Exhibit 99.2

Leading the Way in Electricity SM

Third Quarter 2008 Financial Teleconference

November 7, 2008

EDISON INTERNATIONAL®

Leading the Way in Electricity SM

Forward-Looking Statements

Statements contained in this presentation about future performance, including, without limitation, earnings, asset and rate base growth, load growth, capital investments, 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. Important factors that could cause different results are discussed under the headings “Risk Factors” and “Management’s Discussion and Analysis” in Edison International’s 2007 Form 10-K and other reports filed with the Securities and Exchange Commission and are available on our website: www.edisoninvestor.com. 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.

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Third Quarter Key Items

Core EPS up 4% to $1.46 per share1 due to SCE earnings gains

Increased balance sheet liquidity given turmoil in financial markets

Implemented capital preservation program at EMG

• 2008 core guidance reaffirmed near the middle of the range and GAAP guidance updated2

1 See Use of Non-GAAP Financial Measures in appendix. See Third Quarter Financial Results slide for reconciliation of core earnings to GAAP earnings. Core earnings is defined as GAAP earnings less discontinued operations and other non-core items.

2 See 2008 Earnings Guidance slide.

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Third Quarter Earnings Summary

GAAP Core1

Net Income Reported EPS Net Income EPS

($ millions) ($ millions)

$482 $461 $465 $439 $1.40 $1.46 $1.33 $1.41

3Q 07 3Q 08 3Q 07 3Q 08 3Q 07 3Q 08 3Q 07 3Q 08

1 GAAP earnings per share refers to basic earnings per share. See Third Quarter Financial Results slide for reconciliation of core earnings to GAAP earnings. Core earnings is defined as GAAP earnings less discontinued operations and other non-core items.

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Third Quarter Financial Results

Reconciliation of Core Earnings to GAAP Earnings Core Earnings Variances

SCE 0.07

Core Earnings 3Q 07 3Q 08 Variance Higher operating income and lower financing costs.

EMG

SCE $ 0.80 $ 0.87 $ 0.07 Homer City 0.07

Higher gross margin and SFAS 133 gains, partially offset by higher EMG 0.64 0.64 — plant operating costs.

EMMT2 0.01

Higher income from energy trading.

EIX parent company (0.03) (0.05) (0.02) Midwest Generation —

and other Higher gross margin from higher realized energy and capacity prices $ 1.41 $ 1.46 and SFAS 133 gains, offset by Lehman hedge contract charge and Core EPS1 $ 0.05 higher plant operating costs.

Corporate expense and other items (0.02)

Non-core Items Lower interest income and other.

Edison Capital (0.03)

Lower lease income and infrastructure fund performance.

SCE $ — $ (0.15) $ (0.15)

Income from other projects (0.03)

EMG (0.01) 0.02 0.03 EIX (0.02)

Higher insurance claims and higher net interest expense.

Total Non-Core $ (0.01) $ (0.13) $ (0.12) Non-Core Variances

SCE (0.15)

Basic EPS $ 1.40 $ 1.33 $ (0.07) 3Q 08: ($0.15) for performance-based ratemaking decision.

EMG 0.03

Diluted EPS $ 1.39 $ 1.33 $ (0.06) 3Q 07: ($0.01) from discontinued operations. 3Q 08: $0.02 from discontinued operations.

1 See Use of Non-GAAP Financial Measures in appendix. The impact of participating securities is included in EIX parent company and other, and was $(0.02) for each of the quarters ended September 30, 2007 and 2008.

2 EMMT overhead is included in corporate expense and other items.

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Year-to-Date Earnings Summary

GAAP Core1

Net Income Reported EPS Net Income EPS

($ millions) ($ millions)

$3.03 $3.18 $1,048 $3.04 $999 $1,003 $2.69 $887

YTD 07 YTD 08 YTD 07 YTD 08 YTD 07 YTD 08 YTD 07 YTD 08

1 GAAP earnings per share refers to basic earnings per share. See Year-to-Date Financial Results slide for reconciliation of core earnings to GAAP earnings. Core earnings is defined as GAAP earnings less discontinued operations and other non-core items.

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Year-to-Date Financial Results

Reconciliation of Core Earnings to GAAP Earnings Core Earnings Variances

SCE 0.11

Higher operating income, lower financing costs and lower income taxes.

