Exhibit 99.2

Exhibit 99.2

Leading the Way in Electricity SM

Fourth Quarter 2011 Financial Teleconference

February 29, 2012

EDISON INTERNATIONAL®

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Forward-Looking Statements

Statements contained in this presentation about future performance, including, without limitation, earnings, asset and rate base growth, load growth, capital expenditures, 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 are discussed under the headings “Risk Factors,” and “Management’s Discussion and Analysis” in Edison International’s 2011 Form 10-K 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.

February 29, 2012 1 EDISON INTERNATIONAL®

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Fourth Quarter Earnings Summary

Q4 10 Q4 11 Variance

Core EPS1

SCE $0.56 $0.76 $0.20

EMG 0.10 (0.03) (0.13)

EIX parent company (0.08) 0.02 0.10 and other

Core EPS $0.58 $0.75 $0.17

Non-Core Items

SCE $— $— $—

EMG (0.07) (3.26) (3.19)

EIX parent company — (0.06) (0.06) and other

Total Non-Core $(0.07) $(3.32) $(3.25) Basic EPS $0.51 $(2.57) $(3.08) Diluted EPS $0.51 $(2.57) $(3.08)

Core Earnings Core EPS

($ millions)

$243 $0.75

$190 $0.58

Q4 10 Q4 11 Q4 10 Q4 11

GAAP Earnings Basic EPS

($ millions)

$166 $0.51

$(839) $(2.57) Q4 10 Q4 11 Q4 10 Q4 11

1 See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. The per share impact of participating securities is included in EIX parent company and other and was zero for the quarters ended December 31, 2011 and December 31, 2010.

February 29, 2012 2 EDISON INTERNATIONAL®

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SCE Fourth Quarter Highlights

EPS Q4 10 Q4 11 Variance

Core1 $0.56 $0.76 $0.20

Non-Core Items — — —

Basic EPS1 $0.56 $0.76 $0.20

Key Core Earnings Drivers

Higher operating revenue $0.05

Rate base growth

Operating revenue and other

Lower expenses 0.15 Higher depreciation (0.04) Higher net financing costs (0.03)

Income tax and other

Deferred income taxes2 0.09 Other (0.02) Total $0.20

Recent Developments

• Proposed decision on 2012 GRC pending

• Tehachapi transmission project supplemental information filed with CPUC January 10 and February 1 for Chino Hills segment

• SONGS Unit 2 steam generator preventive tube work being addressed during current planned outage; testing for tube leak cause continues on Unit 3 during unplanned outage; 20 year manufacturer warranty

• $0.03 per share in energy efficiency incentive earnings recorded

1 See Use of Non-GAAP Financial Measures in Appendix and Fourth Quarter Earnings Summary slide for reconciliation of core earnings per share to basic earnings per share.

2 Fourth quarter recognition of deferred income tax asset related to excess tax over book basis of nuclear fuel inventories.

February 29, 2012 3 EDISON INTERNATIONAL®

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EMG Fourth Quarter Highlights

EPS Q4 10 Q4 11 Variance

Core1 $0.10 $(0.03) $(0.13)

Non-Core Items2 (0.07) (3.26) (3.19)

Basic EPS1 $0.03 $(3.29) $(3.32)

Key Core Earnings Drivers

Merchant coal3

Midwest Generation $(0.15) Homer City (0.06) EMMT—trading 0.01 Renewable energy projects 0.03 Natural gas projects 0.02 Higher net corporate interest expense and (0.04) Lower income taxes and other 0.06 Total $(0.13)

Recent Developments

• EPA MATS rule finalized in December; consistent with coal fleet compliance scenarios

• CSAPR rule stayed in December; CAIR allowance-based compliance approach continues in 2012

• New multi-year rail transportation agreement for Midwest Generation effective January 1, 2012

• Capistrano wind financing completed on February 13, 2012

• Year end asset impairment for Homer City, three Midwest Generation facilities, and certain wind projects

1 See Use of Non-GAAP Financial Measures in Appendix and Fourth Quarter Earnings Summary slide for reconciliation of core earnings per share to basic earnings per share.

2 Includes impairments and other charges for the quarter ended December 31, 2011, and write-off of capitalized costs for the quarter ended December 31, 2010.

3 Includes per share impact of unrealized gains of $0.01 for the quarter ended December 31, 2011, and losses of ($0.01) for the quarter ended December 31, 2010.

February 29, 2012 4 EDISON INTERNATIONAL®

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Fourth Quarter 2011 Non-Core Charges

EPS Description

EMG

Impairment of Homer City (1.91) EMG expects to lose substantially all beneficial economic interest and

material control of the plant; remaining net assets were $167 million

at December 31, 2011; Homer City expected to eventually be a

discontinued operations

Impairment of three Midwest (1.19) Fair value of Fisk, Crawford, and Waukegan stations determined to be

Generation facilities zero; Fisk to be shut down by the end of 2012; Crawford to be shut

down by the end of 2014

Impairment of wind portfolio (0.13) Fair value of Storm Lake and four small Minnesota wind projects

and charges reduced from $53 million to $23 million based on increasing operating

costs and declining future power prices; reduced staffing and wind

pipeline-related charges

Write-down of net investment in (0.05) Net investment in three aircraft owned by Edison Capital and leased to

aircraft leases American Airlines written down from $34 million to $8 million as a

result of lessee filing for bankruptcy

Gain on sale of March Point $0.02 Final distribution related to 2010 sale of 50% interest in March Point

EMG Non-Core Total $(3.26)

EIX parent company and other

Deferred tax adjustment (0.06) Relates to EMG asset impairments

Non-Core Total $(3.32)

February 29, 2012 5 EDISON INTERNATIONAL®

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Full-Year Earnings Summary

2010 2011 Variance

Core EPS1

SCE $3.01 $3.33 $0.32

EMG 0.59 (0.07) (0.66)

