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EDISON INTERNATIONAL - Quarter Report: 2011 September (Form 10-Q)

Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________________________________
FORM 10-Q
____________________________________________________
(Mark One)
S
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the quarterly period ended September 30, 2011
£
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the transition period from                         to                          
Commission File Number 1-9936
____________________________________________________

EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
____________________________________________________
California
 
95-4137452
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
2244 Walnut Grove Avenue
(P. O. Box 976)
Rosemead, California
 
91770
(Address of principal executive offices)
 
(Zip Code)
(626) 302-2222
(Registrant's telephone number, including area code)
____________________________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes S No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes S No £
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer S
Accelerated filer £
Non-accelerated filer £
(Do not check if a smaller reporting company)
Smaller reporting company £
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes £ No S
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Class
 
Outstanding at October 31, 2011
Common Stock, no par value
 
325,811,206
 
Table of Contents

TABLE OF CONTENTS

i
Table of Contents


ii
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iii
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iv
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GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
2010 Form 10-K
 
Edison International's Annual Report on Form 10-K for the year-ended December 31, 2010
2010 Tax Relief Act
 
Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
AFUDC
 
allowance for funds used during construction
Ambit project
 
American Bituminous Power Partners, L.P.
AOI
 
Adjusted Operating Income (Loss)
APS
 
Arizona Public Service Company
ARO(s)
 
asset retirement obligation(s)
BACT
 
best available control technology
BART
 
best available retrofit technology
Bcf
 
billion cubic feet
Big 4
 
Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
Btu
 
British thermal units
CAA
 
Clean Air Act
CAIR
 
Clean Air Interstate Rule
CAISO
 
California Independent System Operator
CAMR
 
Clean Air Mercury Rule
CARB
 
California Air Resources Board
CDWR
 
California Department of Water Resources
CEC
 
California Energy Commission
coal plants
 
Midwest Generation coal plants and Homer City plant
Commonwealth Edison
 
Commonwealth Edison Company
CPS
 
Combined Pollutant Standard
CPUC
 
California Public Utilities Commission
CSAPR
 
Cross-State Air Pollution Rule
CRRs
 
congestion revenue rights
DOE
 
U.S. Department of Energy
EME
 
Edison Mission Energy
EMG
 
Edison Mission Group Inc.
EMMT
 
Edison Mission Marketing & Trading, Inc.
EPS
 
earnings per share
ERRA
 
energy resource recovery account
EWG
 
Exempt Wholesale Generator
Exelon Generation
 
Exelon Generation Company LLC
FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission
FGIC
 
Financial Guarantee Insurance Company
FIP(s)
 
federal implementation plan(s)
Four Corners
 
coal fueled electric generating facility located in Farmington, New Mexico in
which SCE holds a 48% ownership interest
GAAP
 
generally accepted accounting principles
GHG
 
greenhouse gas
Global Settlement
 
A settlement between Edison International and the IRS that resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002 and related matters with state tax authorities.

v
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GRC
 
general rate case
GWh
 
gigawatt-hours
Homer City
 
EME Homer City Generation L.P., a Pennsylvania limited partnership that leases and operates three coal-fired electric generating units and related facilities located in Indiana County, Pennsylvania
Illinois EPA
 
Illinois Environmental Protection Agency
IRS
 
Internal Revenue Service
ISO
 
Independent System Operator
kWh(s)
 
kilowatt-hour(s)
LIBOR
 
London Interbank Offered Rate
MD&A
 
Management's Discussion and Analysis of Financial Condition and Results
of Operations in this report
Midwest Generation
 
Midwest Generation, LLC, a Delaware limited liability company that owns and/or leases, and that operates, the Midwest Generation plants
Midwest Generation plants
 
Midwest Generation's power plants (fossil fuel) located in Illinois
MMBtu
 
million British thermal units
Mohave
 
two coal fueled electric generating facilities that no longer operate located
in Clark County, Nevada in which SCE holds a 56% ownership interest
Moody's
 
Moody's Investors Service
MRTU
 
Market Redesign and Technology Upgrade
MW
 
megawatts
MWh
 
megawatt-hours
NAAQS
 
national ambient air quality standards
NAPP
 
Northern Appalachian
NERC
 
North American Electric Reliability Corporation
Ninth Circuit
 
U.S. Court of Appeals for the Ninth Circuit
NOV
 
notice of violation
NOx
 
nitrogen oxide
NRC
 
Nuclear Regulatory Commission
NSR
 
New Source Review
NYISO
 
New York Independent System Operator
PADEP
 
Pennsylvania Department of Environmental Protection
Palo Verde
 
large pressurized water nuclear electric generating facility located near
Phoenix, Arizona in which SCE holds a 15.8% ownership interest
PBOP(s)
 
postretirement benefits other than pension(s)
PBR
 
performance-based ratemaking
PG&E
 
Pacific Gas & Electric Company
PJM
 
PJM Interconnection, LLC
PRB
 
Powder River Basin
PSD
 
Prevention of Significant Deterioration
QF(s)
 
qualifying facility(ies)
ROE
 
return on equity
RPM
 
Reliability Pricing Model
RTO(s)
 
Regional Transmission Organization(s)
S&P
 
Standard & Poor's Ratings Services
San Onofre
 
large pressurized water nuclear electric generating facility located in south
San Clemente, California in which SCE holds a 78.21% ownership interest
SCE
 
Southern California Edison Company
SNCR
 
selective non-catalytic reduction

vi
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SDG&E
 
San Diego Gas & Electric
SEC
 
U.S. Securities and Exchange Commission
SIP(s)
 
state implementation plan(s)
SO2
 
sulfur dioxide
US EPA
 
U.S. Environmental Protection Agency
VIE(s)
 
variable interest entity(ies)
year-ended 2010 MD&A
 
Management's Discussion and Analysis of Financial Condition and Results
of Operations appearing in the 2010 Form 10-K


vii
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Statements of Income
Edison International
 
 
 
 
 
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions, except per-share amounts, unaudited)
2011
 
2010
 
2011
 
2010
Electric utility
$
3,385

 
$
3,097

 
$
8,060

 
$
7,502

Competitive power generation
596

 
691

 
1,686

 
1,838

Total operating revenue
3,981

 
3,788

 
9,746

 
9,340

Fuel
352

 
328

 
866

 
877

Purchased power
1,264

 
1,118

 
2,422

 
2,337

Operations and maintenance
1,119

 
1,102

 
3,531

 
3,287

Depreciation, decommissioning and amortization
436

 
378

 
1,288

 
1,127

Total operating expenses
3,171

 
2,926

 
8,107

 
7,628

Operating income
810

 
862

 
1,639

 
1,712

Interest and dividend income
4

 
4

 
38

 
27

Equity in income from unconsolidated affiliates – net
56

 
62

 
68

 
101

Other income
27

 
33

 
110

 
103

Interest expense
(203
)
 
(175
)
 
(601
)
 
(518
)
Other expenses
(11
)
 
(12
)
 
(37
)
 
(39
)
Income from continuing operations before income taxes
683

 
774

 
1,217

 
1,386

Income tax expense
242

 
247

 
369

 
261

Income from continuing operations
441

 
527

 
848

 
1,125

Income (loss) from discontinued operations – net of tax
—

 
(4
)
 
(3
)
 
4

Net income
441

 
523

 
845

 
1,129

Dividends on preferred and preference stock of utility
15

 
13

 
44

 
39

Other noncontrolling interests
—

 
—

 
(1
)
 
—

Net income attributable to Edison International common shareholders
$
426

 
$
510

 
$
802

 
$
1,090

Amounts attributable to Edison International common shareholders:
 
 
 
 
 
 
 
Income from continuing operations, net of tax
$
426

 
$
514

 
$
805

 
$
1,086

Income (loss) from discontinued operations, net of tax
—

 
(4
)
 
(3
)
 
4

Net income attributable to Edison International common shareholders
$
426

 
$
510

 
$
802

 
$
1,090

Basic earnings per common share attributable to Edison International common shareholders:
 
 
 
 
 
 
 
Weighted-average shares of common stock outstanding
326

 
326

 
326

 
326

Continuing operations
$
1.31


$
1.57


$
2.47


$
3.32

Discontinued operations
—

 
(0.01
)
 
(0.01
)
 
0.01

Total
$
1.31

 
$
1.56

 
$
2.46

 
$
3.33

Diluted earnings per common share attributable to Edison International common shareholders:
 
 
 
 
 
 
 
Weighted-average shares of common stock outstanding, including effect of dilutive securities
329

 
328

 
329

 
328

Continuing operations
$
1.30

 
$
1.57

 
$
2.46

 
$
3.30

Discontinued operations
—

 
(0.01
)
 
(0.01
)
 
0.01

Total
$
1.30

 
$
1.56

 
$
2.45

 
$
3.31

Dividends declared per common share
$
0.320

 
$
0.315

 
$
0.960

 
$
0.945


The accompanying notes are an integral part of these consolidated financial statements.

1
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Consolidated Statements of Comprehensive Income
 
Edison International
 
 
 
 
 
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions, unaudited)
2011
 
2010
 
2011
 
2010
Net income
$
441

 
$
523

 
$
845

 
$
1,129

Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Pension and postretirement benefits other than pensions:
 
 
 
 
 
 
 
Net gain arising during the period, net of income tax expense of $2 for the nine months ended September 30, 2010
—

 
1

 
—

 
13

Amortization of net (gain) loss included in net income, net of income tax expense (benefit) of $1 and $1 for the three months and $4 and $(3) for the nine months ended September 30, 2011 and 2010, respectively
3

 
1

 
7

 
(5
)
Prior service credit arising during the period, net of income tax expense of $1 for the nine months ended September 30, 2010
—

 
—

 
—

 
2

Amortization of prior service credit, net of income tax benefit of $1 for the nine months ended September 30, 2010
—

 
—

 
—

 
(2
)
Unrealized gain (loss) on derivatives qualified as cash flow hedges:
 
 
 
 
 
 
 
Unrealized holding gain (loss) arising during the period, net of income tax expense (benefit) of $(19) and $29 for the three months and $(24) and $41 for the nine months ended September 30, 2011 and 2010, respectively
(30
)
 
43

 
(38
)
 
61

Reclassification adjustments included in net loss, net of income tax benefit of none and $5 for the three months and $12 and $54 for the nine months ended September 30, 2011 and 2010, respectively
—

 
(7
)
 
(17
)
 
(80
)
Other comprehensive income (loss)
(27
)
 
38

 
(48
)
 
(11
)
Comprehensive income
414

 
561

 
797

 
1,118

Less: Comprehensive income attributable to noncontrolling interests
15

 
13

 
43

 
39

Comprehensive income attributable to Edison International
$
399

 
$
548

 
$
754

 
$
1,079



The accompanying notes are an integral part of these consolidated financial statements.

2
Table of Contents

Consolidated Balance Sheets
Edison International
 
 
 
 
 
(in millions, unaudited)
September 30,
2011
 
December 31,
2010
ASSETS
 
 
 
Cash and cash equivalents
$
1,384

 
$
1,389

Receivables, less allowances of $97 and $85 for uncollectible accounts at respective dates
1,218

 
931

Accrued unbilled revenue
709

 
442

Inventory
592

 
568

Prepaid taxes
72

 
390

Derivative assets
100

 
133

Restricted cash
15

 
2

Margin and collateral deposits
54

 
65

Regulatory assets
454

 
378

Other current assets
153

 
124

Total current assets
4,751

 
4,422

Nuclear decommissioning trusts
3,393

 
3,480

Investments in unconsolidated affiliates
569

 
559

Other investments
231

 
223

Total investments
4,193

 
4,262

Utility property, plant and equipment, less accumulated depreciation of $6,745 and $6,319 at respective dates
26,490

 
24,778

Competitive power generation and other property, plant and equipment, less accumulated depreciation of $2,083 and $1,865 at respective dates
5,579

 
5,406

Total property, plant and equipment
32,069

 
30,184

Derivative assets
191

 
437

Restricted deposits
43

 
47

Rent payments in excess of levelized rent expense under plant operating leases
1,320

 
1,187

Regulatory assets
4,486

 
4,347

Other long-term assets
619

 
644

Total long-term assets
6,659

 
6,662

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
47,672

 
$
45,530



The accompanying notes are an integral part of these consolidated financial statements.

3
Table of Contents

Consolidated Balance Sheets
Edison International
 
 
 
 
 
(in millions, except share amounts, unaudited)
September 30,
2011
 
December 31,
2010
LIABILITIES AND EQUITY
 
 
 
Short-term debt
$
560

 
$
115

Current portion of long-term debt
51

 
48

Accounts payable
1,224

 
1,362

Accrued taxes
128

 
52

Accrued interest
207

 
205

Customer deposits
203

 
217

Derivative liabilities
290

 
217

Regulatory liabilities
734

 
738

Other current liabilities
764

 
998

Total current liabilities
4,161

 
3,952

Long-term debt
13,010

 
12,371

Deferred income taxes
6,003

 
5,625

Deferred investment tax credits
89

 
122

Customer advances
133

 
112

Derivative liabilities
344

 
468

Pensions and benefits
2,293

 
2,260

Asset retirement obligations
2,658

 
2,561

Regulatory liabilities
4,481

 
4,524

Other deferred credits and other long-term liabilities
2,454

 
2,041

Total deferred credits and other liabilities
18,455

 
17,713

Total liabilities
35,626

 
34,036

Commitments and contingencies (Note 9)


 


Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued and outstanding at each date)
2,346

 
2,331

Accumulated other comprehensive loss
(124
)
 
(76
)
Retained earnings
8,793

 
8,328

Total Edison International's common shareholders' equity
11,015

 
10,583

Preferred and preference stock of utility
1,029

 
907

Other noncontrolling interests
2

 
4

Total noncontrolling interests
1,031

 
911

Total equity
12,046

 
11,494

Total liabilities and equity
$
47,672

 
$
45,530



The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

Consolidated Statements of Cash Flows
Edison International
 
 
 
 
Nine months ended
September 30,
(in millions, unaudited)
2011
 
2010
Cash flows from operating activities:
 
 
 
Net income
$
845

 
$
1,129

Less: Income (loss) from discontinued operations
(3
)
 
4

Income from continuing operations
848

 
1,125

Adjustments to reconcile to net cash provided by operating activities:
 
 
 
Depreciation, decommissioning and amortization
1,288

 
1,127

Regulatory impacts of net nuclear decommissioning trust earnings
131

 
106

Other amortization
112

 
90

Stock-based compensation
22

 
20

Equity in income from unconsolidated affiliates – net
(68
)
 
(101
)
Distributions from unconsolidated entities
52

 
76

Deferred income taxes and investment tax credits
373

 
414

Proceeds from U.S. treasury grants
310

 
92

Income from leveraged leases
(4
)
 
(3
)
Changes in operating assets and liabilities:
 
 
 
Receivables
(205
)
 
(184
)
Inventory
(20
)
 
(27
)
Margin and collateral deposits – net of collateral received
6

 
32

Prepaid taxes
318

 
33

Other current assets
(319
)
 
(224
)
Rent payments in excess of levelized rent expense
(133
)
 
(148
)
Accounts payable
178

 
28

Accrued taxes
76

 
(23
)
Other current liabilities
(189
)
 
(129
)
Derivative assets and liabilities – net
137

 
1,079

Regulatory assets and liabilities – net
(73
)
 
(530
)
Other assets
(14
)
 
(40
)
Other liabilities
1

 
(67
)
Operating cash flows from discontinued operations
(3
)
 
4

Net cash provided by operating activities
2,824

 
2,750

Cash flows from financing activities:
 
 
 
Long-term debt issued
686

 
1,652

Long-term debt issuance costs
(24
)
 
(35
)
Long-term debt repaid
(97
)
 
(371
)
Bonds purchased
(86
)
 
—

Preference stock issued – net
123

 
—

Short-term debt financing – net
573

 
13

Settlements of stock-based compensation – net
(14
)
 
(7
)
Dividends and distributions to noncontrolling interests
(43
)
 
(39
)
Dividends paid
(313
)
 
(308
)
Net cash provided by financing activities
$
805

 
$
905



The accompanying notes are an integral part of these consolidated financial statements.