Core Earnings YTD 07 YTD 08 Variance

EMG

SCE $ 1.70 $ 1.81 $ 0.11 Midwest Generation 0.22

Higher gross margin including SFAS 133 gains, higher realized energy and capacity prices, and lower interest expense, offset by Lehman EMG 1.41 1.47 0.06 hedge contract charge and higher plant operating costs.

EMMT2 0.06

Higher income from energy trading.

EIX parent company (0.07) (0.10) (0.03)

Edison Capital (0.02)

and other Higher 2007 infrastructure fund performance, offset by gain on sale

Core EPS1 $ 3.04 $ 3.18 $ 0.14 of Beaver Valley lease.

Income from other projects (0.03)

Non-core Items Homer City (0.04)

Lower gross margin from lower generation, and higher plant operations.

SCE $ 0.10 $ (0.15) $ (0.25) Corporate expense and other items (0.13)

Lower interest income, higher G&A related to growth initiatives and other.

EMG (0.45) — 0.45 EIX (0.03)

Higher insurance claims, net interest expense, and taxes.

Non-Core Variances

Total Non-Core $ (0.35) $ (0.15) $ 0.20

SCE (0.25)

YTD 07: $0.10 for resolution of the tax treatment of certain Basic EPS $ 2.69 $ 3.03 $ 0.34 environmental remediation costs.

YTD 08: ($0.15) for performance-based ratemaking decision.

EMG 0.45

Diluted EPS $ 2.67 $ 3.02 $ 0.35 YTD 07: ($0.45) from early debt extinguishment charges.

1 See Use of Non-GAAP Financial Measures in appendix. The impact of participating securities is included in EIX parent company and other, and was $(0.04) per share for 2008 and $(0.03) per share for 2007.

2 EMMT overhead is included in Corporate expense and other items.

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Midwest Generation – Operating Performance

Operating Statistics 3Q 07 3Q 08 YTD 07 YTD 08

Total Generation (GWh) 8,413 8,413 23,169 23,616 Equivalent Availability 86.6 % 87.4 % 78.7 % 80.9 % Capacity Factor 67.9 % 69.7 % 63.0 % 65.8 % Load Factor 78.4 % 79.8 % 80.1 % 81.3 % Forced Outage Rate 8.6 % 8.3 % 7.0 % 9.0 %

All-in Average Realized Prices1

$68 $60.29 $58.05 $54.08 $53.30

$51 All-in average $43.38 realized price increased

$42.54

$/MWh $34 $40.20 $39.90 9% YTD compared to prior year

$17 $13.88 $16.91 $13.40 $15.51 $0 3Q 07 3Q 08 YTD 07 YTD 08

Average realized gross margin ($/MWh)2 Average fuel and emission costs ($/MWh)

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

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

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Homer City – Operating Performance

Operating Statistics 3Q 07 3Q 08 YTD 07 YTD 08 3Q 07 vs. 3Q 08

Total Generation (GWh) 3,759 3,354 10,211 8,796 Improved plant

Equivalent Availability 96.5 % 93.6 % 89.0 % 80.9 % performance relative to Capacity Factor 90.2 % 80.5 % 82.6 % 70.9 % first half of 2008

Lower off-peak dispatch

Load Factor 93.4 % 86.0 % 92.8 % 87.6 %

YTD 08 performance

Forced Outage Rate 3.5 % 4.0 % 3.7 % 8.1 % affected by elevated

forced outages

All-in Average Realized Prices1

$68 $66.19 $61.44 $56.48 $53.65 $51

$42.89 All-in average

$38.42

$31.17 $34.48 realized price increased

$/MWh $34

9% YTD compared to prior year

$17 $22.48 $23.30 $22.00 $23.02 $0 3Q 07 3Q 08 YTD 07 YTD 08

Average realized gross margin ($/MWh)2 Average fuel and emission costs ($/MWh)

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

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

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EMG Hedge Program Status

Status at September 30, 2008

Remainder of

2008 2009 2010 2011 Midwest Generation

Energy Only Contracts 1

Northern Illinois & AEP/Dayton Hubs (GWh) 2,765 9,945 6,534 611 Average price ($/MWh) $61.35 $65.42 $68.62 $76.40

