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| 8-K - 8-K BUSINESS UPDATE 11/2/16 - EDISON INTERNATIONAL | form8-kbusinessupdatenovem.htm |
November 2, 2016
Business Update
November 2016
November 2, 2016 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 regulatory
assets 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 the
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 bundled 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 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.
Forward-Looking Statements
November 2, 2016 2
Page
New (N) or Updated (U) from
September 2016 Business Update
EIX Shareholder Value 3 U
SCE Highlights, Regulatory Model 4‐5
Capital Expenditures and Rate Base History and Forecast 6‐8
2018 GRC Overview 9‐10
Distribution and Transmission Capital Expenditure Detail 11‐15
Growth Drivers Beyond 2017 16 U
CPUC Cost of Capital 17 U
2016 Guidance 18 U
Annual Dividends Per Share 19
Operational Excellence 20
EIX Responding to Industry Change 21 U
Edison Energy 22‐24 U
Appendix
SCE Tax Memorandum Account 26 U
Historical Capital Expenditures 27
Capital Expenditure and Rate Base Detailed Forecast 28
Key Regulatory Proceedings 29 U
Power Grid of the Future, Grid Modernization 30‐33
SCE Customer Demand Trends 34 U
California Energy Policy 35 U
SCE Bundled Revenue Requirement, System Average Rate Historical Growth 36‐37
Residential Rate Reform and Other 38‐40 U
SCE Rates and Bills Comparison 41 U
Third Quarter 2016 Earnings Summary, Results of Operations, Non‐GAAP Reconciliations 42‐47 N,U
Table of Contents
November 2, 2016 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
• 8.5% 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 growth rate within its
target payout ratio of 45-55% of SCE
earnings in steps over time
Wires-Focused SCE Strategy
• Infrastructure replacement – public
safety and reliability
• Grid modernization – supports
California’s low-carbon policy goals
• Operational excellence
Edison Energy Group Strategy
• Energy as a service concept for large
commercial and industrial customers -
capital light business model
• Also pursuing solar, competitive
transmission and water resources
opportunities in selected markets
Note: Wires assets (transmission, distribution and general plant) represent over 90% of utility plant as of December 31, 2015.
November 2, 2016 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
• 725,000 transformers
• 103,000 miles of distribution and transmission lines
• 3,100 MW owned generation
Above average rate base growth driven by
• Public safety and reliability
• California’s low-carbon policy objectives
Grid modernization
Electric vehicle charging
Energy storage
Limited Generation Exposure
• SCE owns less than 20% of its power generation needs
• Future generation needs via competitive market
SCE Highlights
November 2, 2016 5
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 are not affected by variability of 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 related 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 cost of capital proceeding
Regulatory Model Key Benefits
November 2, 2016 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 SCE Core EPS Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures. 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 $4.20
November 2, 2016 7
SCE Capital Expenditure Forecast – Request Level
Note: Forecasted capital spending includes CPUC, FERC and other spending. See Capital Expenditure/Rate Base Detailed Forecast.
($ billions)
$3.8
$4.5
$5.0
$5.2
$4.9
2016 2017 2018 2019 2020
Distribution Transmission Generation
Traditional Capital Spending:
Grid Modernization Capital Spending:
Grid Modernization
$23.3 Billion Capital Program
for 2016-2020
• Capital expenditure forecast incorporates GRC, FERC and
non-GRC CPUC spending
Grid modernization spending of $2.3 billion during
five-year period
2016-2017 traditional capital spending incorporates
2015 GRC decision and FERC spending
Certain non-GRC CPUC capital spending of:
- ~$210 million for grid modernization in 2016-2017
- $187 million for Mobile Home Park Conversion
pilot program in 2016-2017
• Authorized/Actual may differ from forecast
Since the 2009 GRC, CPUC has approved 81%, 89%,
and 92% of capital requested, respectively
SCE has no prior approval experience on grid
modernization capital spending and, therefore, prior
results may not be predictive
Forecasted FERC capital spending subject to timely
receipt of permitting, licensing, and regulatory
approvals
November 2, 2016 8
SCE Rate Base Forecast – Request Level
• Incorporates 2015 GRC final decision,
except “rate-base offset” excluded because
of write off of regulatory asset related to
2012-2014 incremental tax repairs
• CPUC rate base based on request levels
from 2018 GRC and 2018 positive true-up
from authorized to forecast 2017 rate base
• FERC rate base is approximately 19% of
SCE’s rate base by 2020; includes
Construction Work in Progress (CWIP)
• Excludes SONGS regulatory asset
($ billions)
Note: Weighted-average year basis. 2016-2017 based on 2015 GRC decision. 2018-2020 based on 2018 GRC request. Rate base calculated under current tax law.