EIX parent company (0.12) (0.04) 0.08

and other

Core EPS $3.48 $3.22 $(0.26)

Non-Core Items

SCE $0.18 $— $(0.18)

EMG 0.10 (3.27) (3.37)

EIX parent company 0.08 (0.06) (0.14)

and other

Total Non-Core $0.36 $(3.33) $(3.69)

Basic EPS $3.84 $(0.11) $(3.95)

Diluted EPS $3.82 $(0.11) $(3.93)

Core Earnings Core EPS

($ millions)

$1,140 $3.48

$1,048 $3.22

2010 2011 2010 2011

GAAP Earnings Basic EPS

($ millions)

$1,256 $3.84

$(37) $(0.11)

2010 2011 2010 2011

1 See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. The per share impact of participating securities is included in EIX parent company and other and was zero for the year ended December 31, 2011, and $(0.01) for the year ended December 31, 2010.

February 29, 2012 6 EDISON INTERNATIONAL®

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SCE Full-Year Highlights

EPS 2010 2011 Variance

Core1 $3.01 $3.33 $0.32

Non-Core Items2 0.18 — (0.18)

Basic EPS1 $3.19 $3.33 $0.14

Key Core Earnings Drivers

Higher operating revenue $0.54

Rate base growth

Operating revenue and other

Lower expenses 0.12

Higher depreciation (0.15)

Higher net financing costs (0.10)

Income tax and other

Change of tax accounting (0.12)

Deferred income taxes3 0.09

Other (0.06)

Total $0.32

1 See Use of Non-GAAP Financial Measures in Appendix for reconciliation of core earnings per share to basic earnings per share.

2 Global tax settlement and Medicare Part D.

3 Fourth quarter recognition of deferred income tax asset related to excess tax over book basis of nuclear fuel inventories.

February 29, 2012 7 EDISON INTERNATIONAL®

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EMG Full-Year Highlights

EPS 2010 2011 Variance

Core1 $0.59 $(0.07) $(0.66)

Non-Core Items2 0.10 (3.27) (3.37)

Basic EPS1 $0.69 $(3.34) $(4.03)

Key Core Earnings Drivers

Merchant coal3

Midwest Generation $(0.38)

Homer City (0.20)

EMMT—trading (0.07)

Renewable energy projects 0.04

Higher net interest expense (0.13)

Lower income taxes and other 0.08

Total $(0.66)

1 See Use of Non-GAAP Financial Measures in Appendix for reconciliation of core earnings per share to basic earnings per share.

2 Includes impairments and other charges for the year ended December 31, 2011, and global tax settlement, discontinued operations, and write-off of capitalized costs for the year ended December 31, 2010.

3 Includes per share impact of unrealized gains of $0.01 for the year ended December 31, 2011, and losses of $(0.06) for the year ended December 31, 2010.

February 29, 2012 8 EDISON INTERNATIONAL®

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SCE Year-End Rate Base and Core Earnings

($ billions)

$18.8 2006 – 2011 CAGR

Rate Base1 11%

$16.8

Core Earnings2 12%

$15.0

$13.1

$12.5

$11.4

2006 2007 2008 2009 2010 2011

Core

$1.89

$2.07

$2.25

$2.68

$3.01

$3.33

Earnings2

1 Recorded rate base, year-end basis.

2 See SCE Core EPS Non-GAAP Reconciliations and Use of Non -GAAP Financial Measures

in Appendix.

February 29, 2012 0 EDISON INTERNATIONAL®

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SCE Capital Expenditures Forecast

($ billions)

$3.9

$5.0

$4.4

$3.8

2011 2012 2013 2014

Forecast

By Classification

$ %

Solar Photovoltaic 0.2 1

Edison SmartConnect™ 0.4 3

Generation 1.7 13

Transmission 3.8 29

Distribution 7.1 54

Total 13.2 100

By Proceeding

%

2012 CPUC Rate Case 68

Other CPUC 3

FERC Cases 29

Total 100

Total

Forecast $5.0 $4.4 $3.8 $13.2

Range1 $4.4 $4.0 $3.4 $11.8

Capital expenditures reflect 2012 GRC assumptions; proposed decision is pending

1 Currently forecasted 2012-2014 FERC and CPUC capital spending, subject to timely receipt of permitting, licensing, and regulatory approvals. Forecast range reflects an 11% variability to annual expenditure levels related to execution risk, scope change, delays, regulatory constraints, and other contingencies. Variability based on average level of actual variability experienced from 2009 through 2011.

February 29, 2012 10 EDISON INTERNATIONAL®

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SCE Rate Base Forecast

($ billions)

2012 – 2014 CAGR2

Rate Base 7-9%

$20.8

$19.9

2012

$22.6

$21.2

2013

$24.7

$22.8

2014

Rate base forecast1 based on 2012 CPUC GRC and 2012 FERC Formula Rate requests including consolidated FERC CWIP in rate base Forecast subject to change based on timely receipt of permitting, licensing, capital deployment, and regulatory approvals on capital expenditures

1 Forecast range is weighted-average year basis and includes: (1) forecasted 2012-2014 CPUC and FERC rate base requests; (2) SCE Solar PV program including CPUC approved petition for modification; (3) consolidation of CWIP projects; (4) estimated impact of bonus depreciation provisions as allowed by The Tax Relief and Unemployment Insurance Reauthorization and Job Creation Acts of 2010. Rate Base forecast range reflects capital expenditure forecast range from SCE Capital Expenditures Forecast.

2 Forecasted Rate Base and related earnings per share growth may vary depending on authorized revenues and cost of capital, including financing costs, operating expenses, taxes, and other revenue activities.

