Exhibit 99.1
Business Update
August 2006
Forward-Looking Statement
This presentation contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Edison
International’s current expectations and projections about future events based on Edison International’s knowledge of present facts and circumstances and assumptions about future
events and include any statement that does not directly relate to a historical or current fact. In this presentation and elsewhere, the words “expects,” “believes,” “anticipates,”
“estimates,” “projects,” “intends,” “plans,” “probable,” “may,” “will,” “could,” “would,” “should,” and variations of such words and similar expressions, or discussions of strategy or of
plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those
anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ, or that otherwise could impact Edison International or its subsidiaries,
include but are not limited to:
• the ability of Edison International to meet its financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay dividends;
• the ability of Southern California Edison (SCE) to recover its costs in a timely manner from its customers through regulated rates;
• decisions and other actions by the California Public Utilities Commission (CPUC) and other regulatory authorities and delays in regulatory actions;
• market risks affecting SCE’s energy procurement activities;
• access to capital markets and the cost of capital;
• changes in interest rates, rates of inflation and foreign exchange rates;
• governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market
and environmental regulations that could require additional expenditures or otherwise affect the cost and manner of doing business;
• risks associated with operating nuclear and other power generating facilities, including operating risks, nuclear fuel storage, equipment failure, availability, heat rate and
output;
• the availability of labor, equipment and materials;
• the ability to obtain sufficient insurance, including insurance relating to SCE’s nuclear facilities;
• effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
• supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which MEHC generating units have
access;
• the cost and availability of coal, natural gas, and fuel oil, nuclear fuel, and associated transportation;
• the cost and availability of emission credits or allowances for emission credits;
• transmission congestion in and to each market area and the resulting differences in prices between delivery points;
• the ability to provide sufficient collateral in support of hedging activities and purchased power and fuel;
• the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation
facilities and technologies;
• the difficulty of predicting wholesale prices, transmission congestion, energy demand, and other activities in the complex and volatile markets in which MEHC and its
subsidiaries participate;
• general political, economic and business conditions;
• weather conditions, natural disasters and other unforeseen events; and
• changes in the fair value of investments and other assets accounted for using fair value accounting.
Additional information about risks and uncertainties, including more detail about the factors described above, is contained in Edison International’s reports filed with the Securities and Exchange Commission. Readers are urged to read such reports and carefully consider the risks, uncertainties and other factors that affect Edison International’s business.
Readers also should review future reports filed by Edison International with the Securities and Exchange Commission. The information contained in this presentation is subject to change without notice. Forward-looking statements speak only as of the date they are made and Edison International is not obligated to publicly update or revise forward-looking statements.
1
Edison International—Value Drivers
EIX
Integrated Platform
SCE
Value Drivers
Strong customer and load growth
• Tight reserve margins keep focus on reliability
• $11 billion, 5-year capital investment program
• 63%—Expand and strengthen distribution system
• 23%—New transmission for system reliability and
renewables
• 14%—San Onofre steam generators and other
generation
• Additional investment potential for new
transmission and advanced metering
• Strengthened regulatory framework
• 3-year forward rate-setting
• Cost of Capital
• Procurement cost recovery mechanisms
• Financial performance
• Rate base CAGR 9% through 2010
EMG
Value Drivers
• Low-cost coal generation portfolio
• EBITDA exceeds $1 billion annually1/2
• Strong operational and marketing/trading capabilities
• Focus on optimizing and stabilizing merchant
margins
• Match duration of hedges (coal, transportation,
emissions, forward sales)