5
Table of Contents

Consolidated Statements of Cash Flows
Edison International
 
 
 
 
 
 
Nine months ended
September 30,
(in millions, unaudited)
2011
 
2010
Cash flows from investing activities:
 
 
 
Capital expenditures
$
(3,491
)
 
$
(3,129
)
Purchase of interest in acquired companies
(3
)
 
(4
)
Proceeds from sale of nuclear decommissioning trust investments
2,108

 
903

Purchases of nuclear decommissioning trust investments and other
(2,254
)
 
(1,036
)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment
6

 
35

Investments in other assets
—

 
3

Effect of consolidation and deconsolidation of variable interest entities
—

 
(91
)
Net cash used by investing activities
(3,634
)
 
(3,319
)
Net increase (decrease) in cash and cash equivalents
(5
)
 
336

Cash and cash equivalents, beginning of period
1,389

 
1,673

Cash and cash equivalents, end of period
$
1,384

 
$
2,009



The accompanying notes are an integral part of these consolidated financial statements.

6
Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1. Summary of Significant Accounting Policies
Edison International has two business segments for financial reporting purposes: an electric utility operation segment (SCE) and a competitive power generation segment (EMG). SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to an approximately 50,000 square mile area of southern California. EMG is the holding company for its principal wholly owned subsidiary, EME. EME is a holding company with subsidiaries and affiliates engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also engages in hedging and energy trading activities in competitive power markets through its Edison Mission Marketing & Trading, Inc. ("EMMT") subsidiary.
Basis of Presentation
Edison International's significant accounting policies were described in Note 1 of "Edison International Notes to Consolidated Financial Statements" included in the 2010 Form 10-K. Edison International follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2011, discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2010 Form 10-K.
In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America ("GAAP") for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and nine-month periods ended September 30, 2011 are not necessarily indicative of the operating results for the full year.
The December 31, 2010 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.
Cash Equivalents
Cash equivalents included investments in money market funds totaling $1.1 billion at both September 30, 2011 and December 31, 2010. Generally, the carrying value of cash equivalents equals the fair value, as these investments have maturities of three months or less.
Edison International temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. Edison International reclassified $215 million and $197 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at September 30, 2011 and December 31, 2010, respectively.
Inventory
Inventory is stated at the lower of cost or market, cost being determined by the weighted-average cost method for fuel, and the average cost method for materials and supplies. Inventory consisted of the following:
(in millions)
September 30,
2011
 
December 31,
2010
Coal, gas, fuel oil and other raw materials
$
191

 
$
184

Spare parts, materials and supplies
401

 
384

Total inventory
$
592

 
$
568

Earnings Per Share
Edison International computes earnings per share ("EPS") using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International's participating securities are stock-based compensation awards payable in common shares, including stock options, performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares. Stock options awarded during the period 2003 through 2006 received dividend equivalents. EPS attributable to Edison International common shareholders was computed as follows:


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Table of Contents

 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Basic earnings per share – continuing operations:
 
 
 
 
 
 
 
Income from continuing operations attributable to common shareholders, net of tax
$
426

 
$
514

 
$
805

 
$
1,086

Participating securities dividends
—

 
(3
)
 
—

 
(5
)
Income from continuing operations available to common shareholders
$
426

 
$
511

 
$
805

 
$
1,081

Weighted average common shares outstanding
326

 
326

 
326

 
326

Basic earnings per share – continuing operations
$
1.31


$
1.57


$
2.47


$
3.32

Diluted earnings per share – continuing operations:
 
 
 
 
 
 
 
Income from continuing operations available to common shareholders
$
426

 
$
511

 
$
805

 
$
1,081

Income impact of assumed conversions
1

 
2

 
3

 
3

Income from continuing operations available to common shareholders and assumed conversions
$
427

 
$
513

 
$
808

 
$
1,084

Weighted average common shares outstanding
326

 
326

 
326

 
326

Incremental shares from assumed conversions
3

 
2

 
3

 
2

Adjusted weighted average shares – diluted
329

 
328

 
329

 
328

Diluted earnings per share – continuing operations
$
1.30

 
$
1.57

 
$
2.46

 
$
3.30

Stock-based compensation awards to purchase 5,943,378 and 9,700,218 shares of common stock for the three months ended September 30, 2011 and 2010, respectively, and 8,970,290 and 6,154,826 shares of common stock for the nine months ended September 30, 2011 and 2010 respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares during the respective periods and, therefore, the effect would have been antidilutive.
New Accounting Guidance
Accounting Guidance Adopted in 2011
Revenue—Multiple-Deliverables
In October 2009, the Financial Accounting Standards Board ("FASB") issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenues based on those separate deliverables. This update also requires additional disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is required to be applied prospectively to new or significantly modified revenue arrangements. Edison International adopted this guidance effective January 1, 2011. The adoption of this accounting standards update did not have a material impact on Edison International's consolidated results of operations, financial position or cash flows.
Fair Value Measurements and Disclosures
The FASB issued an accounting standards update modifying the disclosure requirements related to fair value measurements. Under these requirements, purchases and settlements for Level 3 fair value measurements are presented on a gross basis, rather than net. Edison International adopted this guidance effective January 1, 2011.
Accounting Guidance Not Yet Adopted
Fair Value Measurement
In May 2011, the FASB issued an accounting standards update modifying the fair value measurement and disclosure guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the value be based on the individual security. This amendment also results in new disclosures primarily related to Level 3 measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. Edison International will adopt this


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guidance effective January 1, 2012 and does not expect the adoption of this standard will have a material impact on Edison International's consolidated statements of income, financial position or cash flows.
Presentation of Comprehensive Income
In June 2011, the FASB issued an accounting standards update on the presentation of comprehensive income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. Edison International will adopt this guidance effective January 1, 2012. Edison International currently presents the statement of comprehensive income immediately following the statement of income and expects to continue to do so. The adoption of this accounting standards update does not change the items that constitute net income and other comprehensive income.
Note 2. Consolidated Statements of Changes in Equity
The following table provides the changes in equity for the nine months ended September 30, 2011.
 
Equity Attributable to Edison International
 
Noncontrolling Interests
 
 
(in millions)
Common
Stock
 
Accumulated
Other
Comprehensive
Loss
 
Retained
Earnings
 
Subtotal
 
Other
 
Preferred
and
Preference
Stock
 
Total
Equity
Balance at December 31, 2010
$
2,331

 
$
(76
)
 
$
8,328

 
$
10,583

 
$
4

 
$
907

 
$
11,494

Net income (loss)
—

 
—

 
802

 
802

 
(1
)
 
44

 
845

Other comprehensive loss
—

 
(48
)
 
—

 
(48
)
 
—

 
—

 
(48
)
Common stock dividends declared ($0.96 per share)
—

 
—

 
(313
)
 
(313
)
 
—

 
—

 
(313
)
Dividends, distributions to noncontrolling interests and other
—

 
—

 
—

 
—

 
(1
)
 
(44
)
 
(45
)
Stock-based compensation and other
7

 
—

 
(21
)
 
(14
)
 
—

 
—

 
(14
)
Noncash stock-based compensation and other
22

 
—

 
(3
)
 
19

 
—

 
(1
)
 
18

Purchase of noncontrolling interests1
(14
)
 
—

 
—

 
(14
)
 
—

 
—

 
(14
)
Issuance of preference stock
—

 
—

 
—

 
—

 
—

 
123

 
123

Balance at September 30, 2011
$
2,346

 
$
(124
)
 
$
8,793

 
$
11,015

 
$
2

 
$
1,029

 
$
12,046

1 
During the nine months ended September 30, 2011, EMG purchased the remaining interests in Pinnacle Wind Force, LLC, and Broken Bow I, LLC and all assets of the Crofton Bluffs project. All three projects are now 100% owned by EMG. The purchases of the noncontrolling interests were accounted for as equity transactions between controlling and noncontrolling interest holders.
The following table provides the changes in equity for the nine months ended September 30, 2010.
 
Equity Attributable to Edison International
 
Noncontrolling Interests
 
 
(in millions)
Common
Stock
 
Accumulated
Other
Comprehensive
Income
 
Retained
Earnings
 
Subtotal
 
Other
 
Preferred
and
Preference
Stock
 
Total
Equity
Balance at December 31, 2009
$
2,304

 
$
37

 
$
7,500

 
$
9,841

 
$
258

 
$
907

 
$
11,006

Net income
—

 
—

 
1,090

 
1,090

 
—

 
39

 
1,129

Other comprehensive loss
—

 
(11
)
 
—

 
(11
)
 
—

 
—

 
(11
)
Deconsolidation of variable interest entities
—

 
—

 
—

 
—

 
(249
)
 
—

 
(249
)
Cumulative effect of a change in accounting principle, net of tax
—

 
—

 
15

 
15

 
—

 
—

 
15

Common stock dividends declared ($0.945 per share)
—

 
—

 
(308
)
 
(308
)
 
—

 
—

 
(308
)
Dividends, distributions to noncontrolling interests and other
—

 
—

 
—

 
—

 
(4
)
 
(39
)
 
(43
)
Stock-based compensation and other
5

 
—

 
(12
)
 
(7
)
 
—

 
—

 
(7
)
Noncash stock-based compensation and other
16

 
—

 
(2
)
 
14

 
—

 
—

 
14

Balance at September 30, 2010
$
2,325

 
$
26

 
$
8,283

 
$
10,634

 
$
5

 
$
907

 
$
11,546



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Note 3. Variable Interest Entities
A variable interest entity ("VIE") is defined as a legal entity whose equity owners do not have sufficient equity at risk, or, as a group, the holders of the equity investment at risk lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE. Commercial and operating activities are generally the factors that most significantly impact the economic performance of VIEs in which Edison International has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.
Categories of Variable Interest Entities
Projects or Entities that are Consolidated
At September 30, 2011 and December 31, 2010, EMG consolidated 13 and 14 projects, respectively, with a total generating capacity of 570 MW and 580 MW, respectively, that have interests held by others. In April 2011, EMG sold its 75% ownership interest in a Minnesota wind project.
The following table presents summarized financial information of the projects that were consolidated by EMG:
(in millions)
September 30,
2011
 
December 31,
2010
Current assets
$
40

 
$
26

Net property, plant and equipment
702

 
739

Other long-term assets
6

 
6

Total assets
$
748

 
$
771

Current liabilities
$
28

 
$
25

Long-term debt net of current portion
67

 
71

Deferred revenues
69

 
71

Other long-term liabilities
21

 
21

Total liabilities
$
185

 
$
188

Noncontrolling interests
$
2

 
$
4

At September 30, 2011 and December 31, 2010, assets serving as collateral for the debt obligations had a carrying value of $160 million and $163 million, respectively, and primarily consist of property, plant and equipment.
Variable Interest in VIEs that are not Consolidated
Power Purchase Contracts
SCE has 16 power purchase agreements ("PPAs") that have variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to fuel the plants and 10 contracts with qualifying facilities ("QFs") that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. In general, because payments for capacity are the primary source of income, the most significant economic activity for SCE's VIEs is the operation and maintenance of the power plants.
As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts. Under these contracts, SCE recovers the costs incurred under its approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 9. As a result, there is no significant potential exposure to loss as a result of SCE's involvement with these VIEs. The aggregate capacity dedicated to SCE for these VIE projects was 3,820 MW at September 30, 2011 and the amounts that SCE paid to these projects were $178 million and $205 million for the three months ended September 30, 2011 and 2010, respectively, and $347 million and


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$447 million for the nine months ended September 30, 2011 and 2010, respectively. These amounts are recovered in customer rates.
Equity Interests
EMG accounts for domestic gas and wind energy projects in which it has less than a 100% ownership interest, and cannot exercise unilateral control, under the equity method. At September 30, 2011 and December 31, 2010, EMG had five significant variable interests in natural gas projects that are not consolidated, consisting of the Big 4 projects (Kern River, Midway-Sunset, Sycamore and Watson) and the Sunrise project. A subsidiary of EMG operates three of the four Big 4 projects and the Sunrise project and EMG's partner provides the fuel management services for the Big 4 projects. In addition, the executive director of these projects is provided by EMG's partner. Commercial and operating activities are jointly controlled by a management committee of each VIE. Accordingly, EMG accounts for its variable interests under the equity method.
EMG accounts for its interest in three renewable wind generating facilities under the equity method. At December 31, 2010, EMG had interests in 2 renewable wind generating facilities, the Elkhorn Ridge and San Juan Mesa projects. In addition to these 2 projects, at September 30, 2011, EMG had interests in Community Wind North, which achieved commercial operation on May 28, 2011. The commercial and operating activities of these entities are jointly directed by representatives of each partner. Thus, EMG is not the primary beneficiary of these projects.
The following table presents the carrying amount of EMG's investments in unconsolidated VIEs and the maximum exposure to loss for each investment:
 
September 30, 2011
(in millions)
Investment
 
Maximum
Exposure
Natural gas-fired projects
$
340

 
$
340

Renewable energy projects
228

 
228

EMG's maximum exposure to loss in its VIEs accounted for under the equity method is generally limited to its investment in these entities. One of EMG's domestic energy projects has long-term debt that is secured by a pledge of project entity assets, but does not provide for recourse to EMG. Accordingly, a default under the project financing could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EMG's investment, but would not require EMG to contribute additional capital. At September 30, 2011, entities which EMG has accounted for under the equity method had indebtedness of $64 million, of which $16 million is proportionate to EMG's ownership interest in this project.
Note 4. Fair Value Measurements
Recurring Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, referred to as an exit price. Fair value of an asset or liability should consider assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk.
Edison International categorizes financial assets and liabilities into a fair value hierarchy based on valuation inputs used to determine fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).


