Exhibit 99.2

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Fourth Quarter 2010 Financial Teleconference

February 28, 2011 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 2010 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.

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Fourth Quarter Earnings Summary

Q4 09 Q4 10 Variance

Core EPS1

SCE $0.51 $0.56 $0.05

EMG 0.13 0.10 (0.03)

EIX parent company (0.05) (0.08) (0.03)

and other

Core EPS $0.59 $0.58 $(0.01)

Non-Core Items

SCE $0.02 $— $(0.02)

EMG 0.04 (0.07) (0.11)

EIX parent company — — —

and other

Total Non-Core $0.06 $(0.07) $(0.13)

Basic EPS $0.65 $0.51 $(0.14)

Diluted EPS $0.65 $0.51 $(0.14)

Core Earnings Core EPS

($ millions)

$194 $190 $0.59 $0.58

Q4 09 Q4 10 Q4 09 Q4 10

GAAP Earnings Basic EPS

($ millions) $212 $0.65

$166 $0.51

Q4 09 Q4 10 Q4 09 Q4 10

1 See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. The impact of participating securities is included in EIX parent company and other and was zero per share for the quarter ended December 31, 2010 and zero per share for the quarter ended December 31, 2009.

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SCE Fourth Quarter Highlights

EPS Q4 09 Q4 10 Variance

Core1 $0.51 $0.56 $0.05

Non-Core Items 0.02 — (0.02)

Basic EPS

attributable to SCE1 $0.53 $0.56 $0.03

Key Core Earnings Drivers

Higher operating revenue $0.15

• Rate base growth

• Operating revenue and other

Higher operating expense (0.05)

Higher depreciation (0.03)

Higher net financing costs (0.01)

Income taxes and other (0.01)

Total $0.05

Recent Developments

• In February 2011, the FERC approved a settlement agreement on SCE’s 2010 FERC rate case that provides a FERC retail base revenue requirement of $490 million

• 50% bonus depreciation extended for qualifying property through 2012 and new 100% bonus depreciation created for qualifying property placed in service between September 9, 2010 and

December 31, 2011

• In December 2010, the CPUC approved a $24 million ($0.04 per share) final payment for 2006 – 2008 performance under the energy efficiency incentive mechanism

• In November 2010, SCE filed its 2012 GRC application requesting a 2012 base rate revenue requirement of $6.3 billion

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.

February 28, 2011 3 EDISON INTERNATIONAL®

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EMG Fourth Quarter Highlights

EPS Q4 09 Q4 10 Variance

Core1 $0.13 $0.10 $(0.03)

Non-Core Items 0.04 (0.07) (0.11)

Basic EPS

attributable to EMG1 $0.17 $0.03 $(0.14)

Key Core Earnings Drivers

Merchant coal2

Midwest Generation $0.04

Homer City (0.04)

EMMT - trading (0.01)

Natural gas projects (0.01)

Taxes and other (0.01)

Total $(0.03)

Recent Developments

• Received Trona permits from IL EPA for Powerton Units 5 & 6 (February 2011) and Waukegan Unit

7 (November 2010)

• Wind projects began commercial operations

• Big Sky (240 MW; IL) in February 2011

• Laredo Ridge (80 MW; NE) in February 2011

• Cedro Hill (150 MW; TX) in December 2010

• Completed High Lonesome term financing of $75 million in November 2010

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 impact of unrealized gains of $0.03 per share in 2009 and unrealized losses of $0.01 per share in 2010.

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Full-Year Earnings Summary

2009 2010 Variance

Core EPS1

SCE $2.68 $3.01 $0.33

EMG2 0.68 0.59 (0.09)

EIX parent company (0.11) (0.12) (0.01)

and other

Core EPS $3.25 $3.48 $0.23

Non-Core Items

SCE $1.08 $0.18 $(0.90)

EMG(1.89) 0.10 1.99

EIX parent company 0.15 0.08 (0.07)

and other

Total Non-Core $(0.66) $0.36 $1.02

Basic EPS $2.59 $3.84 $1.25

Diluted EPS $2.58 $3.82 $1.24

Core Earnings Core EPS

($ millions) $1,140 $3.48 $1,064 $3.25

2009 2010 2009 2010

GAAP Earnings Basic EPS

($ millions) $1,256 $3.84

$849 $2.59

2009 2010 2009 2010

1 See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. The impact of participating securities is included in EIX parent company and other and was $(0.01) per share for the year-ended December 31, 2010 and $(0.01) per share for the year-ended December 31, 2009.