5-year CAGR of 8.5%
$24.9
$26.4
$29.6
$32.4
$35.1
2016 2017 2018 2019 2020
Traditional Grid Modernization
November 2, 2016 9
• 2018 GRC Application (A. 16-09-001) filed September 1st
• Addresses major portion of 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 discrete SCE capital projects (such as SCE Charge Ready – transportation
electrification infrastructure program)
Excludes FERC jurisdictional transmission
• Requests 2018 revenue requirement of $5.885 billion
$222 million increase over presently authorized base rates, a 2.7% increase over total rates
Requests post test year increases: $533 million in 2019 and $570 million in 2020, 4.2% and
5.2% increases over presently authorized total rates, respectively
• GRC filing consistent with SCE strategy to focus on safety and reliability by continuing
infrastructure investment and beginning grid modernization investments while mitigating
customer rate impacts through lower operating costs
GRC
Application
Rebuttal Final
Decision
2016 2017
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Estimated
Intervenor
Testimony
Proposed
Decision
2018 SCE General Rate Case (GRC) Summary
Evidentiary
Hearings
Note: Actual schedule to be set by CPUC in a future regulatory order. The schedule is subject to change over the course of the proceeding.
November 2, 2016 10
• Capital expenditures include $2.1 billion of
proposed grid modernization capital to
support improved safety and reliability and
increased levels of distributed energy
resources (DER)
Requested approval to establish a
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 is
not approved
• Need to increase 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) to adjust
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 Summary (cont.)
November 2, 2016 11
SCE Distribution System Investments
1. Other includes energy storage, Charge Ready Pilot and mobile home park conversion
Distribution Trends
• Continued focus on safety and reliability with
infrastructure replacement representing 46% 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
2016 – 2020 Capital Spending Forecast
for Distribution1 – Request Level
$17.8 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
November 2, 2016 12
$0.03
$0.18
$0.64
$0.75
$0.71
2016 2017 2018 2019 2020
Building next generation electric grid will require
accelerating traditional Transmission and
Distribution / Information Technology programs
and investing in new capabilities
• Increased capacity: Upgrade portions of the grid (such as
4kV system) to increase capacity, improve reliability, and
address technology obsolescence
• Advanced Capabilities: Automation to monitor and
control grid equipment in real-time
• Communication Networks: Expansion of fiber optic
network and field area network for real-time data transfer
• Technology Platforms: Foundational tools for forecasting
and planning; management systems to operate the
distribution grid
Capital will be deployed to achieve two primary
objectives
• Improving safety and reliability
Focus on worst performing circuits in conjunction with
traditional infrastructure replacement activities
• Increase DER integration capacity and enable advanced
operations on circuits with high forecasted penetration or
where DERs can provide grid services
1. Forecast excludes capitalized overheads
2. Pending approval of memorandum account for 2016 and 2017 forecast and 2018 GRC decision for 2018-2020 forecast
SCE Grid Modernization – Request Level
($ billions)
$2.3 Billion Capital Request for 2016-20201,2
November 2, 2016 13
Energy Storage
Given flexibility counting rules, SCE has already met the
aggregate 2016 targetsCPUC 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, customer
programs, and requests for proposals (RFPs):
• SCE’s first storage-only RFO, completed November 2015,
resulted in 3 contracts for 16.3 MW of storage that were
approved in September 2016
• CPUC approved SCE’s 2016 Storage Procurement Plan in
September 2016, which detailed the current storage
portfolio and SCE’s plans for launch of a storage RFO for
late 2016
• In response to CPUC Res. E-4791, SCE also issued the Aliso
Canyon Energy Storage RFO for 3rd party-owned storage
and an RFP for sellers to design, build, and transfer energy
storage facilities to SCE
Cost Recover Mechanism for Storage
Utility-Owned Storage (UOS)1
(except Aliso Canyon RFP)
Capital Expenditures – General
Rate Case
Third-Party Owned Storage Energy Resource Recovery
Account
Aliso Canyon RFP1 (UOS) Special Application – targeted
Q1 2017
1. Typically recovered through GRC capital expenditures, but as a special circumstance, UOS procured through Aliso Canyon RFP will require a separate application for cost recovery