Load Requirement Services Contracts

Northern Illinois Hub (Estimated GWh)2 1,015 1,571 — — Average price NiHub ($/MWh)3 $63.65 $63.65 — — Total estimated GWh hedged 3,780 11,516 6,534 611

Coal under contract (in millions of tons) 5.6 12.8 11.7 —

Homer City

Total estimated GWh hedged 1,708 4,096 2,654 — Average price ($/MWh)4 $60.90 $82.84 $90.52 —

Coal under contract (in millions of tons)5 1.9 4.5 0.4 0.3

1 The energy only contracts exclude power contracts held with Lehman Brothers Commodity Services totaling 1,434 GWh for 2009 and 1,428 GWh for 2010, which were suspended at September 30, 2008 and subsequently terminated in October 2008.

2 The amount of power sold is a portion of the retail load of the purchasing utility and can vary significantly with variations in that retail load. Retail load depends upon a number of factors, including the time of day and year, and the utility’s number of new and continuing customers. Estimated GWh have been forecast based on historical patterns and on assumptions regarding the factors that may affect retail loads in the future. The actual load will vary from that used for the above estimate, and the amount of variation may be material.

3 The average price per MWh, which is subject to a seasonal price adjustment, represents the sale of a bundled product that includes, but is not limited to, energy, capacity and ancillary services. Also, Midwest Generation will incur charges from PJM as a load-serving entity. Thus, the average price per MWh is not comparable to the sale of power under an energy only contract. The average price per MWh represents the sale of the bundled product based on an estimated customer load profile.

4 The average price/MWh for Homer City’s hedge position is based on PJM West Hub prices. As a result of transmission congestion in the PJM, actual energy prices at the Homer City busbar have been lower than those at the PJM West Hub.

5 At September 30, 2008, there are options to purchase additional coal of 0.3 million tons in 2009, 1.9 million tons in 2010 and 1.4 million tons in 2011.

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2008 Earnings Guidance

Guidance Reconciliation: Core Earnings per Share to GAAP Earnings

2008 Core Guidance Updated Guidance Factors

2008 Core Guidance Reaffirmed and GAAP Guidance

EIX Consolidated

Core EPS1 as of 8/8/2008 Updated as of 11/7/2008

Expect to see 2008 core

SCE $2.18 — $2.28 $2.18 — $ 2.28 earnings near the middle of the range

EMG 1.57 — 1.87 1.57 — 1.87

SCE

EIX parent company and other (0.14) (0.14) 11.5% Return on Equity

Includes potential Energy

EIX core earnings per share $3.61 — $4.01 $3.61 — $4.01 Efficiency earnings of ~$0.07 per share

Non-Core Items

EMG

SCE— —PBR decision (0.15) Forward hedge positions and prices as of 9/30/2008 EMG — — EMMT pre-tax trading income $138M as of 9/30/2008

Total Non-Core Items $ — — $ — $(0.15) — $(0.15) Lower pre-tax earnings from EMG’s Sycamore and Watson

EIX GAAP earnings per share $3.61 — $4.01 $3.46 — $3.86 projects ($60M-$70M reduction)

Excluded from Guidance

Potential impact of IRS issues

Note: Guidance excludes certain items shown at right • CAIR allowances purchased by EMG

Discontinued operations

1 See Use of Non-GAAP Financial Measures in appendix. The expected impact of participating securities is $(0.05) per share for 2008 guidance and is included in EIX parent company and other. GAAP earnings per share refers to basic earnings per share.

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Liquidity Profile

Available Liquidity at June 30 and September 30, 2008

June 30, 2008 September 30, 2008

EIX EIX Parent Co. Parent Co.

Sources ($ in Millions) SCE EMG & Other Total1 SCE EMG & Other Total1

Credit Facility $ 2,500 $ 1,100 $ 1,500 $ 5,100 $ 2,500 $ 1,100 $ 1,500 $ 5,100 Credit Facility (availability)2 $ 1,503 $ 968 $ 1,500

$3,971 $ 628 $ 433 $ 1,188 $ 1,859 Cash & short term investments4 187 805 91 1,083 1,259 1,904 324 3,487

Available Liquidity $ 1,690 $ 1,773 $ 1,591 $ 5,054 $ 1,887 $ 1,947 $ 1,512 $ 5,346

Edison International companies drew $2.1 billion from their credit facilities to assure near-term liquidity and will repay them once ongoing funding is assured

1 Total amounts do not imply any credit support among entities except as specified in each credit facility.

2 Excludes the unused and/or unfunded commitments for subsidiaries of Lehman Brothers Holdings of $81 million for SCE, $38 million for EMG, and $62 million for EIX. Current funded amounts from subsidiaries of Lehman Brothers Holdings are $25 million for SCE, $42 million for EMG, and $12 million for EIX.