2 Includes impact of unrealized gains of $0.11 per share in 2009 and unrealized losses of $0.06 per share in 2010.

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SCE Historical Rate Base and Earnings Growth

($ billions)

2005 – 2010 CAGR

$15.5

Rate Base 10% $14.1 Core Earnings1 11% $12.6

$11.7

$10.8

$9.8

2005 2006 2007 2008 2009 2010

Core $1.82 $1.89 $2.07 $2.25 $2.68 $3.01

Earnings1

1 See SCE Core EPS Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix.

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SCE Capital Expenditures Forecast

($ billions)

$4.8

$4.4 $4.3

$4.0

$3.8

2010 2011 2012 2013 2014 Total

Forecast $4.4 $4.8 $4.3 $4.0 $17.5 Range1 $3.9 $4.3 $3.8 $3.6 $15.6

Forecast

By Classification

$%

Solar Photovoltaic 0.4 2

Edison SmartConnect™ 0.7 4

Generation 2.3 13

Transmission 5.0 29

Distribution 9.1 52

Total 17.5 100

By Proceeding%

2009 CPUC Rate Case 14

2012 CPUC Rate Case 51

Other CPUC 6

FERC Cases 29

Total 100

1 Currently forecasted 2011-2014 FERC and CPUC capital spending, subject to timely receipt of permitting, licensing and regulatory approvals. Forecast range reflects a 10.5% variability to annual expenditure levels related to execution risk, scope change, delays, regulatory constraints and other contingencies. 10.5% variability based on average level of actual variability experienced in 2009 and 2010.

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Bonus Depreciation Overview

Sept 8, 2010

50% 100% 100% 50% 2010 2011 2012

Property acquired after 2007 and before 9/9/2010

Self-constructed property started after 2007 but before 9/9/2010 and completed prior to 1/1/2013

Property acquired after 9/8/2010 and before 12/31/2011 Self-constructed property started after 9/8/2010 and completed before year end 2011

Property acquired during 2012

Self-constructed property completed during 2012

Legislation passed in 2010 extended bonus depreciation through 2012

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Summary of Bonus Depreciation Impact

• Bonus depreciation expected to have the following impacts on Edison International

Results in an EIX consolidated net operating loss for federal income tax purposes for 2010 and 2011

Increases deferred taxes and reduces SCE’s rate base and revenue requirement

Provides additional cash flow benefits during 2011 to SCE of approximately $550 million

Delays tax allocation payments to EMG until tax benefits are utilized by EIX on a consolidated basis which may be for several years

Eliminates income tax benefits from the domestic production activities deduction (also known as Section 199 deductions) of $16 million in 2011. The negative impact on 2010 net income was $15 million from the recapture of the 2008 Section 199 deductions taken in prior years resulting from the carry back of net operating losses

February 28, 2011 9 EDISON INTERNATIONAL®

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SCE Rate Base Forecast

($ billions)

2011 – 2014 CAGR1,2

Rate Base 8-11% $24.7

$22.6

$20.8

$18.2

$21.2 $22.8

$18.0 $19.9

2011 2012 2013 2014

1 Forecast range includes: (1) 2009 CPUC GRC & 2010 FERC Decisions; (2) forecasted 2011-2014 FERC and 2012-2014 CPUC rate base, subject to timely receipt of permitting, licensing and regulatory approvals; (3) FERC construction work in progress forecast; (4) impact of the Economic Stimulus Act of 2009; (5) CPUC approved solar rooftop program; adjusted for pending PFM; (6) estimated impact of bonus depreciation provision as part of The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Acts of 2010. Rate Base forecast range reflects capital expenditure forecast range from SCE Capital Expenditures Forecast.

2 Rate Base related earnings per share growth rate may vary compared to rate base growth depending on the level and type of financing and other activities.