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The following table sets forth assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:
 
As of September 30, 2011
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting
and
Collateral1
 
Total
Assets at Fair Value
 
 
 
 
 
 
 
 
 
Money market funds2
$
1,056

 
$
—

 
$
—

 
$
—

 
$
1,056

Derivative contracts:
 
 
 
 
 
 
 
 
 
Electricity
—

 
43

 
213

 
(36
)
 
220

Natural gas
2

 
61

 
10

 
(6
)
 
67

Fuel oil
2

 
—

 
—

 
(2
)
 
—

Tolling
—

 
—

 
4

 
—

 
4

Coal
—

 
1

 
—

 
(1
)
 
—

Subtotal of commodity contracts
4

 
105

 
227

 
(45
)
 
291

Long-term disability plan
9

 
—

 
—

 
—

 
9

Nuclear decommissioning trusts:
 
 
 
 
 
 
 
 
 
Stocks3
1,721

 
—

 
—

 
—

 
1,721

Municipal bonds
—

 
767

 
—

 
—

 
767

U.S. government and agency securities
378

 
123

 
—

 
—

 
501

Corporate bonds4
—

 
318

 
—

 
—

 
318

Short-term investments, primarily cash equivalents5
2

 
151

 
—

 
—

 
153

Subtotal of nuclear decommissioning trusts
2,101

 
1,359

 
—

 
—

 
3,460

Total assets6
3,170

 
1,464

 
227

 
(45
)
 
4,816

Liabilities at Fair Value
 
 
 
 
 
 
 
 
 
Derivative contracts:
 
 
 
 
 
 
 
 
 
Electricity
—

 
17

 
84

 
(18
)
 
83

Natural gas
—

 
240

 
12

 
(12
)
 
240

Fuel oil
1

 
—

 
—

 
(1
)
 
—

Tolling
—

 
—

 
231

 
—

 
231

Subtotal of commodity contracts
1

 
257

 
327

 
(31
)
 
554

Interest rate contracts
—

 
80

 
—

 
—

 
80

Total liabilities
1

 
337

 
327

 
(31
)
 
634

Net assets (liabilities)
$
3,169

 
$
1,127

 
$
(100
)
 
$
(14
)
 
$
4,182



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As of December 31, 2010
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting
and
Collateral1
 
Total
Assets at Fair Value
 
 
 
 
 
 
 
 
 
Money market funds2
$
1,100

 
$
—

 
$
—

 
$
—

 
$
1,100

Derivative contracts:
 
 
 
 
 
 
 
 
 
Electricity
—

 
70

 
363

 
(61
)
 
372

Natural gas
1

 
69

 
11

 
(1
)
 
80

Fuel oil
8

 
—

 
—

 
(8
)
 
—

Tolling
—

 
—

 
118

 
—

 
118

Subtotal of commodity contracts
9

 
139

 
492

 
(70
)
 
570

Long-term disability plan
9

 
—

 
—

 
—

 
9

Nuclear decommissioning trusts:
 
 
 
 
 
 
 
 
 
Stocks3
2,029

 
—

 
—

 
—

 
2,029

Municipal bonds
—

 
790

 
—

 
—

 
790

Corporate bonds4
—

 
346

 
—

 
—

 
346

U.S. government and agency securities
215

 
73

 
—

 
—

 
288

Short-term investments, primarily cash equivalents5
1

 
31

 
—

 
—

 
32

Subtotal of nuclear decommissioning trusts
2,245

 
1,240

 
—

 
—

 
3,485

Total assets6
3,363

 
1,379

 
492

 
(70
)
 
5,164

Liabilities at Fair Value
 
 
 
 
 
 
 
 
 
Derivative contracts:
 
 
 
 
 
 
 
 
 
Electricity
—

 
13

 
40

 
(21
)
 
32

Natural gas
—

 
286

 
11

 
(4
)
 
293

Tolling
—

 
—

 
344

 
—

 
344

Coal
—

 
1

 
—

 
(1
)
 
—

Subtotal of commodity contracts
—

 
300

 
395

 
(26
)
 
669

Interest rate contracts
—

 
16

 
—

 
—

 
16

Total liabilities
—

 
316

 
395

 
(26
)
 
685

Net assets (liabilities)
$
3,363

 
$
1,063

 
$
97

 
$
(44
)
 
$
4,479

1 
Represents the netting of assets and liabilities under master netting agreements and cash collateral across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.
2 
Money market funds are included in cash and cash equivalents and restricted cash on Edison International's consolidated balance sheets.
3 
Approximately 69% and 67% of the equity investments were located in the United States at September 30, 2011 and December 31, 2010, respectively.
4 
At September 30, 2011 and December 31, 2010, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $21 million and $27 million, respectively.
5 
Excludes net liabilities of $67 million and $5 million at September 30, 2011 and December 31, 2010, respectively, of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases.
6 
Excludes $31 million at both September 30, 2011 and December 31, 2010, of cash surrender value of life insurance investments for deferred compensation.


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The following table sets forth a summary of changes in the fair value of Level 3 assets and liabilities:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Fair value, net asset (liabilities) at beginning of period
$
(275
)
 
$
(703
)
 
$
97

 
$
62

Total realized/unrealized gains (losses):
 
 
 
 
 
 
 
Included in earnings1
(4
)
 
24

 
14

 
51

Included in regulatory assets and liabilities2
162

3 
(142
)
 
(220
)
3 
(924
)
Included in accumulated other comprehensive income
1

 
1

 
(2
)
 
5

Purchases
24

 
15

 
51

 
48

Settlements
(8
)
 
(76
)
 
(38
)
 
(128
)
Transfers in or out of Level 3
—

 
(12
)
 
(2
)
 
(7
)
Fair value, net liability at end of period
$
(100
)
 
$
(893
)
 
$
(100
)
 
$
(893
)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period4
$
(110
)
 
$
(163
)
 
$
(425
)
 
$
(882
)
1 
Reported in "Competitive power generation" revenue on Edison International's consolidated statements of income.
2 
Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.
3 
Includes the elimination of the fair value of derivatives with SCE's consolidated affiliates.
4 
Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income was a loss of $3 million for the three months ended September 30, 2010, and gains of $7 million and $1 million for the nine months ended September 30, 2011 and 2010, respectively. The remainder of the unrealized losses relate to SCE. See 2 above.
Edison International determines the fair value for transfers in and transfers out of each level at the end of each reporting period. There were no significant transfers between levels during 2011 and 2010.
Valuation Techniques Used to Determine Fair Value
Level 1
Includes financial assets and liabilities where fair value is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. Financial assets and liabilities classified as Level 1 include exchange-traded equity securities, exchange traded derivatives, U.S. treasury securities and money market funds.
Level 2
Pricing inputs include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument. Financial assets and liabilities utilizing Level 2 inputs include fixed-income securities and over-the-counter derivatives.
Derivative contracts that are over-the-counter traded are valued using pricing models to determine the net present value of estimated future cash flows and are generally classified as Level 2. Inputs to the pricing models include forward published or posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar instruments and discount rates. A primary source that best represents traded activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity. Broker quotes are incorporated when corroborated with other information which may include a combination of prices from exchanges, other brokers and comparison to executed trades.
Level 3
Includes financial assets and liabilities where fair value is determined using techniques that require significant unobservable inputs. Over-the-counter options, bilateral contracts, capacity contracts, QF contracts, derivative contracts that trade infrequently (such as congestion revenue rights ("CRRs") in the California market), long-term power agreements, and derivative contracts with counterparties that have significant nonperformance risks are generally valued using pricing models that incorporate unobservable inputs and are classified as Level 3. Assumptions are made in order to value derivative contracts


14
Table of Contents

in which observable inputs are not available. In circumstances where Edison International cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, Edison International continues to assess valuation methodologies used to determine fair value.
For derivative contracts that trade infrequently (illiquid financial transmission rights and CRRs), changes in fair value are based on models forecasting the value of those contracts. The models' inputs are reviewed and the fair value is adjusted when it is concluded that a change in inputs would result in a new valuation that better reflects the fair value of those derivative contracts. For illiquid long-term power agreements, fair value is based upon the discounting of future electricity and natural gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. The fair value of the majority of SCE's derivatives that are classified as Level 3 is determined using uncorroborated non-binding broker quotes and models which may require SCE to extrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for reasonableness.
Nonperformance Risk
The fair value of the derivative assets and liabilities are adjusted for nonperformance risk. To assess nonperformance risks, SCE considers the probability of and the estimated loss incurred if a party to the transaction were to default. SCE also considers collateral, netting agreements, guarantees and other forms of credit support when assessing nonperformance. EMG reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of nonperformance. The nonperformance risk adjustment represented an insignificant amount at both September 30, 2011 and December 31, 2010.
Nuclear Decommissioning Trusts
SCE's nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed-income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed-income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information.
Fair Value of Long-Term Debt Recorded at Carrying Value
The carrying value and fair value of long-term debt are:
 
September 30, 2011
 
December 31, 2010
(in millions)
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Long-term debt, including current portion
$
13,061

 
$
13,500

 
$
12,419

 
$
12,360

Fair values of long-term debt are based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes of new issue prices and relevant credit information.
The carrying value of trade receivables, payables and short-term debt approximates fair value.
Note 5. Debt and Credit Agreements
Long-Term Debt
In May 2011, SCE issued $500 million of 3.875% first and refunding mortgage bonds due in 2021. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program. In October 2011, SCE issued $150 million of floating rate first and refunding mortgage bonds due in 2014. The proceeds from these bonds were used to finance fuel inventories.
In May 2011 and September 2011, SCE purchased $56 million and $30 million, respectively, of its variable rate tax-exempt bonds.


15
Table of Contents

Project Financings
Walnut Creek
On July 27, 2011, EMG completed, through wholly owned subsidiaries, non-recourse financings to fund construction of the Walnut Creek project, a 479 MW natural gas-fired peaker plant in southern California. The financings included floating rate construction loans totaling $495 million that will convert to 10-year amortizing term loans by June 30, 2013, subject to meeting specified conditions, and also included $122 million of letter of credit ($40 million outstanding at September 30, 2011) and working capital facilities.
The non-recourse financings were completed in two parts. A construction plus term loan financing of $442 million that initially accrues interest at the London Interbank Offered Rate (LIBOR) plus 2.25% and increases by 0.25% after the third, sixth and ninth anniversaries of the term conversion date. An interest rate swap agreement for a portion of the construction loan fixed the floating rate at 0.81% beginning November 30, 2011 through March 31, 2013. The effective rate for the outstanding loan of $44 million was 2.48% at September 30, 2011. Under the swap agreement for majority of the term loan, the fixed interest rate will be 3.54% beginning June 28, 2013 through May 31, 2023 and the effective rate is expected to be 5.84%.

A second construction plus term loan financing of $53 million was obtained by a holding company that accrues interest at LIBOR plus 4.00% over the entire term. An interest rate swap agreement for a portion of the construction loan fixed the floating rate at 0.79% beginning July 29, 2011 through May 31, 2013. The effective rate for the outstanding loan of $49 million was 4.94% at September 30, 2011. Under the swap agreement for the majority of the term loan, the fixed interest rate will be 4.00% beginning June 28, 2013 through May 31, 2023 and the effective rate is expected to be 8.00%, Both outstanding loans were recorded in long-term debt on Edison International's consolidated balance sheet at September 30, 2011.

Viento Funding II Wind Financing Amendment
In February 2011, EME completed, through its subsidiary, Viento Funding II, Inc., an amendment of its 2009 non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The amendment increased the financing amount to $255 million, which included a $227 million ten-year term loan (expiring in December 2020), a $23 million seven-year letter of credit facility and a $5 million seven-year working capital facility. At September 30, 2011, $216 million was outstanding under this loan. The amount of outstanding letters of credit was $23 million. Interest under the term loan accrues at LIBOR plus 2.75% initially with the rate increasing 0.25% on every fourth anniversary.
Credit Agreements and Short-Term Debt
At September 30, 2011, SCE's outstanding short-term debt was $550 million at a weighted-average interest rate of 0.34%. This short-term debt was supported by a $2.4 billion credit facility. At December 31, 2010, there was no outstanding short-term debt. At September 30, 2011, letters of credit issued under SCE's credit facilities aggregated $83 million and are scheduled to expire in twelve months or less.
At September 30, 2011, Edison International (Parent)'s outstanding short-term debt was $10 million at a weighted-average interest rate of 0.60%. At December 31, 2010, the outstanding short-term debt was $19 million at a weighted-average interest rate of 0.63%.
Letters of Credit
At September 30, 2011, standby letters of credit under EME's credit facility aggregated $65 million and were scheduled to expire as follows: $1 million in 2011 and $64 million in 2012. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $98 million and were scheduled to expire as follows: $7 million in 2011, $63 million in 2012, $10 million in 2017, and $18 million in 2018.
Note 6. Derivative Instruments and Hedging Activities
Electric Utility
Commodity Price Risk
SCE is exposed to commodity price risk which represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's hedging program reduces ratepayer exposure to variability in market prices related to SCE's power and gas activities. As part of this program, SCE enters into options, swaps, forwards, tolling arrangements and CRRs. These transactions are pre-approved by the California Public Utilities Commission ("CPUC") or executed in compliance with CPUC-approved procurement plans. SCE recovers its related hedging costs through the energy resource


16
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recovery account ("ERRA") balancing account, and as a result, exposure to commodity price risk is not expected to impact earnings, but may impact cash flows.
SCE's electricity price exposure arises from electricity purchased from and sold to the California and other wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities, power purchase agreements and California Department of Water Resources ("CDWR") contracts allocated to SCE.
SCE's natural gas price exposure arises from natural gas purchased for generation at the Mountainview power plant and peaker plants, QF contracts where pricing is based on a monthly natural gas index and power purchase agreements in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.
Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for hedging activities:
 
 
 
Economic Hedges
Commodity
Unit of Measure
 
September 30,
2011
 
December 31,
2010
Electricity options, swaps and forwards
GWh
 
30,143
 
32,138
Natural gas options, swaps and forwards
Bcf
 
266
 
250
CRRs
GWh
 
146,628
 
181,291
Tolling arrangements
GWh
 
104,822
 
114,599
Fair Value of Derivative Instruments
The following table summarizes the gross and net fair values of commodity derivative instruments at September 30, 2011:
 
Derivative Assets
 
Derivative Liabilities1
 
 
(in millions)
Short-
Term
 
Long-
Term
 
Subtotal
 
Short-
Term
 
Long-
Term
 
Subtotal
 
Net
Liability
Non-trading activities
 
 
 
 
 
 
 
 
 
 
 
 
 
Economic hedges
$
82

 
$
145

 
$
227

 
$
305

 
$
577

 
$
882

 
$
655

Netting and collateral
(14
)
 
(13
)
 
(27
)
 
(18
)
 
(23
)
 
(41
)
 
(14
)
Total
$
68

 
$
132

 
$
200

 
$
287

 
$
554

 
$
841

 
$
641

1 
Includes the fair value of derivatives with SCE's consolidated affiliates; however, in Edison International’s consolidated financial statements, the fair value of such derivatives is eliminated.
The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2010:
 
Derivative Assets
 
Derivative Liabilities
 
 
(in millions)
Short-
Term
 
Long-
Term
 
Subtotal
 
Short-
Term
 
Long-
Term
 
Subtotal
 
Net
Liability
Non-trading activities
 
 
 
 
 
 
 
 
 
 
 
 
 
Economic hedges
$
87

 
$
367

 
$
454

 
$
216

 
$
449

 
$
665

 
$
211

Netting and collateral
—

 
—

 
—

 
(4
)
 
—

 
(4
)
 
(4
)
Total
$
87

 
$
367

 
$
454

 
$
212

 
$
449

 
$
661

 
$
207

Income Statement Impact of Derivative Instruments
SCE recognizes realized gains and losses on derivative instruments as purchased-power expense and expects that such gains or losses will be part of the purchased power costs recovered from ratepayers. As a result, realized gains and losses are not reflected in earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore are also not reflected in earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.


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The following table summarizes the components of economic hedging activity:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Realized losses
$
(58
)
 
$
(53
)
 
$
(132
)
 
$
(116
)
Unrealized losses
(110
)
 
(165
)
 
(433
)
 
(1,022
)
Contingent Features/Credit Related Exposure
Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. SCE has historically provided collateral in the form of cash and/or letters of credit for the benefit of counterparties. These requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments and other factors.
Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from each of the major credit rating agencies, referred to as a credit-risk-related contingent feature. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The aggregate fair value of all derivative liabilities with these credit-risk-related contingent features was $162 million and $67 million as of September 30, 2011 and December 31, 2010, respectively, for which SCE has posted no collateral and $4 million of collateral to its counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2011, SCE would be required to post $23 million of collateral.
Counterparty Default Risk Exposure
As part of SCE's procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. If a counterparty were to default on its contractual obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales of excess energy and realized gains on derivative instruments. All of the contracts that SCE has entered into with counterparties are either entered into under SCE's short-term or long-term procurement plan which has been approved by the CPUC, or the contracts are approved by the CPUC before becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance are not expected to affect earnings, but may temporarily affect cash flows.
To manage credit risk, SCE looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary.
Competitive Power Generation
EMG uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EMG's financial results can be affected by fluctuations in interest rates. The derivative financial instruments vary in duration, ranging from a few days to several years, depending upon the instrument. To the extent that EMG does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements.
Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not designated as cash flow hedges. Economic hedges are accounted for at fair value on EMG's consolidated balance sheets with offsetting changes recorded on the consolidated statements of operations. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized, to the extent effective, on EMG's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive loss until the related forecasted transaction occurs. The results of derivative activities are recorded in cash flows from operating activities on the consolidated statements of cash flows.
Derivative instruments that are utilized for trading purposes are measured at fair value and included on the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in operating revenues on the consolidated statements of operations.
Where EMG's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EMG presents its derivative assets and liabilities on a net basis on its consolidated balance sheets.