3 EMG available borrowing capacity reduced by $2 million for Lehman Brothers Commercial Bank’s share of the Midwest Generation working capital facility.

4 SCE amounts include $112 million and $118 million held by SCE’s consolidated variable interest entities (VIE) as of June 30 and September 30, 2008, respectively.

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Financial Institutions Providing Credit Lines

Status at September 30, 2008

Bank/Institution EIX SCE EME MWG Bank Total

($ in Millions)

Royal Bank of Scotland/ABN AMRO $180 $300 $30 $25 $535 JPMorgan Chase 139 231 66 44 480 CSFB 124 206 66 44 440 Merrill Lynch 101 169 66 44 380 Citigroup 104 174 81 9 368 Deutsche Bank 101 169 36 44 350 Wells Fargo 94 206 15 - 315 Lehman Brothers1 74 106 36 44 260 Goldman Sachs 54 169 36 - 259 Union Bank 58 96 56 44 254 Bank of New York/Mellon 94 133 -- 227 Bank of America 75 125 -- 200 All Others 304 415 110 204 1,032

Bank Line Total2 1,500 2,500 600 500 5,100

Edison International has a diverse bank group of domestic and foreign institutions

1 The unused and/or unfunded commitments for subsidiaries of Lehman Brothers Holdings were $81 million for SCE, $38 million for EMG, and $62 million for EIX. Current funded amounts from subsidiaries of Lehman Brothers Holdings are $25 million for SCE, $42 million for EMG, and $12 million for EIX.

2 Totals may be different from summation of individual lines due to rounding.

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Credit Risk Exposure from Counterparties1

Status at September 30, 2008

Edison Mission Energy Southern California Edison

Net Net S&P Credit Rating2 Exposure3 Collateral Exposure Exposure3 Collateral Exposure A or higher $ 140 $ — $ 140 $ 3 $ — $ 3

A— 56 — 56 36 — 36 BBB + 56 (1) 55 — — —BBB 87 (6) 81 — — —BBB— 31 — 31 — — —

Below investment grade and not rated 21 (4) 17 — — —

Total $ 391 $ (11) $ 3804 $ 39 $ — $ 39

1 For power and gas trading and hedging activities. In addition to the amounts set forth in the above table, EME’s subsidiaries have posted a $147M cash margin in the aggregate with PJM, NYISO, MISO, clearing brokers and other counterparties to support hedging and trading activities.

2 EME and SCE assign a credit rating based on the lower of a counterparty’s S&P or Moody’s rating. The table above uses the S&P classification to summarize risk, but reflects the lower of the two credit ratings.

3 Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheet, except for any related accounts receivable. a) For EME, the credit risk exposure is comprised of $197M of net accounts receivable and payables and $194M representing the fair value of derivative contracts. b) For SCE, the credit risk is comprised of $5M of net accounts receivables and payables, and $34M representing the fair value of derivative contracts.

4 Includes total net exposure to financial institutions at September 30, 2008 of $129M which excludes $26M related to net assets from Lehman Brothers Holdings and its subsidiaries which were fully reserved in the third quarter of 2008.

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EMG Capital Expenditures

Estimated Expenditures1 Capital Expenditure Update

2008 – 2010 • Pending recovery of the capital markets, Projects Under Construction EME intends to preserve capital by focusing Wind Turbine Commitments on a more selective growth strategy

Plant/Corporate Capex Plan

Environmental Plan Completion of projects under construction, including the Big Sky

Millions $1,200 project in Illinois $1,039 Development of sites for future

$1,000

renewable projects that would deploy $800 $709 turbines under commitments

? Use cash and future cash flow to meet

$600

existing contractual commitments

$400 $278 $200

$0

Oct-Dec 2009 2010 2008

Estimated capital expenditures are $2.0 billion for the next three years.