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Midwest Generation (Illinois)

Operational Statistics

Q4 09 Q4 10 2009 2010

• Total Generation (GWh) 8,588 7,708 30,310 29,798

• Forced Outage Rate 5.4% 4.5% 5.8% 6.2%

• Capacity Factor 71.2% 63.9% 63.3% 62.3%

• Equivalent Availability 89.8% 90.4% 85.3% 82.2%

• Load Factor 79.3% 70.7% 74.2% 75.8%

All-in Average Realized Prices1,3

$44.54 $47.88 $47.97 $48.94

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

5,172 MW – Six mid-merit facilities Utilizes Powder River Basin (PRB) coal Rail under contract through 2011

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.

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Homer City (Pennsylvania)

Operational Statistics

Q4 09 Q4 10 2009 2010

Total Generation (GWh) 2,769 2,801 11,446 11,028

Forced Outage Rate 14.8% 3.8% 9.4% 10.8%

Capacity Factor 66.4% 67.3% 69.2% 66.8%

Equivalent Availability 78.6% 92.2% 84.7% 79.7%

Load Factor 84.7% 73.0% 81.7% 83.8%

All-in Average Realized Prices1,3

$58.86 $59.25 $59.42

$56.66

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

1,884 MW – Three base-load units Utilizes Northern Appalachian (NAPP) coal Coal largely sourced locally and delivered by truck Homer City Units 1 and 2 offline until Q2 2011

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 28, 2011 12 EDISON INTERNATIONAL®

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EMG Hedge Program Status

December 31, 2010

2011 2012 2013

Midwest Generation

Total estimated GWh hedged (NI & AEP/Dayton Hubs) 10,870 3,358 —

Average price ($/MWh)1 $37.75 $38.11 —

Coal under contract (millions of tons) 15.9 9.8 —

Homer City

Total estimated GWh hedged (West Hub)2,3 2,540 1,370 —

Average price ($/MWh)1,3 $55.36 $51.68 —

Coal under contract (millions of tons) 4.6 1.8 0.5

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 PJM West Hub and to a lesser extent at other trading locations. Years 2011 and 2012 include 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.

3 The average price/MWh includes 72 to 84 MW for periods ranging from January 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

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EMG Capital Expenditures

December 31, 2010

($ millions)

2011 2012 2013

Midwest Generation

Plant capital expenditures $34 $23 $29

Environmental expenditures1 151 132 198

Homer City

Plant capital expenditures 18 25 16

Environmental expenditures — — —

Renewable Energy Projects

Capital & construction 189 — —

Turbine commitments 90 — —

Other capital expenditures 21 19 17

Total $503 $199 $260

1 Midwest Generation plants’ environmental expenditures include $109 million for expenditures in 2011 related to SNCR equipment and $372 million for expenditures in 2011 to 2013 to begin to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with the CPS requirements for SO2 emissions. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply remain subject to conditions applicable at the time decisions are required or made. EME’s use of less expensive dry scrubbing equipment with sodium-based absorbents to meet CPS requirements may be impacted by the content of forthcoming regulations expected to be proposed by the US EPA related to HAPs. If the HAPs regulations issued by the US EPA are not consistent with EME’s less costly environmental compliance plan.

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EMG Wind Energy Business

December 31, 2010

Portfolio & Development Pipeline1

1,335 MW in service (25 projects) 480 MW under construction (4 projects)

55 MW in construction pending (1 project)

3,600 MW in development pipeline (27 projects)

Wind Project Debt

• 949 MW financed

• 866 MW not financed

Recent Activities

• November 2010, completed $75 million debt financing for High Lonesome

• December 2010, Cedro Hill began commercial operation

• February 2011, Laredo Ridge began commercial operation

• February 2011, Big Sky began commercial operation

Wind Turbine Commitments/Inventory1

• 75 MW available for new projects at December 31, 2010

Estimated Capital Expenditures to Complete Wind Projects at December 31, 2010 ($ millions)1

Investment

Prior to

MW Spend Complete Total

Projects under construction/pending construction 535 $1,000 $183 $1,183

Projects in operation 6 6

Turbine commitments/inventory2 75 27 90 117

Total 610 $1,027 $279 $1,306

1 Data as of December 31, 2010 adjusted for impact of MHI settlement dispute. Projects reflect EMG ownership share. Development pipeline includes projects owned or under exclusive agreements.