February 29, 2012 11 EDISON INTERNATIONAL®

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EMG Hedge Program Status

December 31, 2011

Change Change Change

From From From

2012 Q3 2013 Q3 2014 Q3

Midwest Generation

Total GWh (NI, AEP/Dayton, and Indiana Hubs)2 7,185 (1,021) 1,020 — — —

Average price ($/MWh)1 $38.76 $1.16 $40.43 $1.32 — —

Coal under contract (millions of tons) 16.0 2.3 9.8 — 9.8 —

Homer City

Total GWh (West Hub)3 432 (887) — (204) — —

Average price ($/MWh)1,4 $52.34 $0.55 — — — —

Coal under contract (millions of tons) 3.3 1.1 0.8 — — —

1 The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions are not directly comparable to the 24-hour Northern Illinois Hub or PJM West Hub prices set forth above.

2 Includes hedging transactions primarily at the Northern Illinois Hub and to a lesser extent the AEP/Dayton Hub, both in PJM, and the Indiana Hub in MISO.

3 Includes hedging transactions primarily at the PJM West Hub and to a lesser extent at other trading locations. 2012 includes hedging activities entered into by EMMT for the Homer City plant that are not designated under the intercompany agreements with Homer City due to limitations under the sale leaseback transaction documents.

4 The average price/MWh includes 172 MW of capacity for periods ranging from January 1, 2012 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

February 29, 2012 12 EDISON INTERNATIONAL®

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EMG Capital Expenditures

December 31, 2011

($ millions)

20111 2012 2013 2014

Midwest Generation

Environmental expenditures1 $82 $35 $102 $311

Plant capital expenditures 27 21 46 16

Walnut Creek Project2 269 229 40 —

Renewable Energy Projects

Capital & construction 267 114 1 2

Turbine commitments 8 — — —

Other capital expenditures 7 22 19 15

Subtotal $660 $421 $208 $344

Homer City

Environmental expenditures3 4 — — —

Plant capital expenditures3 11 — — —

Total $675 $421 $208 $344

2 Projected environmental expenditures retrofit Powerton Units 5 and 6, Joliet Units 7 and 8, and Will County Units 3 and 4. The estimated cost of retrofitting Joliet Unit 6, if made, would be approximately $75 million, while the estimated cost of retrofitting the Waukegan Station, if made, would be approximately $160 million. No decisions have been made to retrofit particular units.

3 Total project costs are estimated to be $610 million. Capital expenditures in the above table exclude $72 million of interest and expenses during construction, financing costs, and costs incurred before 2011.

4 Excludes expenditures beyond 2011, as EMG expects to lose substantially all beneficial economic interest and control in the plant.

February 29, 2012 13 EDISON INTERNATIONAL®

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EMG Wind Strategy & Financing

Refocused Wind Strategy

Other Recent Project Wind Debt Developments

Capistrano Wind Partners (CWP) formed February 13,

$242 million debt financing closed in December 2011

2012 by EMG, TIAA-CREF, and CIRI (an Alaskan native

for three wind projects:

corporation). $460 million commitment for wind

Taloga, Oklahoma (130 MW)

development:

Buffalo Bear, Oklahoma

(19 MW)

Operating projects transferred –Cedro Hill,

Texas (150 MW) and Mountain Wind I and II,

Pinnacle, West Virginia

(55 MW)

Wyoming (141 MW)

$110 million received in December 2011 and

Projects to be transferred after completion

approximately $95 million by end of March 2012

in 2012 –Broken Bow, Nebraska (80 MW)

January 2012 –Pinnacle began commercial operations

and Crofton Bluffs, Nebraska (40 MW)

Wind Project Debt / Third-Party Capital

Transaction will net EMG ~$235 million

(for five projects)

1,406 MW financed ($1,147 million) 1

EMG retains an economic interest and will

575 MW not financed:

continue to operate and consolidate projects

387 MW contracted2

Reduced development pipeline from 3,800 MW to

188 MW merchant –Goat Wind, Texas

approximately 1,300 MW along with related staffing

(150 MW), Lookout, Pennsylvania (38 MW)

reduction

New wind projects to be developed or acquired only

with third-party capital

1 Includes four Minnesota projects (total 50 MW) that were impaired in the quarter ended December 31, 2011.

2 Includes Storm Lake project (108 MW) that was impaired in the quarter ended December 31, 2011.

February 29, 2012

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Liquidity Profile

December 31, 2011

($ millions)

EMG EME Edison EIX

& Capital parent co.

Sources SCE Subs & other1 & other

Credit Facility $2,894 $1,064 $ $1,426

Credit Facility (availability) $2,394 $995 $ $1,416

Cash & short-term investments2 62 1,300 61 51

Available Liquidity $2,456 $2,295 $61 $1,467

2011 EMG liquidity improved from:

$388 million US Treasury Grants

$167 million distributions from wind financings

Recognized tax benefits total $520 million at December 31, 2011:

EMG recognized tax-sharing benefits related to net operating loss carryforwards of $326 million and production tax and other credit carryforwards of $194 million at December 31, 2011

EMG received $213 million from EIX under tax sharing agreement in 2011 and is expected to make a $185 million payment in 2012 for change in allocation of taxes resulting from net operating loss carrybacks

EMG not expected to receive tax sharing payments from EIX until at least 2013, assuming continuation of current tax law, and may not become current on those payments for several years

EME credit facility terminated in February 2012

Edison Capital & other includes Mission Energy Holding Company and other EMG subsidiaries.

EMG had corporate cash of $951 million at December 31, 2011. Corporate cash is defined as cash and cash equivalents of EMG and cash and cash equivalents of subsidiaries that do not have third-party dividend restrictions.