1 EMG expects to make substantial investments in new projects during the next several years. As of September 30, 2008, EMG had a development pipeline of potential wind projects with an estimated installed capacity of approximately 5,000 MW (the development pipeline represents potential projects for which EME either owns the project rights or has exclusive negotiation rights). Completion of these projects is dependent upon a number of items, and there is no assurance that the projects included in the development pipeline currently or added in the future will lead to the successful completion of a wind project.

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Appendix

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EMG Capacity Sales

Status at September 30, 2008

Oct 1, 2008 — May 31, 2009 Jun 1, 2009 — May 31, 2010 Jun 1, 2010 — May 31, 2011 Jun 1, 2011 — May 31, 2012

Midwest Homer Midwest Homer Midwest Homer Midwest Homer Megawatts except price per MW-day Generation City Generation City Generation City Generation City

Installed Capacity 5,776 1,884 5,776 1,884 5,477 1,884 5,477 1,884

Less: Net capacity held due to load requirement services contracts,1 and retained for outages (1,918) (159) (447) (214) (548) (71) (895) (113)

Net Capacity Available for Sale 3,858 1,725 5,329 1,670 4,929 1,813 4,582 1,771

Fixed Price Capacity Sales RPM Auction Process

• Net Capacity Sold2 2,954 820 4,614 1,670 4,929 1,813 4,582 1,771

• Price per MW-day2 $122.42 $111.92 $102.04 $191.32 $174.29 $174.29 $110.00 $110.00

Non-unit Specific Capacity Sales

• Net Capacity Sold 880 — 715 — — — — —

• Price per MW-day (Net) $64.35 $ — $71.46 $ — $ — $ — $ — $ —

Variable Capacity Sales Third Party Transaction

• Capacity — 905 — — — — — —

• Expected price per MW-day3 $ — $62.22 $ — $ — $ — $ — $ — $ —

Total Capacity Sold 3,834 1,725 5,329 1,670 4,929 1,813 4,582 1,771 Average Price per MW-Day $109.09 $85.85 $97.94 $191.32 $174.29 $174.29 $110.00 $110.00

1 Load requirements services contracts include energy, capacity and ancillary services.

2 The original price of $111.92 was affected by Midwest Generation’s participation in a supplemental RPM auction during the first quarter of 2008, which resulted in purchasing certain capacity amounts at a price of $10 per MW-day, thereby reducing the aggregate forward capacity sales for this period and increasing the effective capacity price to $122.42.

3 Actual contract price is a function of NYISO capacity auction clearing prices for October 2008 and forward over-the-counter NYISO capacity prices on September 30, 2008 for November 2008 through May 2009.

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EMG Comparative Operating Statistics

3Q 07 3Q 08 Variance % YTD 07 YTD 08 Variance %

Midwest Generation

Generation (in GWh)

Energy Only contracts 6,298 7,333 17,441 19,404 Load Requirement Services Contracts 2,115 1,080 5,728 4,212

Total 8,413 8,413 0 0% 23,169 23,616 447 2%

Performance

Equivalent Availability Rate (EAF) 86.6% 87.4% 0.8% 78.7% 80.9% 2.2% Forced Outage Rate (EFOR) 8.6% 8.3% (0.3)% 7.0% 9.0% 2.0%

Pricing Information

Average Realized Energy Price ($/MWh)

Energy Only Contracts $48.15 $54.25 $6.10 13% $48.73 $53.44 $4.71 10% Load Requirement Services Contracts $65.27 $63.40 ($1.87) (3)% $63.34 $62.65 ($0.69) (1)% Average Cost of Fuel ($/MWh) $13.88 $16.90 $3.02 22% $13.40 $15.51 $2.11 16% Flat Energy Price - Nihub ($/MWh) $47.02 $53.18 $6.16 13% $45.40 $52.68 $7.28 16%

Homer City

Generation (in Gwh) 3,759 3,354 (405) (11)% 10,211 8,796 (1,415) (14)%

Performance

Equivalent Availability Rate (EAF) 96.5% 93.6% (2.9)% 89.0% 80.9% (8.1)% Forced Outage Rate (EFOR) 3.5% 4.0% 0.5% 3.7% 8.1% 4.4%