2 Amounts exclude balance of plant costs for 75 MW available for new projects, which would be an additional $60 million to $80 million based on typical project costs.

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Funding for 2010-11 Wind Expenditures

($ millions)

$20 $242

$394 $48 million Bank/Vendor $346 million Treasury Grants2

$1,125 $624

$551 $459 million Bank/Vendor $92 million Treasury Grants

$279

12/31/09 New Mitsubishi 2010 2011 Sources Sources Estimated Projects3 Turbines1 Spend4 Remaining Received Pending Spend Spend (12/31/10)

1 EME’s turbine supply agreement with Mitsubishi Power Systems Americas, Inc. was adjusted for the impact of the settlement agreement.

2 Estimate based on estimated construction costs and anticipated commercial operation dates. Grants anticipated are reduced by the Laredo Ridge bridge loan where repayment is due when grant funds are received.

3 Community Wind North and Pinnacle projects were moved to construction and construction pending. Lower than anticipated costs for new projects.

4 Including accruals.

February 28, 2011 16 EDISON INTERNATIONAL®

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2011 Earnings Guidance

2011

2010 Earnings Guidance

Results as of 2/28/11

Low Mid High

EIX core earnings per share1 $3.48 $2.60 $2.75 $2.90

Non-core items

SCE – tax impact of health care

legislation (0.12) —

Tax settlement 0.54 —

EMG – write-off of capitalized costs and other(0.06) —

Total non-core items 0.36 —

EIX basic earnings per share $3.84 $2.60 $2.75 $2.90

Actual/Midpoint of core guidance

by key business element

SCE $3.01 $3.08

EMG 0.59 (0.19)

EIX parent company and other1 (0.12) (0.14)

Total $3.48 $2.75

Assumptions

Southern California Edison

• Average rate base $18.2 billion

• Approved capital structure

48% equity, 11.5% ROE

• No energy efficiency earnings included in guidance

Edison Mission Group

• Forward hedge position and prices as of January 31, 2011

• EMMT pre-tax trading margin of $75-$125 million

Other

• Normal operating and weather conditions

• No changes in GAAP accounting

• Excludes future discontinued operations and other non-core items

1 See Use of Non-GAAP Financial Measures in Appendix. The actual impact in 2010 of participating securities is included in EIX parent company and other.

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2011 Core Guidance - Midpoint

Reconciliation of Core Earnings Per Share Guidance – 2010 Results to 2011

EIX Parent Co. SCE +0.07 EMG (0.78) (0.02)

0.33 (0.71)

$3.48 (0.04)

(0.22)

(0.01) (0.06) (0.02)

$2.75

2010 2010 2010 Rate Base Generation EMMT Corporate EIX Parent 2011 Results Energy Positive Growth Fleet Expense, Company Guidance1 Efficiency Variances Taxes & Other

1 See Use of Non-GAAP Financial Measures in Appendix.

February 28, 2011 18 EDISON INTERNATIONAL®

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Appendix

February 28, 2011 19 EDISON INTERNATIONAL®

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Updates Since Our Last Presentation

• Q4 10 results and standard information

• SCE Capital Expenditures, Rate Base and Core Earnings (pp. 6, 7 & 10)

• Bonus Depreciation (pp. 8 & 9)

• 2011 Earnings Guidance and Forward Curves (pp. 17, 18 & 30)

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Liquidity Profile

December 31, 2010

($ 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 $2,870 $981 $— $1,407

Cash & short-term investments3 264 1,075 24 33

Available Liquidity $3,134 $2,056 $24 $1,440

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

2 Excludes the unused and/or unfunded commitments of subsidiaries of Lehman Brothers Holdings of $36 million for EMG. In June 2009, SCE and EIX amended their credit facilities to remove a subsidiary of Lehman Brothers Holding as a lender.

3 EME had corporate cash of $615 million at December 31, 2010. Corporate cash is defined as cash and cash equivalents of EME and cash and cash equivalents of subsidiaries that do not have third-party dividend restrictions.