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Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for hedging and trading activities:
September 30, 2011
 
 
 
 
 
 
 
 
 
Hedging Activities
 
 
 
 
Commodity
 
Instrument
 
Classification
 
Unit of Measure
 
Cash Flow
Hedges
 
 
Economic
Hedges
 
 
Trading
Activities
 
Electricity
 
Forwards/Futures
 
Sales
 
GWh
 
15,910

1
 
13,353

3
 
36,597

 
Electricity
 
Forwards/Futures
 
Purchases
 
GWh
 
101

1
 
13,230

3
 
42,429

  
Electricity
 
Capacity
 
Sales
 
MW-Day
(in thousands)
 
134

2
 
—

 
 
12

2
Electricity
 
Capacity
 
Purchases
 
MW-Day
(in thousands)
 
12

2
 
—

 
 
219

2
Electricity
 
Congestion
 
Sales
 
GWh
 
—

 
 
90

4
 
15,910

4
Electricity
 
Congestion
 
Purchases
 
GWh
 
—

 
 
4,023

4
 
253,688

4
Natural gas
 
Forwards/Futures
 
Sales
 
bcf
 
—

 
 
—

  
 
55.3

  
Natural gas
 
Forwards/Futures
 
Purchases
 
bcf
 
—

 
 
—

  
 
53.4

  
Fuel oil
 
Forwards/Futures
 
Sales
 
barrels
 
—

 
 
—

  
 
100,000

 
Fuel oil
 
Forwards/Futures
 
Purchases
 
barrels
 
—

 
 
240,000

  
 
140,000

 
Coal
 
Forwards/Futures
 
Sales
 
tons
 
—

 
 
—

  
 
1,485,000

 
Coal
 
Forwards/Futures
 
Purchases
 
tons
 
—

 
 
—

  
 
1,485,000

 

(in millions)
Instrument
 
Purpose
 
Type of Hedge
 
Notional Amount
 
Expiration Date
Accreting forward starting interest rate swap
 
Convert floating rate (1-month LIBOR debt to fixed rate (0.8135%) debt
 
Cash flow
 
$
39

 
May 2013
Accreting interest rate swap
 
Convert floating rate (1-month LIBOR debt to fixed rate (0.79%) debt
 
Cash flow
 
24

 
May 2013
Amortizing interest rate swap
 
Convert floating rate (6-month LIBOR debt to fixed rate (3.175%) debt
 
Cash flow
 
84

 
June 2016
Amortizing interest rate swap
 
Convert floating rate (6-month LIBOR debt to fixed rate (3.415%) debt
 
Cash flow
 
110

 
December 2020
Amortizing forward starting interest rate swap
 
Convert floating rate (3-month LIBOR debt to fixed rate (3.5429%) debt
 
Cash flow
 
398

 
May 2023
Amortizing forward starting interest rate swap
 
Convert floating rate (3-month LIBOR debt to fixed rate (4.0025%) debt
 
Cash flow
 
48

 
May 2023
Amortizing interest rate swap
 
Convert floating rate (3-month LIBOR debt to fixed rate (4.29%) debt
 
Cash flow
 
119

 
December 2025
Amortizing interest rate swap
 
Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt
 
Cash flow
 
67

 
March 2026



19
Table of Contents

December 31, 2010
 
 
 
 
 
 
 
 
 
Hedging Activities
 
 
 
 
Commodity
 
Instrument
 
Classification
 
Unit of Measure
 
Cash Flow
Hedges
 
 
Economic
Hedges
 
 
Trading
Activities
 
Electricity
 
Forwards/Futures
 
Sales
 
GWh
 
16,799

1
 
22,456

3
 
34,630

 
Electricity
 
Forwards/Futures
 
Purchases
 
GWh
 
408

1
 
22,931

3
 
37,669

 
Electricity
 
Capacity
 
Sales
 
MW-Day
(in thousands)
 
190

2
 
—

 
 
136

2
Electricity
 
Capacity
 
Purchases
 
MW-Day
(in thousands)
 
8

2
 
—

 
 
419

2
Electricity
 
Congestion
 
Sales
 
GWh
 
—

 
 
136

4
 
12,020

4
Electricity
 
Congestion
 
Purchases
 
GWh
 
—

 
 
1,143

4
 
187,689

4
Natural gas
 
Forwards/Futures
 
Sales
 
bcf
 
—

 
 
—

 
 
30.6

 
Natural gas
 
Forwards/Futures
 
Purchases
 
bcf
 
—

 
 
—

 
 
34.3

 
Fuel oil
 
Forwards/Futures
 
Sales
 
barrels
 
—

 
 
250,000

 
 
10,000

 
Fuel oil
 
Forwards/Futures
 
Purchases
 
barrels
 
—

 
 
490,000

 
 
10,000

 
Coal
 
Forwards/Futures
 
Sales
 
tons
 
—

 
 
—

 
 
2,630,500

 
Coal
 
Forwards/Futures
 
Purchases
 
tons
 
—

 
 
—

 
 
2,645,500

 

(in millions)
Instrument
 
Purpose
 
Type of Hedge
 
Notional
Amount
 
Expiration Date
Amortizing interest rate swap
 
Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt
 
Cash flow
 
$
138

 
June 2016
Amortizing forward starting interest rate swap
 
Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt
 
Cash flow
 
122

 
December 2025
Amortizing forward starting interest rate swap
 
Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt
 
Cash flow
 
68

 
March 2026
1 
EMG's hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power contracts for the coal plants which meet the normal purchases and sales exception and are accounted for on the accrual method.
2 
EMG's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM Reliability Pricing Model (RPM) auction is not accounted for as a derivative.
3 
EMG also entered into transactions that adjust financial and physical positions, or day-ahead and real-time positions to reduce costs or increase gross margin. These positions largely offset each other. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.
4 
Congestion contracts include financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.


20
Table of Contents

Fair Value of Derivative Instruments
The following table summarizes the fair value of derivative instruments reflected on EMG's consolidated balance sheets:
September 30, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative Assets
 
Derivative Liabilities
 
Net Assets
(Liabilities)
(in millions)
Short-term
 
Long-term
 
Subtotal
 
Short-term
 
Long-term
 
Subtotal
 
Non-trading activities
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash flow hedges
$
34

 
$
8

 
$
42

 
$
16

 
$
90

 
$
106

 
$
(64
)
Economic hedges
29

 
3

 
32

 
31

 
2

 
33

 
(1
)
Trading activities
132

 
102

 
234

 
96

 
37

 
133

 
101

 
195

 
113

 
308

 
143

 
129

 
272

 
36

Netting and collateral received1
(163
)
 
(54
)
 
(217
)
 
(140
)
 
(49
)
 
(189
)
 
(28
)
Total
$
32

 
$
59

 
$
91

 
$
3

 
$
80

 
$
83

 
$
8

December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-trading activities
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash flow hedges
$
54

 
$
2

 
$
56

 
$
10

 
$
25

 
$
35

 
$
21

Economic hedges
77

 
2

 
79

 
71

 
—

 
71

 
8

Trading activities
184

 
103

 
287

 
148

 
29

 
177

 
110

 
315

 
107

 
422

 
229

 
54

 
283

 
139

Netting and collateral received1
(269
)
 
(37
)
 
(306
)
 
(223
)
 
(35
)
 
(258
)
 
(48
)
Total
$
46

 
$
70

 
$
116

 
$
6

 
$
19

 
$
25

 
$
91

1 
Netting of derivative receivables and derivative payables and the related cash collateral received and paid is permitted when a legally enforceable master netting agreement exists with a derivative counterparty.
Income Statement Impact of Derivative Instruments
The following table provides the cash flow hedge activity as part of accumulated other comprehensive loss:
 
Cash Flow Hedge Activity1
Nine Months Ended
September 30,
 
Income Statement
Location
(in millions)
2011
 
2010
 
Beginning of period derivative gains
$
27

 
$
175

 
 
Effective portion of changes in fair value
(62
)
 
102

 
 
Reclassification to net income
(29
)
 
(134
)
 
Competitive power generation revenue
End of period derivative gains (losses)
$
(64
)
 
$
143

 
 
1 
Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income (loss) at September 30, 2011 and 2010 were $(39) million and $86 million, respectively.
For additional information, see Note 11—Accumulated Other Comprehensive Loss.
The portion of a cash flow hedge that does not offset the change in the value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EMG recorded net gains of $4 million during each of the third quarters of 2011 and 2010, and $6 million and $5 million during the nine months ended September 30, 2011 and 2010, respectively, in operating revenues on the consolidated statements of operations representing the amount of cash flow hedge ineffectiveness.


21
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The effect of realized and unrealized gains (losses) from derivative instruments used for economic hedging and trading purposes on the consolidated statements of operations is presented below:
 
 
 
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
 
Income Statement Location
 
2011
 
2010
 
2011
 
2010
Economic hedges
 
Competitive power generation revenue
 
$
(6
)
 
$
7

 
$
20

 
$
—

 
 
Fuel
 
(3
)
 
2

 
1

 
—

Trading activities
 
Competitive power generation revenue
 
11

 
28

 
68

 
108

Contingent Features
Certain derivative instruments contain margin and collateral deposit requirements. Since EMG's subsidiaries' credit ratings are below investment grade, EMG's subsidiaries have provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties. Future increases in power prices could expose EMG's subsidiaries to additional collateral postings.
Margin and Collateral Deposits
Margin and collateral deposits include cash deposited with counterparties and brokers, and cash received from counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the related positions. Edison International nets counterparty receivables and payables where balances exist under master netting agreements. Edison International presents the portion of its margin and collateral deposits netted with its derivative positions on its consolidated balance sheets. The following table summarizes margin and collateral deposits provided to and received from counterparties:
(in millions)
September 30,
2011
 
December 31,
2010
Collateral provided to counterparties:
 
 
 
Offset against derivative liabilities
$
16

 
$
8

Reflected in margin and collateral deposits
53

 
65

Collateral received from counterparties:
 
 
 
Offset against derivative assets
30

 
52

Note 7. Income Taxes
Effective Tax Rate
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations.
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Income from continuing operations before income taxes
$
683

 
$
774

 
$
1,217

 
$
1,386

Provision for income tax at federal statutory rate of 35%
239

 
271

 
426

 
485

Increase (decrease) in income tax from:
 
 
 
 
 
 
 
Items presented with related state income tax, net:
 
 
 
 
 
 
 
Global Settlement related1
—

 
(37
)
 
—

 
(175
)
Change in tax accounting method for asset removal costs2
—

 
—

 
—

 
(40
)
State tax – net of federal benefit
30

 
34

 
43

 
57

Health care legislation3
—

 
—

 
—

 
39

Production and housing credits
(12
)
 
(14
)
 
(48
)
 
(48
)
Property-related and other
(15
)
 
(7
)
 
(52
)
 
(57
)
Total income tax expense from continuing operations
$
242

 
$
247

 
$
369

 
$
261

Effective tax rate
35
%
 
32
%
 
30
%
 
19
%
1 
During the nine months ended September 30, 2010, Edison International recognized a $175 million earnings benefit resulting from the


22
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Global Settlement, including $138 million in the second quarter resulting from the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service ("IRS") in 2009 and revision to interest recorded on the federal Global Settlement, and $37 million in the third quarter resulting from receipt of the final interest determination from the California Franchise Tax Board.
2 
During the second quarter of 2010, the IRS approved Edison International's request to change its tax accounting method for asset removal costs primarily related to SCE's infrastructure replacement program. As a result, Edison International recognized a $40 million earnings benefit (of which $28 million relates to asset removal costs incurred prior to 2010) from deducting asset removal costs earlier in the construction cycle. These deductions were recorded on a flow-through basis.
3 
During the first quarter of 2010, Edison International recorded a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.
The CPUC requires flow-through ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.
Accounting for Uncertainty in Income Taxes
Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination. The guidance requires the disclosure of all unrecognized tax benefits, which includes both the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims.
Unrecognized Tax Benefits
The following table provides a reconciliation of unrecognized tax benefits:
(in millions)
2011
 
2010
Balance at January 1,
$
565

 
$
664

Tax positions taken during the current year:
 
 
 
Increases
53

 
60

Tax positions taken during a prior year:
 
 
 
Increases
60

 
251

Decreases
(37
)
 
(86
)
Decreases for settlements during the period
—

 
(82
)
Balance at September 30,
$
641

 
$
807

As of September 30, 2011 and December 31, 2010, $500 million and $455 million, respectively, of the unrecognized tax benefits, if recognized, would impact the effective tax rate.
Edison International's federal income tax returns and its California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 are currently under review by the Franchise Tax Board. The IRS examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included proposed adjustments for the following two items:
•
A proposed adjustment increasing the taxable gain on the 2004 sale of EMG's international assets, which if sustained, would result in a federal tax payment of approximately $191 million, including interest and penalties through September 30, 2011 (the IRS has asserted a 40% penalty for understatement of tax liability related to this matter).
•
A proposed adjustment to disallow a component of SCE's repair allowance deduction, which if sustained, would result in a federal tax payment of approximately $92 million, including interest through September 30, 2011.
Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011.
Accrued Interest and Penalties
The total amount of accrued interest and penalties related to Edison International's income tax liabilities was $230 million and $213 million as of September 30, 2011 and December 31, 2010, respectively.
The net after-tax interest and penalties recognized in income tax expense was $5 million and $10 million for the three- and


23
Table of Contents

nine-month periods ended September 30, 2011, respectively, compared to a benefit of $7 million and $95 million for the same periods in 2010.
Note 8. Compensation and Benefit Plans
Pension Plans and Postretirement Benefits Other Than Pensions
Pension Plans
During the nine months ended September 30, 2011, Edison International made contributions of $113 million and during the remainder of 2011, expects to make $30 million of additional contributions. In 2011, annual contributions made to most of SCE's pension plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.
Expense components are:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Service cost
$
43

 
$
34

 
$
129

 
$
102

Interest cost
52

 
54

 
156

 
162

Expected return on plan assets
(60
)
 
(52
)
 
(180
)
 
(156
)
Amortization of prior service cost
2

 
2

 
6

 
6

Amortization of net loss
6

 
7

 
18

 
21

Expense under accounting standards
43

 
45

 
129

 
135

Regulatory adjustment – deferred
(6
)
 
(14
)
 
(18
)
 
(42
)
Total expense recognized
$
37

 
$
31

 
$
111

 
$
93

Postretirement Benefits Other Than Pensions
During the nine months ended September 30, 2011, Edison International made contributions of $18 million and during the remainder of 2011, expects to make $38 million of additional contributions. Annual contributions made to SCE's plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.
Expense components are:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Service cost
$
11

 
$
8

 
$
33

 
$
24

Interest cost
33

 
31

 
99

 
93

Expected return on plan assets
(28
)
 
(25
)
 
(84
)
 
(75
)
Amortization of prior service credit
(9
)
 
(9
)
 
(27
)
 
(27
)
Amortization of net loss
9

 
8

 
27

 
24

Total expense
$
16

 
$
13

 
$
48

 
$
39



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Stock-Based Compensation
During 2011, Edison International granted stock-based compensation awards, which included stock options, performance shares and restricted stock units.
Stock Options
The following is a summary of the status of Edison International stock options:
 
 
 
Weighted-Average
 
 
 
Stock options
 
Exercise
Price
 
Remaining
Contractual
Term (Years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding at December 31, 2010
19,142,209