February 29, 2012 15 EDISON INTERNATIONAL®

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2012 Operating Assumptions

Southern California Edison

Average rate base range of $19.9—$20.8 million

Approved capital structure: 48% equity, 11.5% ROE (CPUC), 11.1% ROE (FERC)

No energy efficiency earnings

AFUDC offsets other costs outside CPUC rate case

FERC ROE may change due to differences in project incentives

Edison Mission Group

No capital commitment from EIX

Reduced dispatch and coal consumption at current power prices

Reduced operations and maintenance expenses at coal plants

Transition Homer City ownership and discontinued operations accounting

Delayed environmental capital expenditures due to use of ultra-low sulfur coal

Reduced development spending

Edison International

Modest dividend increase (subject to Board approval)

Return to historical trend for holding company costs

No change in basic shares outstanding

Due to pending SCE regulatory and financial decisions impacting 2012 earnings, 2012 guidance will not be provided at this time

February 29, 2012 16 EDISON INTERNATIONAL®

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Appendix

February 29, 2012 17 EDISON INTERNATIONAL®

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Updates Since Our Last Presentation

Q4 11 results and standard information

SCE Capital Expenditures Forecast (p. 10)

SCE Rate Base Forecast (p. 11)

EMG Capital Expenditures (p. 13)

EMG Wind Strategy & Financing (p. 14) – New Slide

2012 Operating Assumptions (p. 16) – New Slide

Financing Strategies (p. 20)

SCE 2012 CPUC General Rate Case (p. 25)

SCE Transmission Program (p. 27)

EMG 2006 Illinois CPS Agreement (p. 36)

February 29, 2012 18 EDISON INTERNATIONAL®

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Delivering Superior and Sustained Value

Edison International

Diversified platform (regulated and competitive) best positions EIX in an industry undergoing unprecedented change

Positioned for long-term earnings and dividend growth

Investment discipline

Southern California Edison

Balancing electric system safety, reliability, and affordability to ensure long- term sustainable growth

Strategic focus on infrastructure investment (transmission and distribution)

Pursuing advanced technologies (Smart Grid and electric transportation)

Decoupled regulatory model mitigates risk of changing demand and fuel cost

Edison Mission Group

Narrowed and refocused business strategy – larger Midwest Generation stations, and natural gas-fired and wind generation projects

Preserve and enhance liquidity to weather current market conditions

Our key operating principles emphasize financial discipline, superior execution, and innovative solutions to the challenges of today and tomorrow

February 29, 2012 19 EDISON INTERNATIONAL®

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Financing Strategies

Southern California Edison

Authorized CPUC capital structure (through 2012): 48% common equity, 43% long-term debt, 9% preferred stock

Periodic issuance of debt and preferred equity to maintain authorized capital structure

Issue short-term debt to meet liquidity requirements

Edison Mission Group

No financial support from, or distributions to, Edison International

Preserve and enhance liquidity:

Reduce O&M spending on smaller Midwest Generation facilities

Lower and delay Midwest Generation environmental spending

Reduce development spending

Capistrano Wind Partners and additional non-recourse project debt

Dividend Policy

Modest annual increases, subject to Board approval, while SCE implements major capital investment program

Target payout ratio is 45-55% of SCE earnings

February 29, 2012 20 EDISON INTERNATIONAL®

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Debt Maturity Profiles

December 31, 2011

($ millions)

2012 2013 2014 2015

Short- and Long-Term Debt Maturities

SCE $419 $— $1,200 $300

EMG1 57 755 284 72

EIX 10 — — —

Expiration of Credit Facilities

SCE $— $2,894

EME2 600 —

MWG3 500 —

EIX — 1,426

1 Includes project finance and other non-recourse debt.

2 EME credit facility terminated in February 2012.

3 MWG credit facility may not be available prior to maturity.

February 29, 2012 21 EDISON INTERNATIONAL®

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Earnings Non-GAAP Reconciliations

($ millions)

Reconciliation of EIX Core Earnings to EIX GAAP Earnings

Earnings Attributable to

Edison International Q4 10 Q4 11 2010 2011

Core Earnings

SCE $181 $247 $984 $1,085

EMG 34 (10) 192 (25)

EIX parent company and other (25) 6 (36) (12)

Core Earnings $190 $243 $1,140 $1,048

Non-core items

SCE – tax impact of health care legislation $— $— $(39) $—

SCE – tax settlement — — 95 —

EMG – tax settlement2 — — 52 —

EMG – impairment – Homer City Station — (623) — (623)

EMG – impairment – Fisk, Crawford, and Waukegan Stations — (386) — (386)

EMG – wind related charges — (41) — (41)

EMG – write-off of capitalized costs – Powerton Station (24) — (24) —

EMG – write-down in net investment in aircraft leases — (16) — (16)

EMG – gain on sale of March Point — 5 — 5

EMG – discontinued operations — — 4 (3)

EIX – tax settlement — — 28 —

EIX – asset impairment deferred tax adjustment — (21) — (21)

Total Non-core items $(24) $(1,082) $116 $(1,085)

GAAP Earnings $166 $(839) $1,256 $(37)

1 See Use of Non-GAAP Financial Measures.

2 Includes termination of Edison Capital’s cross-border leases.

February 29, 2012 22 EDISON INTERNATIONAL®

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Our Shareholder Value Proposition

Dual platform operating across the full spectrum of the electric industry

Southern California Edison

Among the best domestic electric utility growth platforms

Supportive regulatory framework

Leadership in renewable energy, energy efficiency, electric vehicles and Smart Grid development

Edison Mission Group

Narrowed and refocused business strategy on larger Midwest Generation stations, and natural gas-fired and wind generation projects

Preserve and enhance liquidity to weather current market conditions

Commitment to long-term shareholder value creation

Incentive compensation and stock ownership guidelines consistent with shareholder interests

Edison people committed to safety, customer service, and operational excellence

February 29, 2012 23 EDISON INTERNATIONAL®

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SCE Appendix

February 29, 2012 24 EDISON INTERNATIONAL®

SCE 2012 CPUC General Rate Case

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Application filed November 23, 2010 to set base revenue requirement for 2012-2014