November 2, 2016 14
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
• 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 2020 non-
single family home charging demand in SCE territory
• 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
November 2, 2016 15
SCE Large Transmission Projects
1. CPUC approved in August 2016
2. Presently under CPUC environmental review
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
Comparable to CPUC 10.45% ROE:
• Base ROE = 9.30% + CAISO participation +
weighted average of individual project incentives
• FERC Formula recovery mechanism in effect
through December 31, 2017
Summary of Large Transmission Projects
Project Name Total Cost4 Remaining Investment In-Service Date
Tehachapi 4-11 $2.5 billion $179 million 2016-2017
West of Devers1,3 $1.1 billion $1.0 billion 2021
Mesa Substation2 $608 million $592 million 2020-2021
Alberhill System2 $397 million $361 million 2021
Riverside Transmission Reliability2 $233 million $230 million 2021
Eldorado-Lugo-Mohave Upgrade $269 million $266 million 2019
November 2, 2016 16
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
Grid Modernization
• Accelerate automation, communication, and analytics capabilities at optimal locations to integrate distributed
energy resources
• 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; On September 1, 2016, filed 2018 GRC application with proposed capital expenditures for 2018-
2020
Transmission
• West of Devers (2019-2021) incorporated from prior Transmission Plans with target in service date of 2021
• California ISO 2013-2014 Transmission Plan2 - approved Mesa Substation Project (system reliability post-
SONGS and renewables integration) with target in-service date of 2020-2021
• Future transmission needs to meet 50% renewables mandate in 2030 – CAISO planning process underway
Energy Storage
• SCE owned investment opportunities
SCE Charge Ready Program
• If approved by CPUC, planned Phase 2 to 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 – Utility proposals due to the CPUC January 2017
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
November 2, 2016 17
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 (10/1/16 – 10/27/16) = 4.33%
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%
November 2, 2016 18
$3.84 $3.91
(0.27)
0.34
SCE 2016 EPS from
Rate Base Forecast
SCE Variances EIX Parent
& Other
2016 EIX Core EPS
Guidance
• Productivity
and financing
benefits -
$0.30
• Energy
efficiency -
$0.04
Reaffirmed 2016 Core Earnings Per Share Guidance –
Building from SCE Rate Base3
2016 Earnings Guidance Reaffirmed
• SCE authorized rate base $24.943 billion
• Energy efficiency earnings $0.04 per
share (previously $0.05 per share)
• Authorized CPUC capital structure - 48%
equity and 10.45% ROE
• FERC ROE comparable to CPUC ROE
• No change in tax policy
• 325.8 million common shares
• MHI arbitration decision not included
Any legal and related cost recoveries
would be core for consistency with
prior period accounting for costs
Balance of SCE’s share of any recovery
would be treated as non-core
Key Assumptions
As of
July 28, 2016
As of
November 1, 2016
Low Mid High Low Mid High
EIX Basic EPS $3.82 $3.92 $4.02 $3.87 $3.92 $3.97
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 $3.86 $3.91 $3.96
1. Non-core items (EIX Parent & Other) for the nine months ended September 30, 2016
2. See Third Quarter and YTD 2016 Earnings Summaries and Use of Non-GAAP Financial Measures
3. Changes since original February 24, 2016 guidance include (per share): $(0.03) for lower SCE rate base; $0.13 for SCE productivity and financing benefits; $(0.01) for SCE energy
efficiency; $(0.09) for EIX Parent & Other. $(0.01) for EIX Parent & Other non-core items not included in chart
• Holding
company -
$(0.15)
• Edison Energy
Group - $(0.12)
2016 Earnings Per Share Guidance
November 2, 2016 19
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
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
November 2, 2016 20
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 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
November 2, 2016 21
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 Integrator for Energy-as-a-
Service platform serving large
commercial and industrial customers –
capital light business model
• Solar opportunities focused on
commercial and industrial customers, co-
operatives and community solar
programs
• Competitive transmission opportunities
outside SCE service territory and
founding member of Grid AssuranceTM
• Desalination of brackish water and on-
site wastewater recycling pilot projects
Long-Term Industry Trends Strategy