 
$
33.28

 
 

 
 

Granted
3,394,229

 
37.95

 
 

 
 

Expired
(113,348
)
 
48.52

 
 

 
 

Forfeited
(369,267
)
 
33.03

 
 

 
 

Exercised
(1,557,548
)
 
26.22

 
 

 
 

Outstanding at September 30, 2011
20,496,275

 
34.51

 
6.07

 
 

Vested and expected to vest at September 30, 2011
20,021,144

 
34.53

 
6.02

 
$
123

Exercisable at September 30, 2011
12,043,993

 
34.93

 
4.52

 
84

At September 30, 2011, there was $23 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately three years.
Performance Shares
The following is a summary of the status of Edison International nonvested performance shares:
 
Equity Awards
 
Liability Awards
 
Shares
 
Weighted-Average
Grant Date
Fair Value
 
Shares
 
Weighted-Average
Fair Value
Nonvested at December 31, 2010
415,028

 
$
30.99

 
415,028

 
$
34.74

Granted
153,067

 
30.19

 
153,067

 
 

Forfeited1
(119,835
)
 
42.64

 
(119,835
)
 
 

Nonvested at September 30, 2011
448,260

 
27.96

 
448,260

 
23.26

1 Includes performance shares that expired with zero value as performance targets were not met.
The current portion of nonvested performance shares classified as liability awards is reflected in "Other current liabilities" and the long-term portion is reflected in "Pensions and benefits" on the consolidated balance sheets.
At September 30, 2011, there was $5 million of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately two years.
Restricted Stock Units
The following is a summary of the status of Edison International nonvested restricted stock units:
 
Restricted
Stock Units
 
Weighted-Average
Grant Date
Fair Value
Nonvested at December 31, 2010
644,796

 
$
32.18

Granted
251,890

 
37.95

Forfeited
(27,114
)
 
32.05

Paid Out
(133,958
)
 
47.60

Nonvested at September 30, 2011
735,614

 
$
32.15



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At September 30, 2011, there was $10 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $2 million in 2011, $5 million in 2012 and $3 million in 2013.
Supplemental Data on Stock Based Compensation
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Stock based compensation expense1
$
8

 
$
9

 
$
25

 
$
26

Income tax benefits related to stock compensation expense
3

 
3

 
10

 
10

Excess tax benefits2
3

 
3

 
7

 
5

Stock options
 
 
 
 
 
 
 
Cash used to purchase shares to settle options
20

 
17

 
59

 
30

Cash from participants to exercise stock options
16

 
10

 
41

 
19

Value of options exercised
4

 
7

 
18

 
11

Restricted stock units
 
 
 
 
 
 
 
Value of shares settled
1

 
—

 
6

 
—

Tax benefits realized from settlement of awards
—

 
—

 
2

 
—

1
Reflected in "Operations and maintenance" on the consolidated statements of income.
2
Reflected in "Settlements of stock based compensation—net" in the financing section of the consolidated statements of cash flows.
Note 9. Commitments and Contingencies
Third-Party Power Purchase Agreements
During the nine months ended September 30, 2011, additional renewable energy power purchase contracts became effective and were classified as operating leases. SCE's additional commitments under these contracts are estimated to be: $116 million each year in 2012 – 2015 and $1.9 billion for the period remaining thereafter.
In October 2011, SCE completed its 2011 annual request for offers and entered into new power purchase contracts with commitments estimated to be: $5 million in 2012, $81 million in 2013, $178 million in 2014 and $240 million in 2015.
Other Commitments
Firm Transmission Commitments
During the nine months ended September 30, 2011, SCE had a firm transmission agreement with additional commitments estimated to be: $1 million in 2011, $4 million each year in 2012 – 2015 and $78 million for the period remaining thereafter.
Fuel Supply Contracts and Coal Transportation Agreements
At September 30, 2011, Midwest Generation and EME Homer City Generation L.P. ("Homer City") had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses. These commitments, together with estimated transportation costs under existing agreements, are estimated to aggregate $925 million, which consists of: $245 million for the remainder of 2011, $332 million in 2012, $198 million in 2013 and $150 million in 2014.
Turbine Commitments
Based upon a June 2011 contract amendment, EMG was required to schedule turbine deliveries by September 2011 or incur a termination obligation equal to its turbine deposit of $29 million. Under the terms of a September 2011 contract amendment, EMG scheduled turbine deliveries for the Broken Bow I wind project which will utilize the $29 million turbine deposit. In October 2011, EMG entered into a contractual agreement for the purchase of additional turbines with commitments of $39 million through 2012 for the Crofton Bluffs wind project.
On October 8, 2010, an agreement was reached to settle disputes included in the complaint filed by EMG against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. As a result of this agreement, EMG may elect to deploy up to 60 additional wind turbines (aggregating 144 MW)


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that were part of the original contract, or may be obligated to make a payment of up to $30 million following the end of the three-year period, which commenced on October 8, 2010, if it has not elected to deploy the additional turbines and if certain other criteria apply.
Capital Commitments
At September 30, 2011, EMG's subsidiaries had firm commitments to spend approximately $157 million during the remainder of 2011, $235 million in 2012 and $19 million in 2013 for capital expenditures. These expenditures primarily relate to the Walnut Creek project and the construction of wind projects. EMG intends to fund these expenditures through project level financing, U.S. Treasury grants, Midwest Generation and EME lines of credit, if available, cash on hand and cash generated from operations.
Guarantees and Indemnities
Edison International's subsidiaries have various financial and performance guarantees and indemnity agreements which are issued in the normal course of business. The contracts discussed below included performance guarantees.
Environmental Indemnities Related to the Midwest Generation Plants
In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison Company ("Commonwealth Edison") with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification obligations are reduced by any insurance proceeds and tax benefits related to such indemnified claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. Also, in connection with the sale-leaseback transaction related to the Powerton and Joliet Stations in Illinois, EME agreed to indemnify the lessors for specified environmental liabilities. These indemnities are not limited in term or amount. Due to the nature of the obligations under these indemnities, a maximum potential liability cannot be determined. Commonwealth Edison has advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the litigation discussed below under "—Contingencies—Midwest Generation New Source Review and Other Litigation." Except as discussed below, EME has not recorded a liability related to these environmental indemnities.
Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of Midwest Generation's reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2012. There were approximately 230 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at September 30, 2011. Midwest Generation had recorded a liability of $55 million at September 30, 2011 related to this contractual indemnity.
The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than projected.
Environmental Indemnity Related to the Homer City Plant
In connection with the acquisition of the Homer City plant, Homer City agreed to indemnify the sellers with respect to specified environmental liabilities before and after the date of sale. EME guaranteed this obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City plant, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnity provisions, they are not subject to a maximum potential liability and do not have expiration dates. EME has not recorded a liability related to this indemnity. For discussion of the New Source Review lawsuit filed against Homer City, see "—Contingencies—Homer City New Source Review and Other Litigation."
Indemnities Provided under Asset Sale and Sale-Leaseback Agreements
The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental


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liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. At September 30, 2011, EME had recorded a liability of $43 million related to these matters.
In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the assets prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Not all indemnities under the asset sale agreements have specific expiration dates. Due to the nature of these potential obligations, a maximum potential liability cannot be determined and has not been recorded as a liability related to these indemnities.
In connection with the sale-leaseback transactions related to the Homer City plant in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Under these tax indemnity agreements, the lessees in the sale-leaseback transactions agreed to indemnify the lessors for specified adverse tax consequences that could result from certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. Although the Collins Station lease terminated in April 2004, Midwest Generation's indemnities in favor of its former lease equity investors are still in effect. EME provided similar indemnities in the sale-leaseback transactions related to the Powerton and Joliet Stations in Illinois. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability for these matters.
EME agreed to indemnify the lessors in the sale-leaseback transaction related to the Homer City plant for certain negative federal income tax consequences should the rent payments be “levelized” for tax purposes and for potential foreign tax credit losses in the event that the lessor's debt is characterized as recourse, rather than non-recourse. This indemnity covers a limited range of possible tax consequences that are unrelated to performance under the lease.

Indemnity Provided as Part of the Acquisition of Mountainview
In connection with the acquisition of the Mountainview power plant, SCE agreed to indemnify the seller with respect to specific environmental claims related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilities with respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.
Mountainview Filter Cake Indemnity
The Mountainview power plant utilizes water from on-site groundwater wells and City of Redlands ("City") recycled water for cooling purposes. Unrelated to the operation of the plant, the groundwater contains perchlorate. The pumping of the water removes perchlorate from the aquifer beneath the plant and concentrates it in the plant's wastewater treatment "filter cake." Use of this impacted groundwater for cooling purposes was mandated by Mountainview's California Energy Commission permit. SCE has indemnified the City for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this indemnity.
Other Edison International Indemnities
Edison International provides other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and indemnities for specified environmental liabilities and income taxes with respect to assets sold. Edison International's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances Edison International may have recourse against third parties. Edison International has not recorded a liability related to these indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.
Contingencies
In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.


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Midwest Generation New Source Review and Other Litigation
In August 2009, the United States Environmental Protection Agency ("US EPA") and the State of Illinois filed a complaint in the Northern District of Illinois alleging that Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration ("PSD") requirements and of the New Source Performance Standards of the Clean Air Act ("CAA"), including alleged requirements to obtain a construction permit and to install controls sufficient to meet best available control technology ("BACT") emission rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at all units subject to the complaint; to obtain new PSD or New Source Review permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies sought by the plaintiffs in the lawsuit could go well beyond the requirements of the Combined Pollutant Standard ("CPS"). Several Chicago-based environmental action groups have intervened in the case.
Nine of ten PSD claims have been dismissed, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court has also dismissed all claims asserted against Commonwealth Edison and EME. The court denied a motion to dismiss a claim by the Chicago-based environmental action groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the court that the statute of limitations should be equitably tolled. The court did not address other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA. Trial of the liability portion of the case is scheduled to commence June 3, 2013. A motion filed by the plaintiffs requesting that the dismissals be certified as “partial final judgments” capable of appeal, and requesting that the remaining claims be stayed pending such an appeal, is pending.
In May 2011, two complaints were filed against Midwest Generation in the Northern District of Illinois by residents living near the Crawford and Fisk facilities on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs sought to have their suits certified as a class action and requested injunctive relief, as well as compensatory and punitive damages. In October 2011, the complaints were dismissed for lack of federal jurisdiction. EME does not know whether the plaintiffs will appeal the dismissal or file a complaint in state court.
Adverse decisions in these cases could involve penalties and remedial actions that could have a material impact on the financial condition and results of operations of Midwest Generation and EME. EME cannot predict the outcome of these matters or estimate the impact on the Midwest Generation plants, or its and Midwest Generation's results of operations, financial position or cash flows.
Homer City New Source Review and Other Litigation
In January 2011, the US EPA filed a complaint in the Western District of Pennsylvania against Homer City, the sale-leaseback owner participants of the Homer City plant, and two prior owners of the Homer City plant. The complaint alleged violations of the PSD and Title V provisions of the CAA, as a result of projects in the 1990s performed by prior owners without PSD permits and the subsequent failure to incorporate emissions limitations that meet BACT into the station's Title V operating permit. In addition to seeking penalties ranging from $32,500 to $37,500 per violation, per day, the complaint called for an injunction ordering Homer City to install controls sufficient to meet BACT emission rates at all units subject to the complaint and for other remedies. The Pennsylvania Department of Environmental Protection, the State of New York and the State of New Jersey intervened in the lawsuit.
Also in January 2011, two residents filed a complaint in the Western District of Pennsylvania, on behalf of themselves and all others similarly situated, against Homer City, the sale-leaseback owner participants of the Homer City plant, two prior owners of the Homer City plant, EME, and Edison International, claiming that emissions from the Homer City plant had adversely affected their health and property values. The plaintiffs sought to have their suit certified as a class action and requested injunctive relief, the funding of a health assessment study and medical monitoring, as well as compensatory and punitive damages.
On October 12, 2011, all of the claims in the US EPA's lawsuit were dismissed with prejudice. On October 13, 2011, the claims in the purported class action lawsuit that were based on the federal CAA were dismissed with prejudice, while state law statutory and common law claims were dismissed without prejudice to re-file in state court should the plaintiffs choose to do so. EME does not know whether the US EPA and the other plaintiffs in these cases will appeal the dismissal of these cases, or whether plaintiffs in the purported class action lawsuit will file a complaint in state court. If the plaintiffs are able to revive the


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lawsuits, adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material impact on the financial condition and results of operations of Homer City and EME.
Four Corners New Source Review Litigation
In October 2011, four private environmental organizations filed a CAA citizens' lawsuit against the co-owners of Four Corners. The complaint alleges that certain work performed at the Four Corners generating units 4 and 5, over the approximate periods of 1985-1986 and 2007-present, constituted plant “major modifications” for which the plant should have, but did not, obtain permits and install BACT in violation of the PSD requirements and of the New Source Performance Standards of the CAA. The complaint also alleges subsequent and continuing violation of BACT air emissions limits. The lawsuit seeks injunctive and declaratory relief, civil penalties, including a mitigation project and litigation costs. In November 2010, SCE entered into an agreement to sell its ownership interest in generating units 4 and 5 to APS. The sale is subject to regulatory approvals and is expected to close in late 2012. Under the agreement SCE would remain responsible for its pro rata share of certain environmental liabilities, including penalties arising from environmental violations prior to the sale, but SCE would not be liable for any costs of installing BACT or other costs related to continuing or extending Four Corners operations. SCE cannot predict the outcome of these matters or estimate the impact on its financial statements.
Concurrently, the US EPA has proposed a regional haze federal implementation plan based on an APS proposal that would require shut down of units 1, 2 and 3 by 2016 and the installation of selective catalytic reduction technology on units 4 and 5 by 2018. APS' proposal contemplated that these actions would both satisfy the federal regional haze requirements and resolve any New Source Review claims the US EPA might have. A final federal implementation plan is expected in early 2012.
Malibu Fire Order Instituting Investigation ("OII")
Following a 2007 wildfire in Malibu, California, the CPUC issued an OII to determine if any statutes, CPUC general orders, rules or regulations were violated by SCE or telecomm providers (“OII Respondents”) that shared the use of three failed power poles in the wildfire area. The CPUC's Consumer Protection and Safety Division (“CPSD”) has alleged, among other things, that the poles were overloaded, that the OII Respondents violated the CPUC's rules governing the design, construction and inspection of poles and misled the CPUC during its investigation of the fire, and that SCE failed to preserve evidence relevant to the investigation. In October 2011, the CPSD proposed that the OII Respondents be assessed penalties of approximately $99 million, with SCE being allocated approximately $50 million of the total. SCE has denied the allegations and believes the proposed penalties are excessive. CPSD's allegations will likely be set for hearing in the first quarter of 2012. SCE cannot predict the amount, if any, of penalties that the CPUC may ultimately impose on SCE.
Navajo Nation Litigation
On August 1, 2011, SCE and the other defendants entered into a comprehensive settlement with the Navajo Nation of the litigation filed in June 1999 against SCE and others concerning royalty payments to the Navajo for the coal supplied to the Mohave Generating Station. Pursuant to the settlement, the Navajo Nation lawsuit was dismissed. The settlement agreement reached with the Navajo Nation did not have a material impact on SCE's financial statements.
Environmental Remediation
Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a single probable amount, Edison International records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.
As of September 30, 2011, Edison International's recorded estimated minimum liability to remediate its 27 identified material sites (sites in which the upper end of the range of costs is at least $1 million) at SCE (24 sites) and EMG (3 sites primarily related to Midwest Generation) was $60 million, of which $51 million was related to SCE, including $15 million related to San Onofre. In addition to its identified material sites, SCE also has 33 immaterial sites for which the total minimum recorded liability was $3 million. The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs at these


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identified material sites and immaterial sites could exceed its recorded liability by up to $195 million and $7 million, respectively, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes.
The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $32 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). In addition, SCE expects to recover 100% of environmental remediation costs incurred at the majority of the remaining sites through customer rates, representing $18 million of its recorded liability. SCE has recorded a regulatory asset of $50 million at September 30, 2011 for its estimated minimum environmental cleanup costs expected to be recovered through customer rates.
Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $7 million to $17 million. Costs incurred for the nine months ended September 30, 2011 and 2010, were $9 million and $7 million, respectively.
Based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $12.6 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($375 million). The balance is covered by a loss sharing program among nuclear reactor licensees. If a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site, all nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.
Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately $35 million per incident in any one year. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.
Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $48 million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the Department of Energy ("DOE") is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to begin acceptance of spent nuclear fuel by January 31, 1998. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim storage for spent nuclear fuel on site sufficient for the current license period.
In June 2010, the United States Court of Federal Claims issued a decision granting SCE and its co-owners damages of approximately $142 million to recover costs incurred through December 31, 2005 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. The DOE's appeal of the decision was denied in August 2011. Additional legal action would be necessary to recover damages incurred after December 31, 2005. Any damages recovered are subject to CPUC review as to what amounts would be returned to SCE ratepayers or used to offset past or future fuel decommissioning or storage costs for the benefit of ratepayers.