• Effective allocation of cash balances
• Debt reduction
• New generation investments
• Hedging collateral
• Diversify and grow the generation portfolio
• Focus on development of non-coal projects with
long-term contracts
• Renewables
• Thermal, initially in California
• IGCC—Carson Hydrogen project
1. See appendix for non-GAAP reconciliation.
2. Reflects guidance issued on June 29th, 2006. Guidance will not be updated until release of third quarter earnings
2
System
Growth
Capital
Investment
Execution Regulatory
Framework
Dependable
Earnings
Southern California Edison (SCE)
Capital
Investment
3
SCE Value Driver – System Growth
System
Growth
Capital
Investment
Execution Regulatory
Framework
Dependable
Earnings
Strong customer and load growth keeps statewide focus on the need to
expand and strengthen the utility infrastructure
SCE Growth 1
88,321 83,979
77,437
73,204
63,463 63,021
50,000
60,000
70,000
80,000
90,000
2001 2002 2003 2004 2005 2006
New Meter Connections
Peak Demand
10,000
14,000
18,000
22,000
26,000
17,890 18,821
20,136 20,762
21,934 22,889
2001 2002 2003 2004 2005 2006
SCE’s service territory has
– 4 of the 10 fastest growing counties in
the nation 2
– 5 of the 25 fastest growing cities in the
nation 3
• New meter connections
– Expect to exceed 88,000 in 2006
– 360,000 meters added in the past 5
years
• Peak demand
– In July 2006 Peak Demand reached
22,889 MW
• 4.4% growth from 2005 peak
• 10.2% higher than 2004 peak
1. 2006 figures projected for full-year.
2. LA, Riverside, San Bernardino and Orange counties. US Census Bureau data, in terms of population increase between 2000 and 2005.
3. Moreno Valley, Rancho Cucamonga, Irvine, Lancaster and Fontana. US Census Bureau data, in terms of population increase between 2004 and 2005.
4 |
|
SCE Value Driver – System Growth
Capital
Investment
System
Growth Execution Regulatory
Framework
Dependable
Earnings
In July 2006, SCE launched solicitations for renewable power contracts
and long-term power contracts for new generation
Renewable Contracts
• 10-, 15-, or 20-year contract proposals due 09/06
??In 2005, SCE purchased and delivered to
customers more than 13 billion kilowatt-hours of
electricity generated with renewable energy, more
than any U.S. utility.
??SCE estimates that more than 16% of the
power it delivers this year will come from
renewable sources
New Generation Contracts
Soliciting up to 1,500 MW of new IPP generation
• 10-year contracts for generation on-line as early
as 2009
• Initial responses due 09/06
• CPUC has provided cost recovery assurance
5
SCE Value Driver – Capital Investment
2.3 2.3 2.3
2.1 2.0
0.0
0.5
1.0
1.5
2.0
2.5
3.0
2006 2007 2008 2009 2010
Current Forecast by Classification
$ %
Current Forecast by Proceeding
$ Billions
$ %
Generation 1.5 14
Transmission 2.5 23
Distribution 7.0 63
CPUC Rate Cases 8.0 72
FERC Rate Cases 2.5 23
Project Specific 0.5 5
Total 11.0 100
Total 11.0 100
• Five-year capital spending projected at $11 billion
• 2006 CPUC GRC authorized $5 billion of investment for 2006-2008
• 50% of our 5-year forecast has received regulatory approval
In addition to above: possible new transmission and advanced metering
Capital
Investment
System
Growth Execution Regulatory
Framework
Dependable
Earnings
Five-year capital spending projected at $11 billion
• 2006 CPUC GRC authorized $5 billion of investment for 2006-2008
• 50% of our 5-year forecast has received regulatory approval
6
SCE Value Driver – Capital Investment
• Capital investment program translates into rate base CAGR of 9%
• 2009-2010 increase primarily from 2009 GRC, new transmission and SONGS SGR
• Plan to file 2009 GRC in July 2007
1. Includes impact of 2006 CPUC and 2006 FERC GRC Decisions; forecasted authorized rate base for FERC (2007 2010) and CPUC
(2009-2010) subject to regulatory approval.