November 2, 2016 22
• 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
Edison Energy launched in March 2016 to become the trusted advisor to the largest
users of energy nationwide
Changing Customer Needs
The Opportunity: Trusted Advisor and Solution Integrator
Edison Energy Focus: Commercial & Industrial
November 2, 2016 23
Edison Energy: Acquired Businesses Summary
• Provides comprehensive renewable energy advisory and procurement services to
leading Fortune 1000 companies, universities and municipalities
• Proprietary market access platform procuring energy for clients by negotiating
multiyear power purchase agreements, controlling energy costs and improving the
environmental performance of their operations
• Leading provider of custom energy consulting services for large, multi-site,
commercial and industrial energy users with a focus on achieving significant energy
cost savings and control
• Collaborates with clients on strategic decisions to achieve 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
• Full-service energy consulting, engineering and project development specializing in
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
commercial and industrial customers, co-operatives, and community programs solar
solutions that provide energy cost savings and carbon reduction opportunities
November 2, 2016 24
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 address 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
November 2, 2016 25
Appendix
November 2, 2016 26
SCE Tax Memorandum Account
• 2018 GRC continues tax accounting memorandum account (TAMA) established in 2015 GRC
decision, which tracks tax benefits or costs associated with changes in:
tax accounting methods
tax laws and regulations impacting depreciation or tax repair
forecasted tax repairs deductions (actual vs. amounts authorized)
depreciation or tax repair deductions as a result of an audit; and
any impact of a private letter ruling related to normalization
• Once a year, aggregate over or undercollection will be calculated and refunded to or collected from
customers
• $70 million regulatory liability at September 30, 2016; in Q2 2016, $206 million transferred to a
balancing account for refund to customers
Tax Repair Deductions
Bonus Depreciation
Tax Policy Rate Base and Earnings Implications
• No earnings impact associated with incremental tax repair
deductions
• No rate base impact
• Flow-through rate making applies
• Earnings impacts occur in relevant year of extension rather
than next GRC cycle
• Normalization rate making applies
November 2, 2016 27
SCE Historical Capital Expenditures
($ billions)
$3.8
$3.9 $3.9
$3.5
$4.0 $3.9
2010 2011 2012 2013 2014 2015
November 2, 2016 28
Detailed Capital Expenditures at Request Level – 2016-2020
2016 2017 2018 2019 2020 Total
Core Distribution1,2 $2.9 $2.9 $3.2 $3.2 $3.1 $15.3
Mobile Home Park Conversion 0.1 0.1 - - - 0.2
Grid Modernization 0.0 0.2 0.6 0.8 0.7 2.3
Subtotal Distribution $3.0 $3.2 $3.9 $3.9 $3.8 $17.8
Transmission1 $0.5 $1.0 $0.9 $1.0 $0.9 $4.4
Generation1 $0.2 $0.2 $0.2 $0.2 $0.2 $1.1
Total $3.8 $4.5 $5.0 $5.2 $4.9 $23.3
Capital Expenditure/Rate Base Detailed Forecast
Detailed Rate Base at Request Level – 2016-2020
2016 2017 2018 2019 2020
Traditional Rate Base $24.9 $26.4 $29.3 $31.6 $33.7
Grid Modernization - - 0.3 0.8 1.4
Total $24.9 $26.4 $29.6 $32.4 $35.1
1. Includes allocated capitalized overheads and general plant
2. Includes $12 million Charge Ready Pilot (2016) and $69 million of Energy Storage (2016-2020; average $14 million per year)
($ in billions)
November 2, 2016 29
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
schedule to be set by ALJ; intervenor testimony
expected in Q2 2017
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 and October 2016; split into
three tracks with additional sub‐tracks
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
record reopened in May 2016
CPUC decisions on pending challenges to the
SONGS Settlement Agreement
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 broadened March 2016 to address SB
350 transportation electrification objectives
Q2 2016 workshops held; utility project proposals
due January 2017
Key FERC Proceedings
FERC Formula Rates Transmission rate setting with annual updates ROE moratorium expired July 2015; settlement in
place through December 2017
November 2, 2016 30
Distribution Power Grid of the Future
One-Way Electricity Flow
• System designed to distribute
electricity from large central plant
• 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
November 2, 2016 31
Grid Modernization Framework
SCE will leverage its automation and infrastructure replacement programs to implement