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Debt Maturity Profiles

December 31, 2010

($ millions)

Debt Profile 2011 2012 2013 2014

Short- and Long-Term Debt Maturities

SCE $— $— $— $1,050

EMG1 144 58 566 260

EIX — — — —

Expiration of Credit Facilities

SCE2 $— $— $2,894 $—

EME — 600 — —

MWG — 500 — —

EIX2 — — 1,426 —

1 Laredo Ridge construction loan $20 million, included in 2011 convert to long-term financing subject to meeting specific provisions.

2 $98 million of SCE commitments and $47 million of the EIX commitments mature in 2012.

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SCE Appendix

February 28, 2011 23 EDISON INTERNATIONAL®

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SCE Cost of Capital Mechanism

Moody’s Baa Utility Index - 12-month moving average and spot rate through 01/31/111

10

Spot rate1

9

8

Moving Average for (%) measurement period

7 Starting Index=6.22% Rate 6

5

4

Sep-07 Dec-07 Mar-08 Jun-08 Sep-08 Dec-08 Mar-09 Jun-09 Sep-09 Dec-09 Mar-10 Jun-10 Sep-10 Dec-10

• In 2008 In , CPUC 2009, approved the CPUC multi extended -year cost the of capital mechanism through 2010 with authorized return on equity (ROE) at 11.5%

mechanism through 2012

• Cost of Capital mechanism allows for indexed changes in SCE’s authorized ROE

Triggers 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

• As of January 2011, index averaged 5.89%

At September 2010, index did not exceed 7.26% and was not below 5.26% to trigger a ROE change

SCE’s authorized ROE for 2011 will continue at 11.5%

1 Spot rate is daily yield on Moody’s Baa Utility Bond Index and the Measurement Period Average is the average of the monthly yields on the index beginning with the first month of the measurement period.

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SCE 2012 CPUC GRC Projected Schedule

• 2012 GRC application forecast filed in late November 2010

• Final Decision expected in December 2011

Estimated 2010 2011

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

July 19 November 23 Opening and Final

Notice of GRC Application Reply Briefs Decision

Intent Filed

Evidentiary ALJ Proposed Hearings Decision

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SCE Regulatory Key Events

Case Date of Status Next Number Filing Milestone

September 2009, FERC accepted SCE’s

2010 FERC ER09-1534 proposed 2010 base transmission rates FERC approved a settlement 07/31/09 Rate Case ER11-2405 and made them effective March 1, 2010, agreement in February 2011 subject to refund

Special Use Permit expected

Tehachapi October 2010, Federal Record of Decision

A. 07-06-031 06/28/07 from the U. S. Forest Service Transmission (ROD) obtained from U.S. Forest Service in Q1 2011

Federal ROD from the Bureau DCR August 2010, SCE obtained final approval A. 05-04-015 04/11/05 of Land Management (BLM) Transmission from the CPUC to commence construction expected in Q2 2011

Eldorado-Ivanpah Federal ROD from the BLM and December 2010, SCE obtained CPCN

Transmission Final Approval from Nevada PUC A. 09-05-027 05/28/09 from the CPUC, approving SCE’s project expected in Q2 2011

Alberhill Permit to Construct (PTC) filed in

September 2009 and converted to a Draft EIR is expected from the A. 09-09-022 09/30/09 CPCN filing in March 2010 CPUC in Q4 2011

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SCE Results of Operations

($ millions)

Twelve Months Ended Dec 30, 2009 Twelve Months Ended Dec 31, 2010

Utility Utility

Utility Cost- Utility Cost-

Earning Recovery Total Earning Recovery Total

Activities Activities Consolidated Activities Activities Consolidated

Operating Revenue $5,303 $4,662 $9,965 $5,606 $4,377 $9,983

Fuel and purchased power — 3,472 3,472 — 3,293 3,293

Operation and maintenance 2,111 1,043 3,154 2,271 1,020 3,291

Depreciation, decommissioning and amortization 1,124 54 1,178 1,213 60 1,273

Property and other taxes 244 — 244 260 3 263

Gain on sale of assets — (1) (1) — (1) (1)

Total operating expenses 3,479 4,568 8,047 3,744 4,375 8,119

Operating income 1,824 94 1,918 1,862 2 1,864

Net interest expense and other (298) — (298) (330) (2) (332)