14.0
15.8
12.6
11.7 10.9 10.2
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
18.0
2005 2006 2007 2008 2009 2010
2003
GRC
2006 GRC 1
CPUC Approved 2009 GRC 1
Growth Rate 6.9% 7.3% 7.7% 11.1% 12.9%
$ Billions Rate Base
Capital
Investment
System
Growth Execution Regulatory
Framework
Dependable
Earnings
7
8
SCE Value Driver – Execution
SCE has made significant strides toward receiving necessary permits
and regulatory approvals for major transmission projects
$829 Various Reliability
$2,496 Total
$ 416 Various Renewables
$ 122 2011 Vincent – Mira Loma
$ 745 2006/2009 DPV1 & DPV2
$ 139
$ 245
2006-2010
(Millions)
2008/2009 Antelope – Phase 1
2009 Rancho Vista
Substation
In Service
Date Project Name
Las Vegas
Existing 500kV
Future 500kV
Midway
(PG&E)
CALIFORNIA
Los Angeles
Sylmar
Lugo
Mohave
Palo
Verde
Vincent
ARIZONA
San Diego
NEVADA
Eldorado
Pardee
Tehachapi
Antelope
Palmdale
Santa
Ana
SCE
Service
Territory
Phoenix
Santa Clarita
Serrano Valley
Mira
Loma
Devers
Rancho
Vista
Palm
Springs
Capital
Investment
System
Growth Execution Regulatory
Framework
Dependable
Earnings
9
SCE Value Driver – Execution
San Onofre Nuclear Generation Station Mountainview
• Mountainview placed in service in time to help meet summer load requirements
• CPUC approved SONGS Steam Generator Replacement (SGR)
• 969 MW in the heart of SCE’s load center
• Began commercial operation in December
2005 and January 2006
• $0.6 billion investment (on-time, on-budget)
• 2,150 MW total (SCE share 75.05%)1
• Unit 2 SGR in service 2010 and Unit 3 SGR
2011
• $0.6 billion—SGR project costs (SCE share)1
1. Pending regulatory approval to transfer Anaheim share to increase SCE ownership to 78.21%.
Capital
Investment
System
Growth Execution Regulatory
Framework
Dependable
Earnings
10
SCE Value Driver – Regulatory Framework
California’s regulatory framework has been strengthened
to support growth, reliability needs and mitigate risks of volatile commodity prices
• 2006 Cost of Capital (COC)
Decision
• 48% common equity
• 11.6% return on common
equity
• SCE has filed an application to
forego the 2007 COC
proceeding and to retain its
current cost of capital and return
on common equity for 2007
Investors’ Return
• General Rate Case (GRC),
provides three-year forward
looking rate-setting mechanism
based on forecast spending, has
been affirmed twice
• Recent 2006 GRC Decision
• Approved 97% of 2006-
2008 capital request
• Approved 95% of annual
operating expense request
• Increased depreciation
providing annual cash flow
of $900 million in 2006
growing to $1 billion in 2008
Rate Base and Operations
• Energy Resources Recovery
Account (ERRA) and related
Trigger Mechanism provides
timely recovery of procurement
costs and mitigates energy price
exposure (AB 57 protections)
• January 2006 ERRA Decision
increased SCE’s revenue
requirement $960 million
mitigating substantial increase in
natural gas and power prices
forecast for 2006
Procurement Cost
Capital
Investment
System
Growth Execution Regulatory
Framework
Dependable
Earnings
11
SCE Value Driver – Dependable Core Earnings
570 570
613
658
586 595
0
100
200
300
400
500
600
700
2004 2005 2006 2007
$ Millions – Core Earnings1
Oct 2004 Strategic Plan Guidance Actual Guidance2
SCE provides EIX high quality and reasonably predictable core earnings
1. See appendix for non-GAAP reconciliation.
2. Earnings guidance was effective as of the date given and will not be updated until third quarter earnings are released
Capital
Investment
System
Growth Execution Regulatory
Framework
Dependable
Earnings
12
Edison Mission Group (EMG)
Operational/Marketing/
Trading Capabilities
Low-Cost
Coal
Cash
Position
Growth
Opportunities
13
EMG – Generation Portfolio
Wildorado
161 MW
Homer City
1,884 MW
Midwest Generation
5,613 MW coal
305 MW gas/oil
March Point
70 MW
Big 4,
Sunrise & Other
964 MW
San Juan
Mesa
90 MW
Storm Lake
109 MW
Misc. Wind
67 MW
Ambit
40 MW
Strong operating platform and evolving growth opportunities
Operational/Marketing/
Trading Capabilities
Low-Cost
Coal
Cash
Position
Growth
Opportunities
MW
7,537 Coal (80%)
1,483 1 Gas/Oil (16%)
427 2 Wind (4%)
