per Share (EPS)
SCE $1.85 $2.12 $(0.27)
EIX Parent & Other (0.17) (0.04) (0.13)
Discontinued Operations
Basic EPS $1.68 $2.08 $(0.40)
Less: Non-Core Items
SCE $ $ $
EIX Parent & Other1 0.01 0.02 (0.01)
Discontinued Operations
Total Non-Core Items $0.01 $0.02 $(0.01)
Core Earnings Per Share (EPS)2
SCE $1.85 $2.12 $(0.27)
EIX Parent & Other (0.18) (0.06) (0.12)
Core EPS2 $1.67 $2.06 $(0.39)
Key SCE EPS Drivers
Revenue3,4,5 $0.15
- CPUC – Escalation 0.17
- CPUC – Timing of GRC (0.12)
- CPUC – GRC return on pole loading rate base 0.05
- CPUC – Other (0.01)
- FERC revenue and other 0.06
Higher O&M (0.04)
Higher depreciation (0.06)
Higher net financing costs (0.03)
Income taxes4,5 (0.29)
- 2015 Change in uncertain tax positions (0.31)
- Higher tax benefits 0.02
Total $(0.27)
YTD 2016 Earnings Summary
Key EIX EPS Drivers
EIX parent – Higher corporate expenses $(0.01)
EMG – Sold portfolio in 2015 (0.04)
EEG – Buyout of an earn-out provision, higher
operating and development costs (0.07)
Non-core items1 (0.01)
Total $(0.13)
1. Impact of hypothetical liquidation at book value (HLBV) accounting method
2. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix
3. Excludes San Onofre revenue of $0.03, interest expense of $0.01, and property taxes of $0.01 which were offset by income taxes of $(0.05)
4. Excludes revenue and income taxes for 2016 incremental tax repair deductions and pole loading program-based cost of removal of $0.17
5. Excludes $0.24 of refunds to customers for incremental tax benefits related to 2012 - 2014 repair deductions
Note: Diluted Earnings were $1.66 and $2.06 per share for the six months ended June 30 2016 and 2015, respectively
July 29, 2016
Exhibit 99.1
44
$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
$1,368
(370)
$998
SCE Results of Operations
• Earning activities – revenue authorized by CPUC and FERC to provide reasonable cost recovery and return on investment
• Cost-recovery activities – CPUC- and FERC-authorized balancing accounts to recover specific project or program costs, subject
to reasonableness review or compliance with upfront standards
Earning
Activities
Cost-
Recovery
Activities
Total
Consolidated
2015
Earning
Activities
Cost-
Recovery
Activities
Total
Consolidated
2014
Operating revenue
Purchased power and fuel
Operation and maintenance
Depreciation, decommissioning and amortization
Property and other taxes
Impairment and other charges
Total operating expenses
Operating income
Interest expense
Other income and expenses
Income before income taxes
Income tax expense
Net income
Preferred and preference stock dividend
requirements
Net income available for common stock
Core earnings
Non-core earnings
Total SCE GAAP earnings
Note: See Use of Non-GAAP Financial Measures in Appendix
($ millions)
$6,831
—
2,106
1,720
318
163
4,307
2,524
(528)
43
2,039
474
1,565
112
$1,453
$6,549
5,593
951
—
—
—
6,544
5
(5)
—
—
—
—
—
$—
$13,380
5,593
3,057
1,720
318
163
10,851
2,529
(533)
43
2,039
474
1,565
112
$1,453
$1,525
(72)
$1,453
July 29, 2016
Exhibit 99.1
45
Earnings Non-GAAP Reconciliations
Note: See Use of Non-GAAP Financial Measures in Appendix
($ 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
$384
(5)
–
$379
$ –
1
–
$1
$384
(6)
$378
$315
(37)
(2)
$276
$ –
2
(2)
$ –
$315
(39)
$276
Q2
2015
Q2
2016
Earnings Attributable to Edison International
$689
(11)
–
$678
$ –
6
–
$6
$689
(17)
$672
$601
(54)
(1)
$546
$ –
4
(1)
$3
$601
(58)
$543
YTD
2015
YTD
2016
July 29, 2016
Exhibit 99.1
46
SCE Core EPS Non-GAAP Reconciliations
Basic EPS
Non-Core Items
Tax settlement
Health care legislation
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
$3.19
0.30
(0.12)
—
—
—
0.18
$3.01
(1%)
7%
$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 in Appendix
$4.46
—
—
—
(0.22)
—
(0.22)
$4.68
$3.06
—
—
—
(1.18)
0.04
(1.14)
$4.20
Earnings Per Share Attributable to SCE 2010 CAGR2011 2012 2013 2014 2015
July 29, 2016
Exhibit 99.1
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
Scott Cunningham, Vice President (626) 302‐2540 scott.cunningham@edisonintl.com
Allison Bahen, Senior Manager (626) 302‐5493 allison.bahen@edisonintl.com