Rate increase driven by system reliability, load growth, capital-related expense, and technology needs

Excludes fuel and purchased power costs, and transmission projects under FERC jurisdiction

Cost of capital determined in separate proceeding

SCE’s current request based on October 24 update testimony: Revenue Requirement increase of $809 million in 2012, $117 million in 2013, and $513 million in 2014, net of sales growth

The Division of Ratepayer Advocates (DRA) recommends a decrease in 2012 revenue requirement of approximately $850 million

$630 million operation and maintenance expense reductions

$220 million capital-related revenue requirement reductions

The Utility Reform Network and other interveners recommend an additional $610 million reduction beyond DRA adjustments, primarily capital-related in nature

Public participation hearing held January 26 on SCE’s response to the December 1 windstorm

Proposed decision pending

Final decision is retroactive to January 1, 2012, through memorandum account

February 29, 2012 25 EDISON INTERNATIONAL®

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SCE Cost of Capital Mechanism

Moody’s Baa Utility Index - 12-month moving average and spot rate through 2/15/12

Starting Index = 6.26% Moody’s Baa Utility Index Spot Rate Moving Average (since October 1, 2011 = 5.07%)

Feb-08 Feb-09 Feb-10 Feb-11 Feb-12

Since 2008, SCE’s CPUC authorized ROE has been 11.5%. The CPUC’s mechanism sets Return on Equity (ROE) annually through end of 2012

ROE adjustment based on 12-month average of Moody’s Baa utility bond index, measured in September of each year

If index exceeds a 1% deadband from starting index value of 6.26%, authorized ROE changes by half the difference

Moving average was 5.76% for final period ending 9/30/11; 2012 ROE will continue at 11.5% through year- end (mechanism not operative for 2013)

By April 20, 2012, SCE will submit an application to the CPUC for its 2013 Cost of Capital and authorized ROE

February 29, 2012 26 EDISON INTERNATIONAL®

February 29, 2012 1 EDISON INTERNATIONAL®

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SCE Transmission Program

In Direct % of

Project Lifecycle 2012-2014

Project Name Service Project Spend

Phase Forecast(1)

Date Costs(1) Complete

Tehachapi 1-11(2,4) Construction 2015 $2,500 62% $904

Devers-Colorado

River(4) Construction 2013 860 18% 709

Engineering /

Eldorado-Ivanpah(3) 2013 444 6% 417

Construction

Red Bluff Construction 2013 234 6% 220

Alberhill Licensing 2015 315 7% 242

San Joaquin Cross Engineering /

Valley Loop Construction 2014 190 10% 170

DCR 500kV Alberhill Redbluff Existing Substation

Tehachapi Segments 1-3 500kV Tehachapi Segments 4-11 500kV Eldorado Ivanpah San Joaquin Cross Valley Loop

Transmission expenditures are needed to improve system reliability and increase access to renewable energy

1 FERC and CPUC jurisdictional assets. Direct expenditures include direct labor, land and contract (materials & contractor) costs incurred for each project and excludes allocated overhead costs included in the SCE Capital Expenditures Forecast for 2012 - 2014. Subject to timely receipt of permitting, licensing, and regulatory approvals.

2 Segments 1-3A were energized and in-service in 2009. The remainder is under construction and will be phased into service through 2015. As required by the CPUC, SCE will file for a revised total project cost cap upon final project engineering, expected to be complete later this year.

3 Eldorado-Ivanpah Project received CPUC approval at $411 million related to reduced contingency. SCE has the ability to file an updated cost when final engineering is completed.

4 SCE has experienced significant cost pressures on its Tehachapi and Devers-Colorado River Transmission Projects, primarily related to environmental monitoring and mitigation costs, scope changes, and schedule delays. Related CPUC filings will be updated when final engineering is completed.

San Joaquin

Rector

Whirlwind

Santa Clarita

Pardee

Los Angeles

Ana Alberhill

San Diego

Valley

Colorado River

Loma Mira

Devers

Redbluff

Ivanpah

Eldorado

Cross Valley Loop

Highwind Windhub

Antelope Palmdale Vincent

February 29, 2012 27 EDISON INTERNATIONAL®

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Other SCE Key Regulatory Events

Case Date of Next

Number Filing Status Milestone

Settlement discussions on formula rate in

FERC Formula ER11-3697 06/03/11 progress. FERC rejected SCE’s request for Settlement conference to be held

Rate Filing rehearing regarding ROE and SCE has February 28 and 29, 2012

initiated court appeal

CPUC approval of Petition for

Modification for aviation marking and

Tehachapi Recently issued CPUC orders have lighting; Advice Letter with revised

Transmission A. 07-06-031 06/28/07 impacted construction on segment 8 costs based on final engineering

to be filed with CPUC

1st half of 2012

Devers-Colorado River Advice Letter with revised

Transmission A. 05-04-015 04/11/05 Construction began January 2012 costs to be filed with CPUC

1st half of 2012

May 2011, Federal Record of Decision Construction and early

Eldorado-Ivanpah A. 09-05-027 05/28/09 obtained from Bureau of Land interconnection to start

Transmission Management Q1 2012

Permit to Construct filed September 2009

converted to a CPCN filing March 2010. Draft Environmental Impact Report

Alberhill A. 09-09-022 09/30/09 Amended Proponent’s Environmental (EIR) is expected from the CPUC

Assessment (PEA) per CPUC request Q1 2012

submitted April 2011

Negative declaration on CEQA application

Four Corners Sale A. 10-11-010 11/15/10 issue January 2012. Proposed decision Final Decision expected

approving sale issued on February 16 March 22, 2012

February 29, 2012 28 EDISON INTERNATIONAL®

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SCE Results of Operations

($ millions)