circuit-specific solutions that improve safety and reliability, while updating the system for
continued DER adoption
Distribution Automation
Installation of more sensors and intelligent
switches on the distribution system
Substation Automation
Installation of next-generation substation
protection controls and communication
systems that enable grid devices to “plug
and play” into the distribution system
Communications Systems
Upgrade/Installation of wireless and fiber
optic networks to allow for safe and secure
coverage of data transfer between
automated devices across the power grid
Technology Platforms and
Applications
Software investments for grid analytics,
long-term planning and modeling
Power Grid Reinforcement
Acceleration of infrastructure replacement
programs
G
r
i
d
M
o
d
e
r
n
i
z
a
t
i
o
n
July 2015 DRP Filing 2018 GRC Application
Advanced Grid 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 to
enable DER penetration and operation
Technology Platforms
Foundational tools for forecasting and
planning; management systems to operate
the power grid
Increased Grid Capacity for DERs
Upgrade portions of power grid to increase
capacity, improve reliability, and address
technology obsolescence
November 2, 2016 32
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
November 2, 2016 33
CPUC Distributed Energy Resources (DER) Proceedings
Expanded scope
• Competitive DER solicitation
framework: product definition,
rules, plans, standard contracts,
“review groups,” and DER
valuation methodology
• Electric power company roles in
DER markets, 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
(Near term
proceedings
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
2016)
November 2, 2016 34
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
22,751
31,693
5,469
3,543
1,433
64,889
1,331
66,220
4,412,581
564,948
10,535
46,433
21,273
132
22
5,055,924
28,282
N/A
November 2, 2016 35
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 20.2 billion kWh, or
110%
• On September 8, 2016, Governor Brown sighed SB 32, which
requires statewide GHG emissions to be reduced to at least
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 2016 program budget:
$333 million
• $0.04 per share 2016 earnings
incentive potential
Electric Power Company Role
Solar 26%
Small Hydro
2%
Geothermal
37%
Wind 33%
2015 Renewable Resources:
24.3% of SCE’s portfolio
Biomass 2%
November 2, 2016 36
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¢
November 2, 2016 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
Comparative System
Average Rates1
% Delta
EIX – 14.9¢ --
PG&E – 18.2¢ 22%
SDG&E – 20.4¢ 37%
November 2, 2016 38
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 – October 2016
17.2¢
38.5¢
100% 101‐400% >400%
22.0¢
Usage Level (% of Baseline)
¢
/
k
W
h
Future Rates - 2019
Usage Level (% of Baseline)
15.7¢
23.0¢
29.3¢
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
November 2, 2016 39
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; CPUC denied
parties’ AFRs on September 22, 2016.
SCE Net Energy Metering Statistics (September 2016):
• 199,115 combined residential and non-residential projects –
1,573 MW installed (of 2,240 MW cap)
99.9% solar
194,366 residential – 1,014 MW
4,567 non-residential – 559 MW
Approximately 2,920,819 MWh/year generated
November 2, 2016 40
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
• 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
November 2, 2016 41
SCE Rates and Bills Comparison
13.0
16.3
US Average SCE
25%
Higher
2015-16 Average Residential Rates
(¢/kWh)
2015-16 Average Residential Bills
($ per Month)
¢
¢
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 –
cost for low carbon energy are higher than
high carbon sources
• Average monthly residential bills are
substantially lower than national average as
higher rate levels offset by lower usage
39% 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 12-Months Ending July 2016
$123
$93
US Average SCE
24%
Lower
November 2, 2016 42
Q3
2016
Q3
2015 Variance
Basic Earnings Per Share (EPS)1
SCE $1.34 $1.19 $0.15
EIX Parent & Other (0.05) (0.03) (0.02)
Discontinued Operations 0.13 (0.13)
Basic EPS $1.29 $1.29 $
Less: Non-Core Items
SCE $ $ $
EIX Parent & Other
Discontinued Operations2 0.13 (0.13)
Total Non-Core Items $ $0.13 ($0.13)
Core Earnings Per Share (EPS)3
SCE $1.34 $1.19 $0.15
EIX Parent & Other (0.05) (0.03) (0.02)
Core EPS3 $1.29 $1.16 $0.13
Key SCE EPS Drivers
Revenue4,5 $0.25
- CPUC – Timing of GRC 0.13
- CPUC – Escalation 0.08
- CPUC – GRC return on pole loading rate base 0.03
- FERC revenue and other 0.01
Lower O&M 0.04
Higher depreciation (0.04)
Higher net financing costs (0.03)