9 Biomass
9,456 Total
1. Includes 180 MW Doga project (EME share 144 MW) located in Turkey which is not shown above.
2. Includes 161 MW under construction.
14
• Low-cost coal generation is the key driver to significant EBITDA 1
– $1.18 billion in 2005, $1.09 billion in 2006 and $1.27 billion in 2007
• Strong operational and marketing/trading capabilities
– Effective management of fuel and transportation contracting and environmental costs
to protect margins
– Match duration of hedges (coal, transportation, emissions, forward sales)
– Illinois BGS Auction (ComEd, Ameren)
• Balance use of cash among continued debt reduction, growth and hedging
requirements (cash position 2 at 6/30—$1.95 billion)
– $1 billion refinancing completed on 6/6 to lower interest costs/extend maturities
– Repay $800 million MEHC Notes in 2008 (12.5 cents per share net earnings benefit)
– Investment in renewables, thermal projects
– Expanded liquidity facilities from $600 million to $1 billion to support hedging
• Expansion of generation portfolio
– Contracted projects with fuel diversity
– Nationwide development of renewable resources
– Thermal/IGCC projects, initially in California
EMG – Value Drivers
1. See appendix for non-GAAP reconciliation. Earnings guidance was effective as of the date given and will not be updated until third quarter earnings are released
Operational/Marketing/
Trading Capabilities
Low-Cost
Coal
Cash
Position
Growth
Opportunities
2. Cash and short-term investments.
15
EMG – Wind Portfolio
• Future wind project pipeline supported
by exclusive agreements:
– 181 MW in late-stage development 1
– 700+ MW in development pipeline 2
• EME secured 668 MW of wind turbines
to support 2006 and 2007 development
• Projects have long-term PPAs with
creditworthy counterparties
• Accelerated return of cash from tax
credits and depreciation
RPS
Requirements
Development
Expertise
Development
Pipeline
Turbine
Commitments
National Wind
Portfolio
1. Late-stage development: Projects with exclusive development agreements and near final investment decisions.
2. Development Pipeline: Projects with exclusive development agreements and under active investment consideration.
130 Optioned Turbines
668 Total Turbines
538 Purchased Turbines
427 10 Total
161 1 Under construction
266 9 In-service
Size (MW) Projects
Wind Project Portfolio
16
EMG – California Thermal Generation Opportunities
Natural Gas-
Fired
Generation
Recontracting
Projects
IGCC
• Big 4 projects contract extension (602 MW)
– Kern River—5-year market-rate contract approved by
CPUC in May 2006
– Other Big 4 contracts expire: December 2007
(Sycamore); April 2008 (Watson); May 2009 (Midway-
Sunset)
• New natural gas-fired generation (1,000 MW)
– 2 project permit applications filed with California Energy
Commission (Sun Valley – 500 MW, Walnut Creek – 500
MW)
– Intend to bid into SCE RFO (Sept 2006)
• EMG/BP hydrogen power project (500 MW)
– Conducting engineering studies
• Petroleum coke fuel with approximately 90% of CO2 removed
and used for enhanced oil recovery
• Submitted DOE application for gasification tax credits
17
Year to Date Performance
through June 30, 2006
Balance Sheet
Strength Performance Growth Dividends Shareholder
Returns
18
Edison International—Earnings Performance
Year-to-Date June 30,
Core Earnings (Loss) Per Common Share
(Unaudited)
2006 2005 Change
Southern California Edison Company $0.84 $0.88 $(0.04)
Edison Mission Group
Mission Energy Holding Company 0.26 0.15 0.11
Edison Capital 0.06 0.22 (0.16)
Edison Mission Group Total 0.32 0.37 (0.05)
EIX (parent) and other (0.06) (0.06) —
EIX Consolidated Core Earnings 1.10 1.19 (0.09)
Non-core items
SCE – Generator refund incentive — 0.01 (0.01)