Twelve Months Ended Dec 31, 2010

Utility

Utility Cost-

Earning Recovery Total

Activities Activities Consolidated

Operating Revenue $5,606 $4,377 $9,983

Fuel and purchased power — 3,293 3,293

Operation and maintenance 2,271 1,020 3,291

Depreciation, decommissioning and amortization 1,213 60 1,273

Property and other taxes 260 3 263

Gain on sale of assets — (1) (1)

Total operating expenses 3,744 4,375 8,119

Operating income 1,862 2 1,864

Net interest expense and other (330) (2) (332)

Income before income taxes 1,532 — 1,532

Income tax expense 440 — 440

Net income 1,092 — 1,092

Dividends on preferred and preference stock not

subject to mandatory redemption 52 — 52

Net income available for common stock $1,040 $— $1,040

Core Earnings $984

Non-Core Earnings1:

Global settlement 95

Tax impact of health care legislation (39)

Total SCE GAAP Earnings $1,040

Twelve Months Ended Dec 31, 2011

Utility

Utility Cost-

Earning Recovery Total

Activities Activities Consolidated

$5,902 $4,675 $10,577

— 3,356 3,356

2,208 1,179 3,387

1,294 132 1,426

277 8 285

— — —

3,779 4,675 8,454

2,123 — 2,123

(378) — (378)

1,745 — 1,745

601 — 601

1,144 — 1,144

59 — 59

$1,085 $— $1,085

$1,085

—

—

$1,085

1 See Use of Non-GAAP Financial Measures.

February 29, 2012 29 EDISON INTERNATIONAL®

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SCE Core EPS Non-GAAP Reconciliations

Reconciliation of SCE Core Earnings Per Share to SCE GAAP Earnings Per Share

Earnings Per Share

Attributable to SCE 2006 2007 2008 2009 2010 2011 CAGR

Core EPS1 $1.89 $2.07 $2.25 $2.68 $3.01 $3.33 12%

Non-core items

Tax settlement — — — 0.94 0.30 —

Health care legislation — — — — (0.12) —

Regulatory and tax items 0.40 0.10 (0.15) 0.14 — —

Generator settlement/refund incentive 0.09 — — — — —

Total non-core items 0.49 0.10 (0.15) 1.08 0.18 —

Basic EPS $2.38 $2.17 $2.10 $3.76 $3.19 $3.33 7%

1 See Use of Non-GAAP Financial Measures.

February 29, 2012 30 EDISON INTERNATIONAL®

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EMG Appendix

February 29, 2012 31 EDISON INTERNATIONAL®

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EMG Business Platform

December 31, 2011

Operating Platform1 MW %

Coal2 7,096 68

Natural Gas 1,269 12

Wind 1,861 18

Other 153 2

Total 10,379 100

Under Construction MW

Wind 120

Natural Gas3 479

Wind Development MW

Pipeline4 ~1,300

1 Natural gas includes oil-fired; other includes Doga in Turkey (144 MW) and Huntington biomass (9 MW) which are not shown.

2 Includes 858 MW to be shut down by 2014.

3 Deliveries under the power sales agreement are expected to commence in 2013.

4 Owned or under exclusive agreement.

964 479

19

141

133 120

190

461

244

167

144

240

5,172

305

1,884 67

55 40

February 29, 2012 32 EDISON INTERNATIONAL®

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EMG Coal Fleet Capacity Sales

December 31, 2011

Installed Unsold Capacity RPM Capacity Sold in Other Capacity Sales,

Capacity Capacity1 Sold2 Base Residual Auction Net of Purchases3 Aggregate

Price per Average Price Average Price

MW MW MW MW MW-day MW per MW-day per MW-day

January 1, 2012 to May 31, 2012

Midwest Generation 5,477 (555) 4,922 4,582 $110.00 340 $98.92 $109.23

Homer City5 1,884 (163) 1,721 1,771 $110.00 (50) $30.00 $112.32

June 1, 2012 to May 31, 2013

Midwest Generation 5,477 (773) 4,704 4,704 $16.46 — — $16.46

Homer City 1,884 (232) 1,652 1,736 $133.37 (84) $16.46 $139.31

June 1, 2013 to May 31, 2014

Midwest Generation 5,477 (827) 4,650 4,650 $27.73 — — $27.73

Homer City 1,884 (104) 1,780 1,780 $226.15 — — $221.034

June 1, 2014 to May 31, 2015

Midwest Generation 5,477 (852) 4,625 4,625 $125.99 — — $125.99

Homer City 1,884 (190) 1,694 1,694 $136.50 — — $136.50

1 Capacity not sold arises from: (1) capacity retained to meet forced outages under the RPM auction guidelines, and (2) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.

2 Excludes renewable energy projects capacity sold between the periods of January 1, 2011 through May 31, 2015 of 4 MW and 56 MW.

3 Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions, and other capacity transactions entered into to manage capacity risks.

4 Includes the impact of a 100 MW capacity swap transaction executed prior to the base residual auction at $135 per MW-day.