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Note 10. Regulatory and Environmental Developments
Environmental Developments
Cross-State Air Pollution Rule
On July 6, 2011, the US EPA adopted the Cross-State Air Pollution Rule ("CSAPR"). CSAPR is the final form of a previously proposed replacement for the Clean Air Interstate Rule ("CAIR"), originally called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual sulfur dioxide ("SO2") emissions and annual and ozone season nitrogen oxide ("NOx") emissions in two phases: a first phase effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO2 emissions.
CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO2 or NOx emissions from operations will need to be matched by a sufficient amount of SO2 or NOx allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO2 and NOx allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual or seasonal compliance period, units must surrender allowances for each ton of SO2 and NOx emitted or face penalties. While trading of allowances is permitted within designated groups of states, the rule provides for penalties against a unit with emissions in excess of its predefined "assurance level," but only if the state in which it is located also exceeds its budgeted emissions level. On October 6, 2011, the US EPA announced a proposed revision to the rule that would effectively eliminate such penalties in the first phase.
EMG believes that Midwest Generation's current environmental remediation plan developed to comply with the CPS, along with the allowances allocated to it under CSAPR, will be sufficient to comply with the requirements of CSAPR and the US EPA's proposed regulation on hazardous air pollutant emissions. In order to achieve compliance, Midwest Generation has begun work to install SO2 controls at certain of its plants.
The SO2 allowances allocated to Homer City in CSAPR Phase I (25,797 tons in 2012 and 2013) are significantly lower than the amount that would be required based on Homer City's historical emissions (2010 SO2 emissions were 112,951 tons). Therefore, pending installation of additional equipment for Units 1 and 2 (Homer City's Unit 3 is equipped with a wet scrubber flue gas desulfurization system to meet environmental standards), Homer City expects that it will be required to procure additional allowances. It is unclear at this time whether Homer City will be able to acquire allowances for 2012 and 2013 in sufficient quantity to cover its normal operations and whether it will be able to pass through the cost of such allowances in the marketplace. Also, Homer City's SO2 emissions could exceed its assurance level, and, therefore, unless the proposed revision to the rule is adopted, Homer City could be subject to penalties depending on whether, collectively, emissions from all of the subject electrical generating facilities in Pennsylvania exceed the state's budgeted emissions level. Accordingly, Homer City is evaluating alternative options, including reduced dispatch and fuel modifications, for complying with Phase I of CSAPR. The cost of allowances, together with possible operational impacts or reductions of output that may be required to comply with Phase I of CSAPR, could have a material effect on Homer City.
Homer City has begun work on designing SO2 and particulate emissions control equipment for Units 1 and 2. While the Phase II SO2 emission allowances under CSAPR (11,068 tons) are less than were contemplated under the proposed Clean Air Transport Rule, the additional reductions are not expected to materially change the design for the SO2 controls at Units 1 and 2. The installation of those SO2 controls will require capital commitments for the Homer City plant well in advance of the 2014 effective date, including some expenditures in 2011, in order to meet regulatory deadlines. Given the relatively short period of time before Phase II of CSAPR takes effect in 2014, there is no assurance that Homer City will be able to complete all the work that will be required before the deadline. Homer City is continuing to review technologies available to reduce SO2 and mercury emissions; however, it has not determined the most effective and efficient technology to meet all requirements that may be imposed on it. Consequently, the timing, selection of technology and ultimate capital costs remain uncertain. Based on preliminary estimates, Homer City currently believes the cost of such equipment may be between $600 million and $700 million. An application for a construction permit to install the additional controls was filed on October 3, 2011 with the Pennsylvania Department of Environmental Protection.
Homer City does not currently have sufficient capital and does not expect to generate sufficient funds from operations to complete such retrofits and will have to seek third-party financing, which will be subject to decisions by Homer City's lessors, holders of bonds who provided financing for the sale-leaseback transaction and new providers of capital funding. There is no assurance that sufficient financing will be obtained or will not result in significant dilution of Homer City's interest in the Homer City plant.
In July 2011, EME asked the US EPA to stay the effectiveness of CSAPR pending judicial review, and in October 2011, Homer


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City asked the US EPA to reconsider the rule. In August 2011, Homer City asked the United States Court of Appeals for the District of Columbia to review CSAPR and requested a stay of the rule while its motion is pending. Numerous similar challenges have been filed by other industry participants and by several states.
Proposed Hazardous Air Pollutant Regulations
In March 2011, the US EPA proposed National Emission Standards for Hazardous Air Pollutants, limiting emissions of hazardous air pollutants from coal- and oil-fired electrical generating units. This regulation is expected to be finalized by December 2011. Based on its continuing review, EMG does not expect that these standards, if adopted as proposed, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. EMG also does not expect that these standards, if adopted as proposed, would require Homer City to make additional capital requirements beyond those that would be required to comply with CSAPR.
Ozone and Particulates
In September 2011, President Obama announced that the proposed revision to the National Ambient Air Quality Standards ("NAAQS") for ozone, which was expected to have set a more stringent standard for primary ozone and a distinct secondary standard to protect sensitive vegetation and ecosystems, was being withdrawn. The ozone NAAQS established in 2008 remains in place, but the implementation process must be completed before the 0.075 parts-per-million standard can be enforced. The US EPA has indicated that it intends to issue initial area designations of attainment, nonattainment, and unclassifiable areas across the nation in 2012. States will then be required develop and submit state implementation plans outlining how compliance with the 2008 NAAQS will be achieved. New primary and secondary ozone standards are expected in 2014.
Water Quality
Once-Through Cooling Issues
In March 2011, the US EPA proposed standards under the federal Clean Water Act which would affect cooling water intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). The regulations are expected to be finalized by July 2012. Edison International is evaluating the proposed standards and believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable for both the Midwest Generation plants and the Homer City plant without incurring material additional capital expenditures or operating costs. The required measures to comply with the proposed standards regarding entrainment are subject to the discretion of the permitting authority, and Edison International is unable at this time to assess potential costs of compliance, which could be significant for the Midwest Generation plants and San Onofre, but are not expected to be material for the Homer City plant, which already has cooling towers.
In addition to the proposed draft US EPA standards, the existing California once-through cooling policy may result in significant capital expenditures at San Onofre and may affect its operations. If other coastal power plants in California that rely on once-through cooling are forced to shut down or limit operations, the California policy may also significantly impact SCE's ability to procure generating capacity from those plants, which could have an adverse effect on system reliability and the cost of electricity.
Greenhouse Gas Regulation
California Air Resources Board's ("CARB") regulations implementing a California cap-and-trade program continue to be the subject of litigation. In June 2011, the CARB announced that initial cap-and-trade program compliance for the electricity sector would be delayed until January 2013.
In April 2011, California enacted a law requiring California utilities to procure 33% of their electricity requirements from renewable resources, as defined in the statute. The impact of the new 33% law will depend on how the CPUC and CEC implement the law, which remains uncertain.
Greenhouse Gas Litigation Developments
In June 2011, the U.S. Supreme Court dismissed public nuisance claims against five power companies, ruling that the CAA and the US EPA actions it authorizes displace federal common law nuisance claims that might arise from the emission of greenhouse gases. The court also affirmed the Second Circuit's determination that at least some of the plaintiffs had standing to bring the case. The court did not address whether the CAA also preempts state law claims arising from the same circumstances.
Parties to the case brought by the Alaskan Native Village of Kivalina against Edison International and other defendants, the


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appeal of which was deferred before the Ninth Circuit Court of Appeals pending the Supreme Court's ruling described above, have requested that the appeal recommence and have asked for permission to file additional briefs on the impact of the Supreme Court's ruling. The stay of the appeal has now been lifted and argument before the Ninth Circuit is scheduled for November 2011. Kivalina is seeking damages of up to $400 million for the cost of relocating the village.
On May 27, 2011, private citizens filed a purported class action complaint in the United States District Court for the Southern District of Mississippi, naming among a large number of defendants, Edison International and its subsidiaries, including SCE and EME. Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of greenhouse gases that have contributed to climate change and sea level rise, which in turn are alleged to have increased the destructive force of Hurricane Katrina. The lawsuit alleges causes of action for negligence, public and private nuisance, and trespass, and seeks unspecified compensatory and punitive damages. The claims in this lawsuit are nearly identical to a subset of the claims that were raised against many of the same defendants in a previous lawsuit that was filed in, and dismissed by, the same federal district court where the current case has been filed. Edison International was dismissed as a defendant in this complaint in July 2011, but SCE and EME remain defendants.
Note 11. Accumulated Other Comprehensive Loss
Edison International's accumulated other comprehensive loss consists of:
(in millions)
Unrealized
Gain (Loss)
on Cash
Flow Hedges
 
Pension and
PBOP – Net
Gain
(Loss)
 
Pension and
PBOP – Prior
Service Cost
 
Accumulated
Other
Comprehensive
Loss
Balance at December 31, 2010
$
16

 
$
(87
)
 
$
(5
)
 
$
(76
)
Current period change
(55
)
 
7

 
—

 
(48
)
Balance at September 30, 2011
$
(39
)
 
$
(80
)
 
$
(5
)
 
$
(124
)
Included in accumulated other comprehensive loss at September 30, 2011 was $10 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $49 million, net of tax, of unrealized losses related to interest rate hedges. The maximum period over which a commodity cash flow hedge is designated is May 31, 2014.
Unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. Approximately $11 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenues recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.


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Note 12. Supplemental Cash Flows Information
Edison International's supplemental cash flows information is:
 
Nine months ended
September 30,
(in millions)
2011
 
2010
Cash payments (receipts) for interest and taxes:
 
 
 
Interest – net of amounts capitalized
$
529

 
$
486

Tax payments (refunds) – net
(330
)
 
44

Noncash investing and financing activities:
 
 
 
Accrued capital expenditures
$
393

 
$
421

Details of debt exchange:
 
 
 
Pollution-control bonds redeemed
$
(86
)
 
$
(303
)
Pollution-control bonds issued
86

 
303

Consolidation of variable interest entities:
 
 
 
Assets other than cash
$
—

 
$
(94
)
Liabilities and noncontrolling interests
—

 
99

Deconsolidation of variable interest entities:
 
 
 
Assets other than cash
$
—

 
$
380

Liabilities and noncontrolling interests
—

 
(476
)
Dividends declared but not paid:
 
 
 
Common stock
$
104

 
$
103

Preferred and preference stock
12

 
9

Note 13. Preferred and Preference Stock of Utility
In March 2011, SCE issued 1,250,000 shares of 6.5% Series D preference stock (cumulative, $100 liquidation value). The Series D preference stock may not be redeemed prior to March 1, 2016. After March 1, 2016, SCE may, at its option, redeem the shares, in whole or in part for a price of $100 per share plus accrued and unpaid dividends, if any. These shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used for general corporate purposes.


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Note 14. Regulatory Assets and Liabilities
Regulatory assets included on the consolidated balance sheets are:
(in millions)
September 30,
2011
 
December 31,
2010
Current:
 
 
 
Regulatory balancing accounts
$
191

 
$
213

Energy derivatives
262

 
162

Other
1

 
3

Total Current
454

 
378

Long-term:
 
 
 
Deferred income taxes – net
1,938

 
1,855

Pensions and other postretirement benefits
1,084

 
1,097

Unamortized generation investment – net
323

 
355

Unamortized loss on reacquired debt
253

 
268

Energy derivatives
214

 
177

Nuclear-related investment – net
160

 
154

Unamortized transmission and distribution investment – net
153

 
105

Regulatory balancing accounts
62

 
56

Other
299

 
280

Total Long-term
4,486

 
4,347

Total Regulatory Assets
$
4,940

 
$
4,725


Regulatory liabilities included on the consolidated balance sheets are:
(in millions)
September 30,
2011
 
December 31,
2010
Current:
 
 
 
Regulatory balancing accounts
$
728

 
$
733

Other
6

 
5

Total Current
734

 
738

Long-term:
 
 
 
Costs of removal
2,663

 
2,623

Asset Retirement Obligations
944

 
1,099

Regulatory balancing accounts
873

 
802

Other
1

 
—

Total Long-term
4,481

 
4,524

Total Regulatory Liabilities
$
5,215

 
$
5,262



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Note 15. Other Investments
Nuclear Decommissioning Trusts
Future decommissioning costs of removal of nuclear assets are expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately $23 million per year included in SCE customer rates. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through customer rates. Funds collected, together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.
The following table sets forth amortized cost and fair value of the trust investments:
 
 
 
Amortized Cost
 
Fair Value
(in millions)
Longest
Maturity Dates
 
September 30,
2011
 
December 31,
2010
 
September 30,
2011
 
December 31,
2010
Stocks
—
 
$
861

 
$
895

 
$
1,721

 
$
2,029

Municipal bonds
2051
 
644

 
706

 
767

 
790

U.S. government and agency securities
2041
 
445

 
270

 
501

 
288

Corporate bonds
2054
 
266

 
288

 
318

 
346

Short-term investments and receivables/payables
One-year
 
81

 
26

 
86

 
27

Total
 
 
$
2,297

 
$
2,185

 
$
3,393

 
$
3,480

Trust fund earnings (based on specific identification) increase the trust fund balance and the asset retirement obligations ("ARO") regulatory liability. Proceeds from sales of securities (which are reinvested) were $962 million and $302 million for the three months ended September 30, 2011 and 2010, respectively, and $2.1 billion and $903 million for the nine months ended September 30, 2011 and 2010, respectively. Unrealized holding gains, net of losses, were $1.1 billion and $1.3 billion at September 30, 2011 and December 31, 2010, respectively.
The following table sets forth a summary of changes in the fair value of the trust:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Balance at beginning of period
$
3,657

 
$
3,083

 
$
3,480

 
$
3,140

Realized gains – net
41

 
14

 
76

 
48

Unrealized gains (losses) – net
(305
)
 
233

 
(199
)
 
90

Other-than-temporary impairments
(22
)
 
(5
)
 
(35
)
 
(16
)
Interest, dividends, contributions and other
22

 
22

 
71

 
85

Balance at end of period
$
3,393

 
$
3,347

 
$
3,393

 
$
3,347

Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on operating revenue or earnings.