Pricing Information

Average Realized Energy Price ($/MWh) $51.48 $61.95 $10.47 20% $54.42 $57.69 $3.27 6% Average Cost of Fuel ($/MWh) $22.48 $23.30 $0.82 4% $22.00 $23.02 $1.02 5% Flat Energy Price - PJM West Hub ($/MWh) $63.34 $77.25 $13.91 22% $60.27 $73.86 $13.59 23% Flat Energy Price - HC Busbar ($/MWh) $50.86 $61.63 $10.77 21% $50.95 $61.82 $10.87 21% Flat Energy Price- Basis (PJM West Hub - HC Busbar) $12.48 $15.62 $3.14 $9.32 $12.04 $2.72

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EMG Business Platform

Washington Iowa Illinois New York

Natural Gas 70 MW Wind 145 MW Coal 5,471 MW Wind (Pipeline) 258 MW

Wind (Pipeline) 221 MW Natural Gas 305 MW

California West Virginia

Wind (Pipeline) 520 MW

Natural Gas 964 MW Minnesota Coal 40 MW

Natural Gas (Pipeline) 479 MW Wind 95 MW Wisconsin Wind (Pipeline) 60 MW

Wind (UC) 50 MW Wind (Pipeline) 100 MW

Arizona Pennsylvania

Wind (Pipeline) 131 MW

Wind (Pipeline) 1,000 MW Wyoming Coal 1,884 MW

Nebraska Wind 141 MW Wind 29 MW Utah Wind (UC) 53 MW Wind (UC) 38 MW

Wind (Pipeline) 100 MW

Wind 19 MW Wind (Pipeline) 80 MW

Wind (Pipeline) 40 MW Maryland

Wind (Pipeline) 85 MW

Oklahoma

Wind 95 MW Operating Platform1

Wind (UC) 19 MW MW %

Wind (Pipeline) 580 MW Coal 7,395 76

Natural Gas 1,339 14

Nevada

Wind 855 8

Wind (Pipeline) 515 MW Other 153 2

New Mexico 9,742 100

Wind 90 MW Wind Development Pipeline2

Wind (UC) 100 MW

MW

Wind (Pipeline) 970 MW

Under Construction 330 Texas Pipeline 5,060

Wind 241 MW Turbines (Not Shown) 942

Wind (UC) 70 MW

Wind (Pipeline) 400 MW Thermal Pipeline3 MW

Natural Gas 479

1 Natural gas includes oil-fired; other includes Doga in Turkey (144 MW) and Huntington biomass (9 MW) which are not shown. Data as of September 30, 2008.

2 Owned or under exclusive agreement. Turbines purchased or committed to support development pipeline. Data as of September 30, 2008.

3 Contract award subject to regulatory approval with planned on-stream date June 2013.

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EMG – Third Quarter Adjusted EBITDA

Reconciliation to Net Income ($ Millions) 3Q 07 3Q 08

Net income $ 203 $ 214 Addback (Deduct): Discontinued operations 4 (6) Income from continuing operations 207 208 Interest expense 74 70 Interest income (26) (7) Income taxes 116 125 Depreciation and amortization 45 50

EBITDA1 416 446

Production tax credits2 6 9 Discrete items: Gain on sale of assets (1) (1)

Adjusted EBITDA1 $ 421 $ 454

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

2 Production tax credits (PTC) are after-tax.

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EMG – Year-to-Date Adjusted EBITDA

Reconciliation to Net Income ($ Millions) YTD 07 YTD 08

Net income $ 315 $ 479 Addback (Deduct): Discontinued operations (1) — Income from continuing operations 314 479 Interest expense 247 211 Interest income (81) (27) Income taxes 139 265 Depreciation and amortization 125 143

EBITDA1 744 1,071

Production tax credits2 18 29 Discrete items: Gain on sale of assets (1) (50) Loss on early extinguishment of debt 241 —

Adjusted EBITDA1 $ 1,002 $ 1,050

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

2 Production tax credits (PTC) are after-tax.

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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 as primary performance measurements when communicating with analysts and investors regarding our earnings results and outlook, as it allows us to more accurately compare the company’s ongoing performance across periods. Core earnings exclude discontinued operations and other non-core items and are reconciled to basic earnings per common share.

EPS by principal operating subsidiary is based on the principal operating subsidiary net income and Edison International’s weighted average 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. EPS and core EPS by principal operating subsidiary are reconciled to basic earnings per common share.

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.

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 the presentation.

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