SCE – Resolution of an outstanding state tax item 0.25 — 0.25
MEHC – Extinguishment of debt (0.27) (0.05) (0.22)
MEHC – Earnings from discontinued operations 0.24 0.08 0.16
Total non-core items 0.22 0.04 0.18
Total EIX Consolidated Earnings $1.32 $1.23 $0.09
19
Three months ended June 30, Six months ended June 30,
2006 2005 Change % 2006 2005 Change %
Midwest Generation
Generation (in TWhr) 5.5 5.8 (0.3) -5.2% 12.7 14.2 (1.5) -10.6%
Equivalent Availability 66.0% 62.1% 3.9% 76.4% 71.1% 5.3%
Forced Outage Rate (EFOR) 7.7% 9.6% -1.9% 5.0% 8.7% -3.7%
Average Cost of Fuel ($/MWh) 13.42 12.51 0.91 7.3% 13.14 12.12 1.02 8.4%
Flat Energy Price—Nihub ($/MWh) 39.31 38.34 0.96 2.5% 40.89 39.01 1.88 4.8%
Average Midwest Gen Energy Price ($/MWh) 47.63 41.83 5.80 13.9% 47.09 40.12 6.97 17.4%
Homer City
Generation (in TWhr) 2.9 3.1 (0.2) -6.5% 5.4 6.6 (1.2) -18.2%
Equivalent Availability 74.3% 77.1% -2.8% 73.1% 82.6% -9.5%
Forced Outage Rate 19.9% 3.6% 16.3% 22.8% 5.6% 17.2%
Average Cost of Fuel ($/MWh) 24.13 19.36 4.77 24.6% 24.03 18.65 5.38 28.8%
Flat Energy Price—PJM West Hub ($/MWh) 48.08 47.30 0.78 1.6% 52.25 47.24 5.01 10.6%
Flat Energy Price—HC Busbar ($/MWh) 44.00 44.86 (0.86) -1.9% 47.24 44.54 2.70 6.1%
Flat Energy Price—PJM West Hub minus
HC Busbar ($/MWHr)—Basis 4.08 2.44 1.64 5.01 2.70 2.31
Average Homer City Energy Price ($/MWh) 50.02 42.93 7.09 16.5% 51.43 43.38 8.05 18.6%
Hedge Program status at June 30, 2006
Remainder of
2006 2007 2008
Midwest Generation
Megawatt hours (in TWh) 10.0 16.2 3.1
Average Energy Price ($/MWh) 47.61 $ 48.25 $ 66.13 $ (1)
Percent of Coal Requirements Under Contract 108% 95% 33%
Homer City
Megawatt hours (in TWh) 4.4 7.6 2.4
Average Energy Price ($/MWh) 54.07 $ 64.35 $ 66.01 $
Percent of Coal Requirements Under Contract 99% 97% 39%
(1) |
| Represents on-peak hedges. |
Note: Subsequent to June 30, 2006, an agreement was executed to hedge an additional 500 MW of on-peak power from
the Midwest Gen facilities for 2007, 2008 and 2009.
Edison International – EMG Update
Hedge Program status at June 30, 2006
20
Guidance
as of June 29th, 2006
Balance Sheet
Strength Performance Growth Dividends Shareholder
Returns
21
Edison International—Earnings Guidance
(Effective as of June 29th, 2006)
Guidance
2006 2007 Core EPS:
$3.35 $3.13 $3.47 Total
$1.44 $1.14 $1.42 EMG Total
– 0.25 0.40
Non-Core Items:
• SCE 2
– (0.03) (0.06) • EMG 3
$3.35 $2.91 $3.13 Core
(0.11) (0.11) (0.11) • EIX Holding Co. 1
0.13 0.14 0.29 – EC 1
1.31 1.00 1.13 – MEHC
• EMG
$2.02 $1.88 $1.82 • SCE
Recorded
2005 Key Factors/Assumptions
2006-2007
SCE
• DSM incentive benefited 2005 by $0.08
• 2006 CPUC and FERC rate increases and
continuation of 11.6% ROCE in 2007
EMG
• Fuel and emission costs largely hedged
• Power generation hedge plan complete
• 5/31/2006 forward power prices used for
unhedged generation revenue for guidance
• EMMT earnings contribution $0.33 in 2005;
assumption: $0.10 in 2006 4 and $0.04 in
2007
• EC infrastructure gain of $0.16 in 2005
Other
• Impact on earnings of expensing stock
options beginning in 2006: $0.07 in 2006
and in 2007
1. Reflects earnings consolidated on an EMG basis.
2. SCE: 2005: 1991-1993 Tax audit settlement—$0.19; FERC 002 Case—$0.17; Generator refunds—$0.04; 2006: Resolution of a state tax issue.
3. EMG: 2005: March Point impairment—($0.10); Discontinued operations including Lakeland distribution—$0.09; Early debt retirement—($0.05); 2006: Early debt
retirement—($0.27); Discontinued operations including Lakeland distribution – $0.24.
4. EMMT: Includes earnings of $0.08 through May 31, 2006 and forecast earnings of $0.02 for the remainder of 2006.
See appendix for detailed non-GAAP reconciliation.