Income before income taxes 1,526 94 1,620 1,532 — 1,532

Income tax expense 249 — 249 440 — 440

Net income 1,277 94 1,371 1,092 — 1,092

Net income attributable to noncontrolling interest — 94 94 — — —

Dividends on preferred and preference stock not

subject to mandatory redemption 51 — 51 52 — 52

Net income available for common stock $1,226 $— $1,226 $1,040 $— $1,040

Core Earnings $874 $984

Non-Core Earnings1:

Global settlement 306 95

Tax impact of health care legislation — (39)

Regulatory items 46 —

Total SCE GAAP Earnings $1,226 $1,040

1 See Use of Non-GAAP Financial Measures.

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EMG Appendix

February 28, 2011 28 EDISON INTERNATIONAL®

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EMG Business Platform

December 31, 2010

145

141

1,884 67

53 145

5,172

305 40 19 964

190 114

461

Operating Platform1 MW%

Coal 7,096 72

Natural Gas 1,269 13

Wind 1,335 14

Other 153 1

Total 9,853 100

Wind Development Pipeline MW

Pipeline2 ~3,600

Under Construction and Pending 535

Thermal Pipeline

Natural Gas3 479

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

2 Owned or under exclusive agreement.

3 Deliveries under the power sales agreement are expected to commence in 2013. Construction will be unable to begin until the legal challenges to the Priority Reserve emission credits are resolved or another source of credits for the project is identified.

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2011 Forward Curves

$55 PJM West Flat

1/31/2011 $50 $45 /MWh $40 $ $35 $30 $25 $20

Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec

Balance of Year (Feb – Dec)

1/31/2011

-On peak $50.68

Off-peak $38.13

Flat $43.99

1/31/2011

On-peak

$38.37

Off-peak

$23.10

Flat

$30.23

$55 NiHub Flat

1/31/2011 $50

$45

/MWh $40 $ $35

$30

$25

$20

Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec

Source: Broker quotes

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EMG Capacity Sales

December 31, 2010

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-day1 MW per MW-day per MW-day

January 1, 2011 to May 31, 2011

Midwest Generation 5,477 (548) 4,929 4,929 $174.29 — — $174.29

Homer City 1,884 (261) 1,623 1,813 $174.29 (190) $53.95 $188.38

June 1, 2011 to May 31, 2012

Midwest Generation 5,477 (495) 4,982 4,582 $110.00 400 $85.00 $107.99

Homer City 1,884 (113) 1,771 1,771 $110.00 — — $110.00

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

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 72 to 84 MW of capacity for periods ranging from January 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

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.

February 28, 2011 31 EDISON INTERNATIONAL®

Leading the Way in Electricity SM

EMG Debt Covenant Status

Status at

12/31/09 3/31/10 6/30/10 9/30/10 12/31/10

EME Credit Facility

Funds Flow Available for Interest Ratio 1.72 1.99 1.72 1.71 2.07

Covenant threshold (not less than) 1.20 1.20 1.20 1.20 1.20

Corporate-Debt-to-Capital Ratio 0.54 0.53 0.53 0.52 0.52

Covenant threshold (not more than) 0.75 0.75 0.75 0.75 0.75

Midwest Generation Credit Facility

Debt to Capitalization Ratio 0.18 0.16 0.16 0.15 0.15

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

Homer City Lease Agreement

Senior Rent Service Coverage Ratio 2.96 3.10 2.53 2.81 2.51

Covenant Threshold (greater than) 1.70 1.70 1.70 1.70 1.70

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EMG – Illinois Compliance Agreement Timeline

Compliance Deadlines and Estimated Construction Timelines1

Completed 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Mercury ACI ($45 million) Waukegan 7 Will County 3 Compliance deadlines 0.008 or 90% reduction2 and rates (lb/GWh) Construction timelines

(Cost included in SO2 spend) NOx 0.11

Compliance deadlines and rates (lb/mmbtu)

Construction timelines $137 million SO2

Compliance deadlines Waukegan Waukegan 7 8 Crawford 7,

0.44 Joliet, and rates (lb/mmbtu) 0.41 Fisk Powerton,

0.28

0.195 Crawford 8 Will

0.15 County

0.13

0.11

Construction timelines Up to $1.2 billion

NOx SO2 Mercury

Unit-specific technology requirements

Fleet-wide average emission rate requirements Capital spending period

1 Simplified summary of key compliance deadlines and estimated construction timelines. Unit-specific deadlines as of December 31 of the calendar year shown. SO2 unit-specific deadlines apply to Unit 19 at Fisk, Units 7 and 8 at Waukegan, Units 7 and 8 at Crawford, Units 7 and 8 at Joliet, Units 5 and 6 at Powerton and Units 3 and 4 at Will County.