5 Excludes 172 MW of capacity for periods ranging from January 1, 2012 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

February 29, 2012 33 EDISON INTERNATIONAL®

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Midwest Generation (Illinois)

Operational Statistics

Q4 10 Q4 11 2010 2011

• Total Generation (GWh) 7,708 7,158 29,798 28,145

• Forced Outage Rate 4.5% 3.6% 6.2% 5.3%

• Capacity Factor 63.9% 62.8% 62.3% 62.2%

• Equivalent Availability 90.4% 91.7% 82.2% 82.9%

• Load Factor 70.7% 68.5% 75.8% 75.0%

5,172 MW4 – Six mid-merit facilities

Utilizes Powder River Basin (PRB) coal with new

multi-year rail contract beginning in 2012

All-in Average Realized Prices1,3

$47.88

$31.40

$16.48

Q4 10

$39.76

$22.45

$17.31

Q4 11

$48.94

$31.77

$17.17

2010

$45.50

$27.44

$18.06

2011

1,884 MW – Three base-load units

Utilizes Northern Appalachian (NAPP) coal

Coal sourced locally and delivered by truck

Average realized gross margin ($/MWh)2

Average realized fuel cost ($/MWh)3

1 Includes the price of energy, capacity, ancillary services, etc.

2 Average realized gross margin is equal to all-in average realized price less average fuel and emission costs.

3 See Other Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix.

4 Includes 858 MW to be shut down by 2014.

February 29, 2012 34 EDISON INTERNATIONAL®

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Homer City (Pennsylvania)

Operational Statistics

Q4 10 Q4 11 2010 2011

• Total Generation (GWh) 2,801 2,459 11,028 9,428

• Forced Outage Rate 3.8% 5.0% 10.8% 13.8%

• Capacity Factor 67.3% 59.1% 66.8% 57.1%

• Equivalent Availability 92.2% 87.9% 79.7% 75.8%

• Load Factor 73.0% 67.3% 83.8% 75.4%

All-in Average Realized Prices1,3

$59.25

$31.70

$27.55

Q4 10

$46.44

$16.53

$29.91

Q4 11

$59.42

$34.16

$25.26

2010

$55.26

$26.68

$28.58

2011

Average realized gross margin ($/MWh)2 Average realized fuel cost ($/MWh)3

Expect transfer of Homer City ownership and recording as discontinued operations

1 Includes the price of energy, capacity, ancillary services, etc.

2 Average realized gross margin is equal to all-in average realized price less average fuel and emission costs.

3 See Other Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix.

February 29, 2012 35 EDISON INTERNATIONAL®

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EMG 2006 Illinois CPS Agreement

2011

Completed 1 2012 2013 2014 2015 2016 2017 2018 2019 Emissions

Mercury

Fleet-wide average emission rate (lb/GWh) Construction timeline

NOx

Fleet-wide average emission rate (lb/mmbtu) Construction timeline

SO2

Fleet-wide average emission rate (lb/mmbtu)

ACI $45 million

SNCR $105 million

0.0074 or 86%2

0.17

0.43

US EPA MATS Deadline

Waukegan 7

Will County 3

0.008 or 90% reduction

Cost included in SO2 spend

0.11

Waukegan 7

0.44 0.41 Waukegan 8 0.28

0.195

0.15

0.13

Joliet, Powerton, Will County 0.11

Up to $628 million for large units3

Construction timeline

Fleet-wide requirement Unit-specific requirement

1 Based on tests administered closest to year ended December 31, 2011, and submitted to Illinois EPA for compliance.

2 Actual mercury requirement for 2011 under the CPS was 5 lb/MMacf ACI injection, which has been met. Percent reduction requirement is based on mercury concentration in coal before and after treatment system. Reduction is across all units, including Waukegan 7 and Will County 3, which will require particulate removal upgrades to meet fleet-wide emission and unit-specific requirements. Midwest Generation believes that currently installed ACI and particulate removal equipment is sufficient to achieve or exceed the requirements outlined in the final MATS Rule.

3 The estimated cost of retrofitting Joliet Unit 6, if made, would be approximately $75 million, while the estimated cost of retrofitting the Waukegan Station, if made, would be approximately $160 million. No decisions have been made to retrofit particular units.

February 29, 2012 36 EDISON INTERNATIONAL®

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EMG Debt Covenant Status

EME Credit Obligations1 12/31/10 3/31/11 6/30/11 9/30/11 12/31/11

Midwest Generation Credit Facility

Debt to Capitalization Ratio 0.15 0.14 0.14 0.13 0.15

Covenant threshold (less than or equal to) 0.60 0.60 0.60 0.60 0.60

Non-Recourse Homer City Obligations

Homer City Lease Agreement

Senior Rent Service Coverage Ratio2,3 2.51 1.87 1.75 1.64 1.18

Covenant Threshold (greater than) 1.70 1.70 1.70 1.70 1.70

1 E credit facility terminated in February 2012.

2 A Senior Rent Coverage Ratio below the 1.7x threshold is not an event of default under the Homer City Lease Agreement. See “Management’s Overview – Homer City Lease” in EME annual report on Form 10-K for the year ended December 31, 2011.

3 Homer City believes it will not meet the covenant requirements of its sale leaseback documents relating to the payment of equity rent at April 1, 2012.

February 29, 2012 37 EDISON INTERNATIONAL®

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EMG Comparative Operating Statistics

Q4 10 Q4 11 Variance % 2010 2011 Variance %

Midwest Generation

Generation (in GWh) 7,708 7,158 (550) 29,798 28,145 (1,653)

Performance

Equivalent availability 90.4% 91.7% 1.3% 82.2% 82.9% 0.7%

Forced outage rate 4.5% 3.6% (0.9)% 6.2% 5.3% (0.9)%

Pricing Information

Average realized energy price ($/MWh)

Energy only contracts $37.63 $32.84 $(4.79) (13)% $40.12 $36.83 $(3.29) (8)%

Average cost of fuel ($/MWh) $16.48 $17.31 $0.83 5% $17.17 $18.06 $0.89 5%

Flat energy price – NI Hub ($/MWh) $27.39 $26.92 $(0.47) (2)% $33.12 $33.21 $0.09 0%

Homer City

Generation (in GWh) 2,801 2,459 (342) (12)% 11,028 9,428 (1,600) (15)%

Performance

Equivalent availability 92.2% 87.9% (4.30)% 79.7% 75.8% (3.9)%

Forced outage rate 3.8% 5.0% 1.20% 10.8% 13.8% 3.0%

Pricing Information

Average realized energy price ($/MWh) $49.13 $39.70 $(9.43) (19)% $49.04 $46.36 $(2.68) (5)%