Earnings guidance will not be updated until third quarter earnings are released
22
Coal Transp. Coal Emissions Generation Forward
Sales Basis
10% Price Increase Sensitivities
(pre-tax impact)
($ million)
1. Full-year 2006.
2. Coal contracts based on expected burn and contracted deliveries without regard to inventory levels.
3. As of May 31, 2006, excludes transportation.
4. Fuel costs, excluding emissions, includes coal and coal transportation costs, natural gas and oil used for startup and limestone cost.
See Assumptions Detail in appendix for additional information.
($ million)
($ million)
EMG – 2006-2007 Hedge Plan Guidance
(Effective as of June 29th, 2006)
Coal Commodity and Transportation
20061 2007 2006 2007
Midwest Gen
Expected Coal Burn (Millions Tons) 17.8 17.8
Contracted Coal 2 105% 95%
PRB Forward Commodity Price 3 ($/ton) $12.37 $13.54—(1.2)
($/MWh increase)
Fuel Cost, excluding emissions 4 ($/MWh)$13.00 $13.30—0.04
Homer City
Expected Coal Burn (Millions Tons) 5.2 5.6
Contracted Coal 2 97% 95%
NAPP Forward Commodity Price 3 ($/ton) $42.50 $45.25—(1.2)
($/MWh increase)
Fuel Costs, excluding emissions 4 ($/MWh)$18.50 $17.57—0.09
Emission Hedge Position
NOx (Aggregate Credits) 93% 90% (0.3) (0.4)
SO2 (Aggregate Credits) 94% 76% (1.0) (3.8)
Earnings guidance will not be updated until third quarter earnings are released
23
14.0
7.6
54%
$64.35
$63.22
28.8
16.2
56%
$48.25
$44.92
2007
Remainder of
20061 Hedge Program
8.8
5.2
58%
$54.46
$58.64
Homer City
Expected generation (TWH) 2
Volume hedged (TWh)
Percent of expected generation 3
Average hedge price 3/5 ($/MWh)
PJM West Hub Flat Price 4 ($/MWh)
Basis
18.2
11.6
63%
$47.68
$44.47
Midwest Gen
Expected generation (TWh) 2
Volume hedged (TWh)
Percent of expected generation 3
Average hedge price 3 ($/MWh)
NiHub Flat Price 4 ($/MWh)
Midwest Gen
Homer City
1. June 1, 2006 to December 31, 2006. 2006 full year expected generation for Midwest Gen is 28.7 TWh and Homer City is 13.1 TWh.
2. Expected generation levels are forecasted amounts and actual levels could differ based on a number of factors including
weather, demand for power, unit availability, and system dispatch as addressed in the forward looking statement.
3. As of June 26, 2006.
4. As of May 31, 2006.
5. Hedge price at PJM West Hub. During 2005 and 2004, average market price at PJM West was $6.12 and $1.55 higher than average market
price at Homer City Busbar. Without basis hedge, Homer City retains risk in price movements between these locations on hedge position.
Historic average <1%
Averaged 4% in 2004 and 10% in 2005
8.4 TWh basis hedge (4/2006 – 5/2007)
2006 2007
$1/MWh Realized Price Increase
Increases Earnings
$ million
6.7 12.5
3.7 6.4
Sensitivities (pre-tax impact)
Coal Transp. Coal Emissions Generation Forward
Sales Basis
EMG – 2006-2007 Hedge Plan Guidance
(Effective as of June 29th, 2006)
* |
| Note: This assumes expected |
generation and other factors
remain unchanged
Earnings guidance will not be updated until third quarter earnings are released
24
Midwest Gen
Forecast generation 1 (TWh) 29.3
Hedged generation 2 (TWh) 3.1 (10.6%)
Average hedge price 2/3 ($/MWh) $66.13
Contracted Coal 33%
NiHub Flat Price 4 ($/MWh) 44.89
Homer City
Forecast generation 1 (TWh) 13.7
Hedged generation 2 (TWh) 2.4 (17.5%)
Average hedge price 2 ($/MWh) $66.01
Contracted Coal 39%
PJM West Hub Flat Price 4 ($/MWh) 61.37
Initiated 2008 hedge program. PRB coal transportation
contracts are in place through 2011. For 2008, emission
credits position is similar to 2007. Additional hedging of
commodity price risk is contemplated.