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Note 16. Other Income and Expenses
Other income and expenses are as follows:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Other income:
 
 
 
 
 
 
 
Equity Available Funds Used During Construction
$
18

 
$
24

 
$
74

 
$
76

Increase in cash surrender value of life insurance policies
6

 
7

 
19

 
19

Other
2

 
2

 
10

 
8

Total utility other income
26

 
33

 
103

 
103

Competitive power generation and other income
1

 
—

 
7

 
—

Total other income
$
27

 
$
33

 
$
110

 
$
103

Other expenses:
 
 
 
 
 
 
 
Civic, political and related activities and donations
$
6

 
$
7

 
$
21

 
$
21

Other
4

 
3

 
14

 
18

Total utility other expenses
10

 
10

 
35

 
39

Competitive power generation and other expenses
1

 
2

 
2

 
—

Total other expenses
$
11

 
$
12

 
$
37

 
$
39

Note 17. Business Segments
Edison International has two business segments for financial reporting purposes: an electric utility operation segment (SCE) and a competitive power generation segment (EMG). The significant accounting policies of the segments are the same as those described in Note 1.
Reportable Segments Information
The following is information (including the elimination of intercompany transactions) related to Edison International's reportable segments:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Operating Revenue:
 
 
 
 
 
 
 
Electric utility
$
3,386

 
$
3,098

 
$
8,063

 
$
7,504

Competitive power generation
596

 
691

 
1,686

 
1,838

Parent and other2
(1
)
 
(1
)
 
(3
)
 
(2
)
Consolidated Edison International
$
3,981

 
$
3,788

 
$
9,746

 
$
9,340

Net Income (Loss) attributable to Edison International:
 
 
 
 
 
 
 
Electric utility
$
406

 
$
394

 
$
838

 
$
858

Competitive power generation1
33

 
110

 
(17
)
 
214

Parent and other2
(13
)
 
6

 
(19
)
 
18

Consolidated Edison International
$
426

 
$
510

 
$
802

 
$
1,090



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Segment balance sheet information was:
(in millions)
September 30,
2011
 
December 31,
2010
Total Assets:
 
 
 
Electric utility
$
38,122

 
$
35,906

Competitive power generation
9,881

 
9,597

Parent and other2
(331
)
 
27

Consolidated Edison International
$
47,672

 
$
45,530

1 Includes earnings (losses) from discontinued operations of none and $(4) million for the three months ended September 30, 2011 and 2010, respectively, and $(3) million and $4 million for the nine months ended September 30, 2011 and 2010, respectively.
2 Includes amounts from Edison International (parent) and other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.



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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
This quarterly report on Form 10-Q 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. Other information distributed by Edison International that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report 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 from those currently expected, or that otherwise could impact Edison International, include, but are not limited to:
•
cost of capital and the ability of Edison International or its subsidiaries to borrow funds and access the capital markets on reasonable terms;
•
environmental laws and regulations, at both state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business, including compliance with CPS at Midwest Generation and the CSAPR and the proposed National Emission Standards for Hazardous Air Pollutants at Midwest Generation and Homer City;
•
ability of SCE to recover its costs in a timely manner from its customers through regulated rates;
•
decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays in regulatory actions;
•
possible customer bypass or departure due to technological advancements or cumulative rate impacts that make self-generation or use of alternative energy sources economically viable;
•
risks associated with the operation of transmission and distribution assets and nuclear and other power generating facilities including: nuclear fuel storage issues, public safety issues, failure, availability, efficiency, output, cost of repairs and retrofits of equipment and availability and cost of spare parts;
•
cost and availability of electricity including the ability to procure sufficient resources to meet expected customer needs in the event of significant counterparty defaults under power purchase agreements;
•
changes in the fair value of investments and other assets;
•
changes in interest rates and rates of inflation, including those rates which may be adjusted by public utility regulators;
•
governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by Independent System Operators and Regional Transmission Organizations;
•
availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;
•
cost and availability of labor, equipment and materials;
•
ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance;
•
ability to recover uninsured losses in connection with wildfire-related liability;
•
effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
•
potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;
•
cost and availability of coal, natural gas, fuel oil, and nuclear fuel, and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;


40
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•
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;
•
ability to provide sufficient collateral in support of hedging activities and power and fuel purchased;
•
risks inherent in the development of generation projects and transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, construction, permitting, and governmental approvals;
•
risks that competing transmission systems will be built by merchant transmission providers in SCE's territory; and
•
weather conditions and natural disasters.
Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in Edison International's 2010 Form 10-K, including the "Risk Factors" section in Part I, Item 1A. Readers are urged to read this entire report, including the information incorporated by reference, as well as the 2010
Form 10-K, and carefully consider the risks, uncertainties and other factors that affect Edison International's business. 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. Readers should review future reports filed by Edison International with the U.S. Securities and Exchange Commission.
This MD&A for the three- and nine-month periods ended September 30, 2011 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2010, and as compared to the three- and nine-month periods ended September 30, 2010. This discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2010 (the "year-ended 2010 MD&A"), which was included in the 2010 Form 10-K.


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EDISON INTERNATIONAL MANAGEMENT OVERVIEW
Highlights of Operating Results
 
Three months ended
September 30,
 
 
 
Nine months ended
September 30,
 
 
(in millions)
2011
 
2010
 
Change
 
2011
 
2010
 
Change
Net Income (Loss) attributable to Edison International
 
 
 
 
 
 
 
 
 
 
 
SCE
$
406

 
$
394

 
$
12

 
$
838

 
$
858

 
$
(20
)
EMG
33

 
110

 
(77
)
 
(17
)
 
214

 
(231
)
Edison International Parent and Other
(13
)
 
6

 
(19
)
 
(19
)
 
18

 
(37
)
Edison International Consolidated
426

 
510

 
(84
)
 
802

 
1,090

 
(288
)
Less: Non-Core Items
 
 
 
 
 
 
 
 
 
 
 
Global Settlement:
 
 
 
 
 
 
 
 
 
 
 
SCE
—

 
42

 
(42
)
 
—

 
95

 
(95
)
EMG
—

 
(6
)
 
6

 
—

 
52

 
(52
)
Edison International Parent and Other
—

 
1

 
(1
)
 
—

 
28

 
(28
)
SCE – tax impact of health care legislation
—

 
—

 
—

 
—

 
(39
)
 
39

EMG discontinued operations
—

 
(4
)
 
4

 
(3
)
 
4

 
(7
)
Total non-core items
—

 
33

 
(33
)
 
(3
)
 
140

 
(143
)
Core Earnings (Losses)
 
 
 
 
 
 
 
 
 
 
 
SCE
406

 
352

 
54

 
838

 
802

 
36

EMG
33

 
120

 
(87
)
 
(14
)
 
158

 
(172
)
Edison International Parent and Other
(13
)
 
5

 
(18
)
 
(19
)
 
(10
)
 
(9
)
Edison International Consolidated
$
426

 
$
477

 
$
(51
)
 
$
805

 
$
950

 
$
(145
)
Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings by principal operating subsidiary internally for financial planning and for analysis of performance. Core earnings (losses) by principal operating subsidiary are also used when communicating with analysts and investors regarding our earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as earnings attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including lease terminations, sale of certain assets, early debt extinguishment costs and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings.
SCE's 2011 core earnings increased $54 million and $36 million for the quarter and year-to-date, respectively. Core earnings in both periods increased due to rate base growth. The quarterly core earnings increase was also attributable to lower income taxes. The year-to-date increase was partially offset by higher income tax expense, including a $40 million benefit in the second quarter of 2010 from a change in tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program. In October 2011, the CPUC authorized SCE to recover legal costs incurred between 2004 and 2009 in support of SCE's efforts to obtain generator refunds. As a result, SCE expects to record revenue of approximately $25 million in the fourth quarter of 2011.
EMG's 2011 core earnings decreased $87 million and $172 million for the quarter and the year-to-date, respectively. The decrease in core earnings during the quarter was due to lower capacity revenues, realized energy prices and generation from merchant coal plants, and lower trading income and capacity factors from renewable projects. The decrease in core earnings during the quarter was also due to a gain in 2010 from the sale of bankruptcy claims. The decrease in year-to-date core earnings was due to lower realized energy prices and generation from merchant coal plants, higher plant maintenance costs from outages, higher interest expense related to renewable projects, and lower trading income. In addition, unrealized losses were $4 million for the nine months of 2011 compared to unrealized losses of $30 million in the same period last year.
Edison International Parent and Other 2011 core earnings decreased $18 million and $9 million for the quarter and the


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year-to-date, respectively, primarily due to lower tax benefits in 2011 compared to 2010.
Consolidated non-core items for Edison International included:
•
An earnings benefit of $175 million recorded in 2010 relating to the California impact of the federal Global Settlement, including $138 million in the second quarter resulting from acceptance by the Franchise Tax Board of the tax positions finalized with the IRS in 2009 and $37 million in the third quarter resulting from receipt of the final interest determination from the Franchise Tax Board.
•
An after tax earnings charge of $39 million recorded in the first quarter of 2010 to reverse previously recognized federal tax benefits eliminated by federal health care legislation enacted in 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.
Management Overview of SCE
Capital Program
During the first nine months of 2011, SCE's capital investment program focused on upgrading and expanding SCE's transmission and distribution system; replacing generation asset equipment; and installing smart meters. Total capital expenditures (including accruals) were $2.5 billion during the first nine months of 2011 compared to $2.4 billion during the same period in 2010.
As discussed under "Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2010 MD&A, SCE continues to project that 2011 capital expenditures will be in the range of $3.9 billion to $4.4 billion and that 2011 - 2014 total capital expenditures will be in the range of $15.6 billion to $17.5 billion. Actual capital spending will be affected by: changes in regulatory, environmental and engineering design requirements; permitting and project delays; cost and availability of labor, equipment and materials; and other factors.
SCE is currently completing the final engineering design for the Tehachapi Transmission Project and anticipates an increase in its 2011-2014 expenditures for the project as a result of cost pressures associated with engineering design and scope changes, environmental mitigation work, and regulatory and permit delays. The project may be further impacted by the CPUC's response to SCE's petition to modify the 2009 decision approving the project for the purpose of obtaining authorization to install aviation marking and lighting. In October 2011, the CPUC staff notified SCE that the constructed portions of the project could be marked and lighted as required, but instructed SCE to defer completion of remaining project components that may require aviation marking or lighting pending CPUC review of the petition to modify. Community opposition to portions of the project continues and requests for reconsideration of the CPUC's 2009 decision are pending. Once final engineering is complete, SCE will file a revised cost estimate with the CPUC. As with all transmission investments, cost recovery will be subject to future rate proceedings.
In July 2011, the FERC adopted new rules that remove incumbent public utility transmission owners' federally-based right of first refusal to construct certain new transmission facilities. The rules direct regional entities, such as ISOs, to create new processes that would allow other providers to develop new transmission projects. The new processes will not become effective until approved by the FERC, which is expected in late 2012. The majority of SCE's 2011 – 2014 transmission capital forecast relates to transmission projects that have been approved by the CAISO and barring a re-evaluation under the new rules, will not be subject to the new processes. SCE does not expect these projects to be re-evaluated. The impact of the new rules on future transmission projects will depend on the processes ultimately implemented by regional entities.
2012 CPUC General Rate Case
As discussed in the year-ended 2010 MD&A, SCE filed its GRC application in November 2010. In October 2011, SCE submitted updated testimony to reflect changes in escalation rates, known changes due to governmental actions and changes in the timing of recovery for nuclear outages, which taken together changed its requested 2012 base rate revenue requirement to $6.3 billion. SCE's updated request, after considering the effects of sales growth, would result in incremental customer base rate increases of $824 million, $136 million and $532 million in 2012, 2013 and 2014, respectively. The updated request also reflects a previously submitted base revenue requirement reduction of $38 million, $133 million and $145 million in 2012, 2013 and 2014, respectively, primarily due to a reduction in rate base from inclusion of higher deferred income taxes resulting from bonus depreciation deductions under the 2010 Tax Relief Act.
The Division of Ratepayer Advocates ("DRA") recommended that SCE's requested 2012 base rate revenue requirement be decreased by approximately $850 million, comprised of approximately $630 million in operation and maintenance expense reductions and approximately $220 million in capital-related revenue requirement reductions. The Utility Reform Network or


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TURN and other intervenors recommended an additional $610 million revenue requirement reduction, beyond the DRA adjustments, primarily capital-related in nature, as well as disallowances of recorded capital costs for specific projects. Intervenors have also recommended changes to SCE's proposed post test year ratemaking methodology to be used for 2013 and 2014.
The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011, but the Administrative Law Judge
handling the GRC has indicated that a final decision is not expected before year-end. To the extent that a final decision is delayed beyond the end of 2011, the CPUC has authorized the establishment of a GRC memorandum account, which will make the revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or the timing of the final 2012 GRC decision.
FERC Formula Rates
In August 2011, the FERC accepted, subject to refund and settlement procedures, SCE's request to implement a formula rate effective January 1, 2012, to determine SCE's FERC transmission revenue requirement, including its construction work in progress ("CWIP") revenue requirement that was previously recovered through a separate mechanism. The FERC reduced SCE's proposed base ROE request from 11.5% to 9.93%. SCE estimates its total 2012 FERC weighted average ROE will be 11.1%, including the previously authorized 50 basis point incentive for CAISO participation and individual authorized project incentives. The actual weighted average ROE is dependent upon the amount and timing of capital expenditures among FERC incentive and non-incentive projects. SCE's request proposed the adoption of a specific formula to calculate a forecast revenue requirement that is used to establish rates and is trued-up annually to allow SCE to recover its actual revenue requirement, including its actual cost of service, actual rate base and the authorized return on investment. SCE's request also allows SCE to make single-issue rate filings requesting changes to certain elements of the formula, including the base ROE, depreciation rates and the retail rate structure. SCE and the other parties to the proceeding are currently in settlement negotiations. SCE does not expect a final decision until 2012 and cannot predict the formula rate structure that the FERC will ultimately authorize.
In September 2011, SCE reduced its forecasted 2012 transmission revenue requirement for the lower ROE by $49 million to $722 million. SCE had requested a rehearing of the adopted base ROE, however the FERC denied such request in October 2011. SCE is evaluating and must decide by December 2011 whether to appeal the FERC order at the DC Circuit Court. Separately, in October 2011, the FERC issued an order denying SCE's request for rehearing of its 2008 and 2011 CWIP proceedings which adopted a base ROE of 9.54% and 10.3%, respectively, compared to SCE's request of 11.5%. The reduced ROE in these proceedings did not have a material impact on SCE's financial statements.
Nuclear Industry and Regulatory Response to Events in Japan
As discussed in the 2010 Form 10-K under the heading "Nuclear Power Plant Regulation," SCE is subject to the jurisdiction of the NRC with respect to its ownership interest in San Onofre and Palo Verde. In light of the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the March 2011 earthquake and tsunami, the NRC has been performing and plans to continue to perform additional operational and safety reviews of nuclear facilities in the United States. The NRC's Near Term Task Force ("NTTF") conducted a systematic review of U.S. NRC processes and regulations to determine whether additional improvements to the existing nuclear regulatory system are warranted in light of the events in Japan. The NTTF concluded that a sequence of events like the Fukushima accident is unlikely to occur in the U.S., and that continued operation of U.S. reactors does not pose an imminent risk to public health and safety. The NTTF Report proposed changes to regulations applicable to protection against natural phenomena, including earthquakes and flooding and emergency preparedness, and the NTTF made a number of recommendations as to actions that the NRC might implement. The timing and prioritization of these recommendations must be voted on by the NRC and the nuclear industry will have an opportunity to comment on the timing and scope of these recommendations prior to their implementation. If implemented, the recommendations may impact future operations and capital requirements at United States nuclear facilities, including the operations and capital requirements of SCE's nuclear facilities.
Management Overview of EMG
The profitability of EMG's competitive power generation operations is expected to be significantly lower in 2011 compared to 2010 as a result of lower realized energy prices at the Midwest Generation plants, higher fuel costs and outages at the Homer City plant. In addition, the profitability of EMG's Midwest Generation plants is expected to be adversely affected by a decline in capacity prices and higher rail transportation costs (due to the expiration at the end of 2011 of a favorable long-term rail contract), and EMG's Homer City plant may be adversely impacted by new environmental regulations discussed further below. As a result, EMG may incur net losses during 2011 and in subsequent years unless energy and capacity prices increase or its costs decline.
At September 30, 2011, EMG and its subsidiaries had $1.3 billion in cash and cash equivalents and $1.0 billion of liquidity