2 Requirement relates to individual units (for example, Powerton Units 5 and 6 must meet individually).

February 28, 2011 33 EDISON INTERNATIONAL®

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EMG Comparative Operating Statistics

Fav./(Unfav.) Fav./(Unfav.)

Q4 09 Q4 10 Variance % 2009 2010 Variance %

Midwest Generation

Generation (in GWh)

Energy only contracts 8,588 7,708 28,977 29,798

Load requirement services contracts — — 1,333 —

Total 8,588 7,708 (880) -10% 30,310 29,798 (512) -2%

Performance

Equivalent availability 89.8% 90.4% 0.6% 85.3% 82.2% -3.1%

Forced outage rate 5.4% 4.5% 0.9% 5.8% 6.2% -0.4%

Pricing Information

Average realized energy price ($/MWh)

Energy only contracts $38.94 $37.63 $(1.31) -3% $41.17 $40.12 $(1.05) -3%

Load requirement services contracts $— $— $— % $62.52 $— $(62.52) -100%

Average cost of fuel ($/MWh) $17.83 $16.48 $1.35 8% $18.54 $17.17 $1.37 7%

Flat energy price – NI Hub ($/MWh) $29.58 $27.24 $(2.34) -8% $28.86 $33.08 $4.22 15%

Homer City

Generation (in GWh) 2,769 2,801 32 1% 11,446 11,028 (418) -4%

Performance

Equivalent availability 78.6% 92.2% 13.6% 84.7% 79.7% -5%

Forced outage rate 14.8% 3.8% 11% 9.4% 10.8% -1.4%

Pricing Information

Average realized energy price ($/MWh) $48.20 $49.13 $0.93 2% $48.85 $49.04 $0.19 0%

Average cost of fuel ($/MWh) $21.41 $27.55 $(6.14) -29% $21.89 $25.26 $(3.37) -15%

Flat energy price – PJM West Hub ($/MWh) $37.28 $43.59 $6.31 17% $38.31 $45.88 $7.57 20%

Flat energy price – HC Busbar ($/MWh) $34.17 $37.99 $3.82 11% $34.91 $39.35 $4.44 13%

Basis (PJM West Hub – HC Busbar) $3.11 $5.60 $2.49 $3.40 $6.53 $3.13

February 28, 2011 34 EDISON INTERNATIONAL®

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EMG – Adjusted EBITDA

December 31, 2010

($ millions)

Reconciliation to Earnings1 Q4 09 Q4 10 2009 2010

Earnings $55 $10 $(395) $224

Addback (Deduct):

Discontinued operations 2 (1) 7 (4)

Income from continuing operations 57 9 (388) 220

Interest expense 74 65 306 264

Interest income (8) — (23) (9)

Income taxes (benefits) (21) (13) (284) (36)

Depreciation and amortization 62 68 240 249

EBITDA2 164 129 (149) 688

Production tax credits 16 17 56 62

Addback:

Lease termination & other — — 885 —

Adjusted EBITDA $184 $187 $796 $798

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

2 See Use of Non-GAAP Financial Measures for additional information on EBITDA and Adjusted EBITDA.

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Earnings Non-GAAP Reconciliations

($ millions)

Reconciliation of EIX Core Earnings to EIX GAAP Earnings

Earnings

Attributable to Edison International Q4 09 Q4 10 2009 2010

Core Earnings1

SCE $167 $181 $874 $984

EMG 42 34 222 192

EIX parent company and other (15) (25) (32) (36)