2. As of June 26, 2006.
3. Reflects on-peak hedges.
See footnotes on prior page.
4. As of May 31, 2006.
Coal Transp. Coal Emissions Generation Forward
Sales Basis
EMG – 2008 Hedge Plan Guidance
(Effective as of June 29th, 2006)
1. Expected generation levels are forecasted amounts and actual levels could differ based on a number of factors including
weather, demand for power, unit availability, and system dispatch as addressed in the forward looking statement.
25
Edison International – Strategic Plan Foundation
• Strong utility
operating in a large
and rapidly growing
service territory
• Competitive power
generation business
with large base of
low-cost coal assets
Organic Growth
• Significant long-term
earnings and cash flow
growth from regulated
investments
• Business flexibility for
future growth
• Upside earnings potential
from competitive
generation investments
Produces Produces
Balance Sheet
Strength Performance Growth Dividends Shareholder
Returns
26
Appendix
27
Operating Statistics:
Total Assets $25.3 B
Customers 4.8 M
Total Debt 4 $5.8 B
Total Assets $35.1 B
Generation 3 14,490 MW
Edison International – Organizational Structure 1
Operating Statistics:
Total Assets $3.3 B
Total Investments $2.7 B
Total Debt 4 $0.2 B
Southern California Edison
Credit Rating 2 BBB+ / A3
Operating Statistics:
Total Assets $7.0 B
Total MWs Owned 3 9,456
Coal Generation MWs 7,537
Total Debt 4 $4.2 B
Mission Energy
Holding Company
Credit Rating 2 B- / B2
B+ / B1 (EME)
Edison Capital
Credit Rating 2 BB+ / Ba1
1. As of June 30, 2006.
2. Represents S&P and Moody’s ratings as of June 30, 2006. Represents S&P and Moody’s ratings: SCE and MEHC Senior Secured debt, EME and EC Senior Unsecured debt, and EIX
corporate credit rating (S&P) and Senior Unsecured shelf rating (Moody’s)
3. Includes 161 MW under construction at MEHC.
4. Includes short-term, long-term, and current portion of long-term debt; non-recourse debt and intercompany debt
of $54 million and $78 million at SCE and MEHC, respectively.
Edison International
Credit Rating 2 BBB / Baa3
Edison Mission Group
28
Appendix – Non-GAAP Reconciliation
(Guidance effective as of June 29th, 2006)
1.44 1.14 1.42 EMG
$3.47
0.34
0.09
(0.05)
(0.10)
0.40
3.13
(0.11)
0.29
1.13
$1.82
2005
$3.35 $3.13 Total EIX Consolidated Earnings
— 0.22 Total Non-core Items
— 0.24 MEHC – Discontinued operations 1
— (0.27) MEHC – Early debt retirements
— — MEHC – March Point impairment
— 0.25 SCE – Regulatory and tax items
Non-core items
3.35 2.91 EIX Consolidated Core Earnings
(0.11) (0.11) EIX parent company and other
0.13 0.14 Edison Capital and other
1.31 1.00 Mission Energy Holding Company
$2.02 $1.88 Southern California Edison Company
2007 2006
Core Earnings (Loss) Per Common Share
Year Ending December 31,
1. Primarily relates to Lakeland Distribution.
Earnings guidance will not be updated until third quarter earnings are released
29
2004 2005 2006 2007
millions, except EPS guidance 1 recorded guidance 1 recorded guidance guidance
$ EPS $ EPS $ EPS $ EPS $ EPS $ EPS
SCE Core Earnings $570 $1.75 $586 $1.80 $570 $1.75 $595 $1.82 $613 $1.88 $658 $2.02
Non-Core Items:
SCE—Regulatory and tax items 157 0.48 329 1.01 36 0.11 130 0.40 81 0.25—-
Total SCE Earnings $727 $2.23 $915 $2.81 $606 $1.86 $725 $2.22 $694 $2.13 $658 $2.02