Average cost of fuel ($/MWh) $27.55 $29.91 $(2.36) (9)% $25.26 $28.58 $3.32 13%

Flat energy price – PJM West Hub ($/MWh) $43.51 $35.91 $(7.60) (17)% $46.56 $43.57 $(2.99) (6)%

Flat energy price – HC Busbar ($/MWh) $37.35 $33.65 $(3.70) (10)% $39.18 $39.58 $0.40 1%

Basis (PJM West Hub – HC Busbar) $6.16 $2.26 $(3.90) $7.38 $3.99 $(3.39)

February 29, 2012 38 EDISON INTERNATIONAL®

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EMG – Adjusted EBITDA

December 31, 2011

($ millions)

Reconciliation to Earnings1 Q4 0910 Q4 1011 2010 2011

Earnings $10 $(1,071) $224 $(1,089)

Addback (Deduct):

Discontinued operations — — (4) 3

Income from continuing operations 10 (1,071) 220 (1,086)

Interest expense 65 82 264 324

Interest income — — (9) (1)

Income taxes (benefits) (14) (761) (36) (863)

Depreciation and amortization 68 81 249 310

EBITDA2 129 (1,669) 688 (1,316)

Production tax credits 17 19 62 66

Addback:

Asset impairments and other 41 1,753 48 1,760

Adjusted EBITDA $187 $103 $798 $510

Due to SCE pending regulatory and financial decisions impacting 2012 earnings, 2012 guidance will not be provided at this time

1 Earnings refer to net income attributable to Edison Mission Group.

2 See Use of Non-GAAP Financial Measures.

February 29, 2012 39 EDISON INTERNATIONAL®

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EMG Other Non-GAAP Reconciliations

($ millions)

Reconciliation of Midwest Generation and Homer City Operating Revenues and Fuel Costs to All-in Average Realized Price/MWh and Average Realized Fuel Cost/MWh

Midwest Generation Homer City

Q4 10 Q4 11 2010 2011 Q4 10 Q4 11 2010 2011

Generation (GWh) 7,708 7,158 29,798 28,145 2,801 2,459 11,028 9,428

Operating revenues $375 $289 $1,479 $1,286 $159 $117 $636 $527

Less: Unrealized (gains) losses (5) (4) 6 (3) 7 (2) 20 (5)

Other revenues (1) — (27) (2) — (3) — (2)

Realized revenues $369 $285 $1,458 $1,281 $166 $112 $656 $520

All-in average realized price/MWh $47.88 $39.76 $48.94 $45.50 $59.25 $46.44 $59.42 $55.26

Fuel costs $129 $122 $519 $512 $78 $73 $279 $269

Add back: Unrealized gains (losses) (2) 2 (7) (4) — — — —

Realized fuel costs $127 $124 $512 $508 $78 $73 $279 $269

Average realized fuel cost/MWh $16.48 $17.31 $17.17 $18.06 $27.55 $29.91 $25.26 $28.58

Reconciliation of Midwest Generation and Homer City Operating Revenues to Segment Revenues and Fuel Costs

Operating revenues Q4 10 Q4 11 2010 2011

Midwest Generation $375 $289 $1,479 $1,286

Homer City 159 117 636 527

Renewable projects 44 66 137 221

Other revenues 10 27 171 146

Segment revenues as reported $588 $499 $2,423 $2,180

Fuel Costs

Midwest Generation $129 $122 $519 $512

Homer City 78 73 279 269

Other revenues — 6 11 18

Segment revenues as reported $207 $201 $809 $799

February 29, 2012 40 EDISON INTERNATIONAL®

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Use of Non-GAAP Financial Measures

Edison International’s earnings are prepared in accordance with generally accepted accounting principles used in the United States and represent the company’s earnings as reported to the Securities and Exchange Commission. Our management uses core earnings and EPS by principal operating subsidiary internally for financial planning and for analysis of performance. We also use core earnings and EPS by principal operating subsidiary when communicating with analysts and investors regarding our earnings results and outlook, to facilitate the company’s performance from period to period.

Core earnings is a Non-GAAP financial measure and may not be comparable to those of other companies. Core earnings and core earnings per share are defined as GAAP earnings and basic earnings per share excluding income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings. GAAP earnings refer to net income attributable to Edison International common shareholders or attributable to the common shareholders of each subsidiary. EPS by principal operating subsidiary is based on the principal operating subsidiaries’ net income attributable to the common shareholders of each subsidiary, respectively and Edison International’s weighted average shares respectively, International s outstanding common shares. The impact of participating securities (vested stock options that earn dividend equivalents that may participate in undistributed earnings with common stock) for each principal operating subsidiary is not material to each principal operating subsidiary’s EPS and is therefore reflected in the results of the Edison International holding company, which we refer to as EIX parent company and other.

EBITDA is defined as earnings before interest, income taxes, depreciation and amortization. Adjusted EBITDA includes production tax credits from EMG’s wind projects and excludes amounts from gain on the sale of assets, loss on early extinguishment of debt and leases, and impairment of assets and investments. Our management uses Adjusted EBITDA as an important financial measure for evaluating EMG.

The average realized energy price and average realized fuel cost is a non-GAAP performance measure since such statistical measures exclude unrealized gains or losses recorded as operating revenues and unrealized gains or losses recorded as fuel expenses. Management believes that the average realized energy price and average realized fuel cost is more meaningful for investors as it reflects the impact of hedge contracts at the time of actual generation in period-overperiod comparisons or as compared to real-time market prices.

A reconciliation of Non-GAAP information to GAAP information, including the impact of participating securities, is included either on the slide where the information appears or on another slide referenced in this presentation.

February 29, 2012 41 EDISON INTERNATIONAL®