EIX Core Earnings 194 190 1,064 1,140

Non-core items

SCE – tax settlement — — 306 95

health care legislation — — — (39)

regulatory items 5 — 46 —

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

EMG – tax settlement2 14 — (610) 52

EIX – tax settlement — — 50 28

EMG – discontinued operations (1) — (7) 4

Total non-core items 18 (24) (215) 116

EIX GAAP Earnings $212 $166 $849 $1,256

1 See Use of Non-GAAP Financial Measures.

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

February 28, 2011 36 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

SCE Core Earnings Per Share1 $1.82 $1.89 $2.07 $2.25 $2.68 $3.01 11%

Non-core items

Tax settlement — — — 0.94 0.30

Health care legislation — — — — (0.12)

Regulatory and tax items 0.36 0.40 0.10 (0.15) 0.14 —

Generator settlement/refund incentive 0.04 0.09 — — — —

Total non-core items 0.40 0.49 0.10 (0.15) 1.08 0.18

SCE GAAP Earnings Per Share 42.22 $2.38 $2.17 $2.10 $3.76 $3.19 8%

1 See Use of Non-GAAP Financial Measures.

February 28, 2011 37 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 09 Q4 10 2009 2010 Q4 09 Q4 10 2009 2010

Generation (GWh) 8,588 7,708 30,310 29,798 2,769 2,801 11,446 11,028

Operating revenues $391 $375 $1,487 $1,479 $167 $159 $663 $636

Less: Unrealized (gains) losses (8) (5) (30) 6 (4) 7 (15) 20

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

Realized revenues $382 $369 $1,454 $1,458 $163 $166 $648 $656

All-in average realized price/MWh $44.54 $47.88 $47.97 $48.94 $58.86 $59.25 $56.66 $59.42

Fuel costs $150 $129 $547 $519 $59 $78 $251 $279

Add back: Unrealized gains (losses) 3 (2) 15 (7) — — — —

Realized fuel costs $153 $127 $562 $512 $59 $78 $251 $279

Average realized fuel cost/MWh $17.83 $16.48 $18.54 $17.17 $21.41 $27.55 $21.89 $25.26

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

Operating revenues Q4 09 Q4 10 2009 2010

Midwest Generation $391 $375 $1,487 $1,479

Homer City 167 159 663 636

Renewable projects 40 44 141 137

Other revenues 17 10 86 171

Segment revenues as reported $615 $588 $2,377 $2,423

Fuel Costs

Midwest Generation $150 $129 $547 $519

Homer City 59 78 251 279

Other revenues — — (2) 11

Segment revenues as reported $209 $207 $796 $809

February 28, 2011 38 EDISON INTERNATIONAL®

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Use of Non-GAAP Financial Measures

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

Core and core earnings earnings is a per Non share -GAAP are financial defined measure as GAAP and earnings may not and be basic comparable earnings to per those share of other excluding companies income . Core or loss earnings from representative discontinued operations of ongoing and earnings income . GAAP or loss earnings from significant refer to net discrete income items attributable that management to Edison does International not consider common shareholders based on the or principal attributable operating to the subsidiaries’ common shareholders net income attributable of each subsidiary to the . common EPS by principal shareholders operating of each subsidiary subsidiary, is securities respectively (vested , and Edison stock options International that earn ‘s weighted dividend average equivalents outstanding that may common participate shares in undistributed . The impact of earnings participating with common stock) reflected for in each the principal results of operating the Edison subsidiary International is not holding material company, to each principal which we operating refer to as subsidiary’s EIX parent EPS company and is and therefore other . production EBITDA is defined tax credits as earnings from EMG before ‘s wind interest, projects income and excludes taxes, depreciation amounts from and gain amortization on the sale . Adjusted of assets, EBITDA loss on includes early extinguishment as an important of financial debt and measure leases, for and evaluating impairment EMG of. assets and investments. Our management uses Adjusted EBITDA statistical The average measures realized exclude energy unrealized price and average gains or realized losses recorded fuel cost as is operating a non-GAAP revenues performance and unrealized measure gains since or such losses more recorded meaningful as fuel ex for penses investors . Mana asg it ement reflects believes the impact that the of hedge avera g contracts e realized at ener thegy time price of actual and avera generation ge realized in period fuel cost -over is- period comparisons or as compared to real-time market prices.

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

February 28, 2011 39 EDISON INTERNATIONAL®