Year Ending December 31,
1. October 2004 Strategic Plan Guidance.
Earnings guidance will not be updated until third quarter earnings are released
Appendix – Non-GAAP Reconciliation
(Guidance effective as of June 29th, 2006)
30
Appendix – EBITDA
(Guidance effective as of June 29th, 2006)
Edison Mission Group
($ millions)
2005 2006 2007
Actual Outlook Forecast
Net income $442.4 $361.5 $468.8
Add-back (Deduct):
Cumulative effect of change in accounting 1.2 (0.4) -
Discontinued operations (29.5) (78.6) -
Income (Loss) from continued operations 414.1 282.5 468.8
Interest expense 435.2 424.4 406.0
Interest income (73.7) (90.0) (62.5)
Income taxes (benefits) 162.8 159.4 226.3
Depreciation and amortization 146.8 165.7 189.9
EBITDA 1,085.2 942.0 1,228.4
Production tax credits 7.5 16.8 39.5
Discrete items:
Loss on lease termination, asset impairment and other charges 7.3—-
Impairment of equity method investment 54.9—-
Gain on sale of assets—(4.0) -
Loss on early extinguishment of debt 24.6 137.7 -
Adjusted EBITDA $1,179.5 $1,092.5 $1,267.9
Earnings guidance will not be updated until third quarter earnings are released
31
• NAPP, “Northern Appalachian”; PRB, “Powder River Basin”
• Actual future Fuel Costs, excluding emissions, may differ from estimated future fuel costs, excluding emissions due
to a number of factors including SO2 adjustments, Btu adjustments, changes in spot prices/new contracts, inventory
build or reduction, changes in costs based on contractually determined escalators and exercise of options under certain
agreements.
• Fuel Costs, excluding emissions, include coal and coal transportation costs, natural gas and oil used for start-up and,
at Homer City, limestone costs and excludes all emissions purchases and/or sales. Reflects average inventory costs.
• NAPP Coal is a proxy for the actual coal purchased by Homer City. Two types of coal, ready to burn and raw, are
purchased for Units 1 and 2. Ready to burn coal is of a quality that can be burned directly in Units 1 and 2, whereas the
raw coal purchased for Units 1 and 2 must be cleaned in the coal cleaning plant. Coal for all three units is generally
sourced within 100 miles of the facility.
• Coal Contracts (% hedged) are based on expected burn for the calendar year and deliveries during that year.
Percentages are calculated without regard to potential changes in coal inventory.
• Energy price sensitivities are based on a $1/MWh change in the realized price for each unhedged MWh sold. This
sensitivity does not capture possible changes to generation output or correlated changes in the price of fuel or
emissions.
• Coal price sensitivities are based on the unhedged fuel requirement and a 10% change in coal commodity price of PRB,
related to Midwest Generation requirements, and NAPP coal, as a proxy for the coal types burned at Homer City. A
10% change in NAPP coal is assumed to drive a 10% change in Homer City coal types although the absolute price
change may be different.
• Average hedge price reflects the total value of the on- and off-peak hedges and is not directly comparable to the flat
energy price.
• The earnings impact of SO2 price changes incorporates a forecast of emissions that may vary depending upon the
sulfur content of coal and generation levels. Generation levels may also impact NOx emissions and the related earnings
impact.
Assumption Details
(Guidance effective as of June 29th, 2006)
32
EMG – Capital Expenditures
2Q 2006 to 4Q 2008
0
50
100
150
200
250
300
350
400
450
500
2006 BoY 2007 2008 2009
Plant Capex Environmental Growth
$826 Million
• Evaluating FGDs at Homer City Units 1 and 2
• Environmental expenditures at Midwest Gen
• Wind investments
• Thermal investments
Potential Expenditures Planned Expenditures
$ Millions
33
EMG – Liquidity Profile
0
200
400
600
800
1,000
1,200
6/30/06 Collateral² Potential (@ 95%)³
$ millions
$2,748
1,953
295
$500
6/30/06
$2,292
1,869
325
$98
12/31/05
Cash & Short term
investments¹
MWG Revolver
EME Revolver
($ millions)
Sources
Available Liquidity
Credit Facilities
Collateral
1. Excludes $698 million and $336 million of cash collateral held by counterparties at 12/31/05 and 6/30/06, respectively
2. Includes $7 million in letters of credit
3. During next 12 months, using 95% confidence level
$310
$343
• Cash expected to decline from payoff of
MEHC notes (2008) and growth
• Strong market conditions allowed EME to
replace $98 million revolver with $500 million,
6-year facility
• Enhanced liquidity: $1 billion of credit facilities
between MWG and EME