Higher income tax expenses4 (0.09)
Other 0.02
- Property and other taxes (0.01)
- Other income and expenses 0.03
Total $0.15
Third Quarter Earnings Summary
Key EIX EPS Drivers
EMG – Sold portfolio in 2015 (0.01)
EEG – Higher operating expenses (0.01)
Non-core items2,3 (0.13)
Total $(0.15)
1. Diluted earnings were $1.27 and $1.28 per share for the three months ended September 30, 2016 and 2015, respectively
2. Discontinued Operations include income tax benefits of $0.08 from revised estimates based on filing of the 2014 tax returns and insurance recoveries of $0.05 related to
claims resolved in the EME settlement
3. See Use of Non-GAAP Financial Measures
4. Excludes revenue and income taxes for 2016 incremental tax repair deductions and pole loading program-based cost of removal of $0.10
5. Excludes San Onofre revenue of $0.03, which was offset by depreciation expense of $0.01 and income taxes of $(0.04)
November 2, 2016 43
YTD
2016
YTD
2015 Variance
Basic Earnings Per Share (EPS)1
SCE $3.18 $3.31 $(0.13)
EIX Parent & Other (0.22) (0.07) (0.15)
Discontinued Operations 0.13 (0.13)
Basic EPS $2.96 $3.37 $(0.41)
Less: Non-Core Items
SCE $ $ $
EIX Parent & Other2 0.01 0.02 (0.01)
Discontinued Operations3 0.13 (0.13)
Total Non-Core Items $0.01 $0.15 $(0.14)
Core Earnings Per Share (EPS)4
SCE $3.18 $3.31 $(0.13)
EIX Parent & Other (0.23) (0.09) (0.14)
Core EPS4 $2.95 $3.22 $(0.27)
Key SCE EPS Drivers
Revenue5,6,7 $0.40
- CPUC – Escalation 0.26
- CPUC – GRC return on pole loading rate base 0.08
- CPUC – Other (0.01)
- FERC revenue and other 0.07
Higher depreciation (0.10)
Higher net financing costs (0.06)
Income taxes5,7 (0.38)
- 2015 change in uncertain tax positions (0.31)
- Higher tax expenses (0.07)
Other 0.01
- Property and other taxes (0.04)
- Other income and expenses 0.05
Total $(0.13)
YTD 2016 Earnings Summary
Key EIX EPS Drivers
EIX parent – Higher corporate expenses $(0.01)
EMG – Sold portfolio in 2015 and income taxes (0.05)
EEG – Buyout of an earn-out provision, higher
development and operating costs (0.08)
Non-core items2,3,4 (0.14)
Total $(0.28)
1. Diluted earnings were $2.94 and $3.34 per share for the nine months ended September 30, 2016 and 2015, respectively
2. Impact of hypothetical liquidation at book value (HLBV) accounting method
3. Discontinued Operations include income tax benefits of $0.08 from revised estimates based on filing of the 2014 tax returns and insurance recoveries of $0.05 related to
claims resolved in the EME settlement
4. See Use of Non-GAAP Financial Measures
5. Excludes revenue and income taxes for 2016 incremental tax repair deductions and pole loading program-based cost of removal of $0.27
6. Excludes San Onofre revenue of $0.06 which was offset by depreciation expense of $0.01, property taxes of $0.01, interest expense of $0.01 and income taxes of $(0.09)
7. Excludes $0.24 of refunds to customers for incremental tax benefits related to 2012 - 2014 repair deductions
November 2, 2016 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)
$998
SCE Results of Operations
• Earning activities – revenue authorized by CPUC and FERC to provide reasonable cost recovery and return on investment
• Cost-recovery activities – CPUC- and FERC-authorized balancing accounts to recover specific project or program costs, subject
to reasonableness review or compliance with upfront standards
Earning
Activities
Cost-
Recovery
Activities
Total
Consolidated
2015
Earning
Activities
Cost-
Recovery
Activities
Total
Consolidated
2014
Operating revenue
Purchased power and fuel
Operation and maintenance
Depreciation, decommissioning and amortization
Property and other taxes
Impairment and other charges
Total operating expenses
Operating income
Interest expense
Other income and expenses
Income before income taxes
Income tax expense
Net income
Preferred and preference stock dividend
requirements
Net income available for common stock
Core earnings
Non-core earnings
Total SCE GAAP earnings
Note: See Use of Non-GAAP Financial Measures
($ 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)
$1,453
November 2, 2016 45
Earnings Non-GAAP Reconciliations
Note: See Use of Non-GAAP Financial Measures
($ 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
$389
(11)
43
$421
$ –
1
43
$44
$389
(12)
$377
$435
(16)
–
$419
$ –
–
–
$ –
$435
(16)
$419
Q3
2015
Q3
2016
Earnings Attributable to Edison International
$1,079
(23)
43
$1,099
$ –
7
43
$50
$1,079
(30)
$1,049
$1,037
(71)
(1)
$965
$ –
5
(1)
$4
$1,037
(76)
$961
YTD
2015
YTD
2016
November 2, 2016 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
$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
November 2, 2016 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