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available from credit facilities that expire in 2012. EMG's principal subsidiary, EME, had $3.7 billion of senior notes outstanding at September 30, 2011, $500 million of which mature in 2013. EMG's business plans are focused on operating effectively through the current commodity price cycle, environmental compliance and energy project development plans.
Cross-State Air Pollution Rule
On July 6, 2011, the US EPA adopted the CSAPR . CSAPR is the final form of a previously proposed replacement for the CAIR, originally called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual SO2 emissions and annual and ozone season NOx emissions in two phases: a first phase effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO2 emissions.
CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO2 or NOx emissions from operations will need to be matched by a sufficient amount of SO2 or NOx allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO2 and NOx allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual or seasonal compliance period, units must surrender allowances for each ton of SO2 and NOx emitted or face penalties. While trading of allowances is permitted within designated groups of states, the rule provides for penalties against a unit with emissions in excess of its predefined "assurance level," but only if the state in which it is located also exceeds its budgeted emissions level. On October 6, 2011, the US EPA announced a proposed revision to the rule that would effectively eliminate such penalties in the first phase.
EMG believes that Midwest Generation's current environmental remediation plan developed to comply with the CPS, along with the allowances allocated to it under CSAPR, will be sufficient to comply with the requirements of CSAPR and the US EPA's proposed regulation on hazardous air pollutant ("HAP") emissions. In order to achieve compliance, Midwest Generation has begun work to install SO2 controls at certain of its plants.
The SO2 allowances allocated to Homer City in CSAPR Phase I (25,797 tons in 2012 and 2013) are significantly lower than the amount that would be required based on Homer City's historical emissions (2010 SO2 emissions were 112,951 tons). Therefore, pending installation of additional equipment for Units 1 and 2 (Homer City's Unit 3 is equipped with a wet scrubber flue gas desulfurization system to meet environmental standards), Homer City expects that it will be required to procure additional allowances. It is unclear at this time whether Homer City will be able to acquire allowances for 2012 and 2013 in sufficient quantity to cover its normal operations and whether it will be able to pass through the cost of such allowances in the marketplace. Also, Homer City's SO2 emissions could exceed its assurance level, and, therefore, unless the US EPA's proposed revision to the rule is adopted, Homer City could be subject to penalties depending on whether, collectively, emissions from all of the subject electrical generating facilities in Pennsylvania exceed the state's budgeted emissions level. Accordingly, Homer City is evaluating alternative options, including reduced dispatch and fuel modifications, for complying with Phase I of CSAPR. The cost of allowances, together with possible operational impacts or reductions of output that may be required to comply with Phase I of CSAPR, could have a material effect on Homer City.
Homer City has begun work on designing SO2 and particulate emissions control equipment for Units 1 and 2. While the Phase II SO2 emission allowances under CSAPR (11,068 tons) are less than were contemplated under the proposed Clean Air Transport Rule, the additional reductions are not expected to materially change the design for the SO2 controls at Units 1 and 2. The installation of those SO2 controls will require capital commitments for the Homer City plant well in advance of the 2014 effective date, including some expenditures in 2011, in order to meet regulatory deadlines. Given the relatively short period of time before Phase II of CSAPR takes effect in 2014, there is no assurance that Homer City will be able to complete all the work that will be required before the deadline. Homer City is continuing to review technologies available to reduce SO2 and mercury emissions; however, it has not determined the most effective and efficient technology to meet all requirements that may be imposed on it. Consequently, the timing, selection of technology and ultimate capital costs remain uncertain. Based on preliminary estimates, Homer City currently believes the cost of such equipment may be between $600 million and $700 million. An application for a construction permit to install the additional controls was filed on October 3, 2011 with the Pennsylvania Department of Environmental Protection.
Homer City Capital Needs and Liquidity
Homer City does not currently have sufficient capital and does not expect to generate sufficient funds from operations to complete retrofits effectively required by CSAPR Phase II. EME is under no legal obligation to, and has chosen not to, provide funding. Homer City expects to fund $13 million of project costs during the remainder of 2011. However, Homer City will need third-party capital to undertake the retrofits required by 2014 under CSAPR and to fund capital costs beginning in 2012 in order to complete the requisite retrofits by early 2014. However, restrictions under the agreements entered into as part of


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Homer City's 2001 sale-leaseback transaction affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Consequently, Homer City's ability to install environmental compliance equipment will be dependent on approvals by its lessors and holders of bonds who provided financing for the sale-leaseback transaction, and its ability to obtain new capital funding.
Homer City has engaged a financial advisor and commenced a process to obtain capital funding from third parties to install the environmental improvements. Homer City's objective is to maximize the value of its leasehold interest while obtaining the incremental capital needed to make such improvements. There can be no assurance that Homer City will be able to raise the financing necessary to install the required SO2 control equipment in a timely manner or on terms that will not result in a significant dilution of its interest in the Homer City plant. A significant dilution of interest in the Homer City plant may result in a financial statement deconsolidation of Homer City if EME no longer retains control for inclusion in the consolidated financial statements. In this event, the transaction would be accounted for as a disposition and could result in a material loss. At September 30, 2011, the book value of EME's investment in Homer City and related assets was approximately $1.1 billion.
Homer City believes that the persistence of low power prices, combined with the outages suffered earlier this year and the possible impacts of compliance with CSAPR Phase I in 2012, will make it unlikely that Homer City will meet the covenant requirements of its sale-leaseback documents relating to the payment of equity rent at April 1, 2012. Under the sale-leaseback documents, rent payments are comprised of two components, senior rent and equity rent. Senior rent is used exclusively for debt service to holders of senior secured bonds issued in connection with the sale-leaseback transaction, while equity rent is paid to the owner-lessors. In order to pay equity rent, among other requirements, Homer City must meet historical and projected senior rent service coverage ratios of 1.7 to 1 (subject to reduction to 1.3 to 1 under certain circumstances). A failure to pay equity rent does not entitle the owner-lessors to foreclose upon Homer City's leasehold interest, but it does result in the suspension of Homer City's ability to make permitted distributions. Moreover, the ability to make permitted distributions would be permanently frozen if a failure to pay equity rent when due was not cured within nine months, or even if timely cured, there occurred more than one additional failure to pay equity rent when due at any future time during the term of the lease. Homer City is not subject to any minimum historical and projected senior rent service coverage ratios except as conditions to distributions and equity rent payments. Also, failure by Homer City to pay equity rent when due in April 2012 could trigger termination of the $47 million senior rent reserve letter of credit. Homer City would then be required to fund the senior rent reserve, and failure to do so could entitle counterparties to seek available remedies under the sale-leaseback documents, including termination or foreclosure upon the leasehold interest.
EME's subsidiary, EMMT, enters into energy and capacity transactions on behalf of Homer City pursuant to an intercompany agreement. Those transactions are generally back-to-back transactions in which EMMT enters into a transaction with a third party as a principal and then enters into an equivalent transaction with Homer City. In the case of energy sales, if Homer City fails to perform its obligations under the intercompany agreement, EMMT would seek to fulfill its third-party obligations through market transactions which may result in losses. In the case of capacity, EMMT has sold Homer City capacity in the annual PJM base residual auctions through May 2015. If Homer City were to default on its obligations to supply capacity, then EMMT would be liable to PJM to supply that capacity, and failure to do so would expose EMMT to penalties under the PJM tariffs. If one or more of the Homer City units were to be unavailable as a capacity resource and EMMT did not fulfill this obligation through market transactions, then PJM would assess a penalty against EMMT (excluding a refund of any capacity payments received by EMMT) equal to the greater of 20% of the capacity payments or $20 per MW-day.
Failure of Homer City to find an economic manner to continue plant operations, by installing the required equipment or otherwise, could result in a foreclosure on its leasehold interest and/or a curtailment of plant operations. These events or other matters described above could have an adverse effect on future financial results, cash flow, financial flexibility and assets of EME compared to historical levels.
Midwest Generation Environmental Compliance Plans and Costs
During 2011, Midwest Generation continued its permitting and planning activities for NOx and SO2 controls to meet the requirements of the CPS. Midwest Generation does not anticipate a material change to its current approach in order to comply with CSAPR. Based on its continuing review, EME also does not expect the US EPA's proposed National Emission Standards for Hazardous Air Pollutants, if adopted, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. Midwest Generation expects to continue to develop and implement a compliance program that includes the use of activated carbon injection, upgrades to particulate removal systems and dry sorbent injection, combined with its use of low sulfur PRB coal, to meet emissions limits for criteria pollutants, such as NOx and SO2 as well as for HAPs, such as mercury, acid gas and non-mercury metals. Based on stack tests performed at various Midwest Generation plants, Midwest Generation believes that currently installed activated carbon injection and particulate removal equipment is sufficient to achieve or exceed the mercury standards outlined in the US EPA's existing and proposed rules.


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In February 2011, the Illinois EPA issued construction permits authorizing Midwest Generation to install a dry sorbent injection system using Trona or other sodium-based sorbents at the Powerton Station's Units 5 and 6.
Decisions regarding whether or not to proceed with retrofitting units to comply with CPS requirements for SO2 emissions, including those that have received permits, remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation could also elect to temporarily or permanently shut down units, instead of installing controls, to be in compliance with the CPS.
Therefore, decisions about any particular combination of retrofits and shutdowns Midwest Generation may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital or continue with the expenditure of capital that is budgeted may not occur until 2012 for some of the units and potentially later for others, subject to the requirements of the CPS and other applicable regulations. Pending such final decisions, Midwest Generation plans to continue with any work necessary to comply with issued permits.
Environmental Regulation Developments
For additional discussion of environmental regulation developments regarding the Cross-State Air Pollution Rule, proposed Hazardous Air Pollutant Regulations, Ozone and Particulates Standards, Once-Through Cooling Issues, Greenhouse Gas Regulation and Greenhouse Gas Litigation Developments, see "Edison International Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments."



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SOUTHERN CALIFORNIA EDISON COMPANY
RESULTS OF OPERATIONS
SCE's results of operations are derived mainly through two sources:
•
Utility earning activities – representing CPUC and FERC-authorized base rates, including the opportunity to earn the authorized return; and
•
Utility cost-recovery activities – representing CPUC and FERC-authorized balancing accounts which allow for recovery of costs incurred or provide for mechanisms to track and recover or refund differences in forecasted and actual amounts.
Utility earning activities include base rates that are designed to recover forecasted operation and maintenance costs, certain capital-related carrying costs, interest, taxes and a return, including the return on capital projects recovered through CPUC-authorized mechanisms outside the GRC process. Differences between authorized amounts and actual results impact earnings. Also, included in utility earning activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.
Utility cost-recovery activities include rates that provide for recovery (with no return), subject to review of reasonableness or compliance with upfront standards, of fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs), certain operation and maintenance expenses, and depreciation expense related to certain projects.
The following tables summarize SCE's results of operations for the periods indicated. The presentation separately identifies utility earning activities and utility cost-recovery activities.
Three Months Ended September 30, 2011 versus September 30, 2010
 
Three months ended
September 30, 2011
 
Three months ended
September 30, 2010
(in millions)
Utility
Earning
Activities
 
Utility
Cost-
Recovery
Activities
 
Total
Consolidated
 
Utility
Earning
Activities
 
Utility
Cost-
Recovery
Activities
 
Total
Consolidated
Operating revenue
$
1,697

 
$
1,689

 
$
3,386

 
$
1,601

 
$
1,497

 
$
3,098

Fuel and purchased power
—

 
1,374

 
1,374

 
—

 
1,218

 
1,218

Operations and maintenance
541

 
278

 
819

 
541

 
262

 
803

Depreciation, decommissioning and amortization
323

 
35

 
358

 
300

 
16

 
316

Property taxes and other
69

 
2

 
71

 
64

 
1

 
65

Total operating expenses
933

 
1,689

 
2,622

 
905

 
1,497

 
2,402

Operating income
764

 
—

 
764

 
696

 
—

 
696

Net interest expense and other
(98
)
 
—

 
(98
)
 
(84
)
 
—

 
(84
)
Income before income taxes
666

 
—

 
666

 
612

 
—

 
612

Income tax expense
245

 
—

 
245

 
205

 
—

 
205

Net income
421

 
—

 
421

 
407

 
—

 
407

Dividends on preferred and preference stock
15

 
—

 
15

 
13

 
—

 
13

Net income available for common stock
$
406

 
$
—

 
$
406

 
$
394

 
$
—

 
$
394

Core Earnings1
 

 
 

 
$
406

 
 

 
 

 
$
352

Non-Core Earnings:
 
 
 
 
 
 
 
 
 
 
 
Global Settlement
 

 
 

 
—

 
 

 
 

 
42

Total SCE GAAP Earnings
 

 
 

 
$
406

 
 

 
 

 
$
394

1 
See use of Non-GAAP financial measures in "Edison International Management Overview—Highlights of Operating Results."


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Utility Earning Activities
Utility earning activities were primarily affected by the following:
•
Higher operating revenue of $96 million primarily due to the following:
•
$50 million increase primarily due to a 4.35% increase in 2011 authorized revenue approved in the 2009 CPUC GRC decision.
•
$25 million increase in FERC-related revenue primarily due to CWIP incentive revenue for the Tehachapi transmission project.
•
$15 million increase related to capital-related revenue requirements primarily related to the steam generator replacement project and EdisonSmartConnectTM.
•
Higher depreciation, decommissioning and amortization expense of $23 million primarily related to increased transmission and distribution investments.
•
Higher net interest expense and other of $14 million primarily due to higher outstanding balances on long-term debt.
•
Higher income taxes primarily due to a benefit recorded in 2010 related to the Global Settlement. See "—Income Taxes" below for further information.
Utility Cost-Recovery Activities
Utility cost-recovery activities were primarily affected by the following:
•
Higher purchased power expense of $146 million primarily driven by the cost to replace CDWR contracts that expired in 2011 .
•
Higher operation and maintenance expense of $16 million resulting primarily from increased energy efficiency program costs.
•
Higher depreciation, decommissioning and amortization expense of $19 million primarily related to the steam generator replacement project and the EdisonSmartConnect™ project.


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Nine Months Ended September 30, 2011 versus September 30, 2010
 
Nine months ended
September 30, 2011
 
Nine months ended
September 30, 2010
(in millions)
Utility
Earning
Activities
 
Utility
Cost-
Recovery
Activities
 
Total
Consolidated
 
Utility
Earning
Activities
 
Utility
Cost-
Recovery
Activities
 
Total
Consolidated
Operating revenue
$
4,442

 
$
3,621

 
$
8,063

 
$
4,175

 
$
3,329

 
$
7,504

Fuel and purchased power
—

 
2,691

 
2,691

 
—

 
2,612

 
2,612

Operations and maintenance
1,619

 
831

 
2,450

 
1,598

 
674

 
2,272

Depreciation, decommissioning and amortization
964

 
94

 
1,058

 
905

 
40

 
945

Property taxes and other
212

 
5

 
217

 
193

 
2

 
195

Gain on sale of assets
—

 
—

 
—

 
—

 
(1
)
 
(1
)
Total operating expenses
2,795

 
3,621

 
6,416

 
2,696

 
3,327

 
6,023

Operating income
1,647

 
—

 
1,647

 
1,479

 
2

 
1,481

Net interest expense and other
(269
)
 
—

 
(269
)
 
(244
)
 
(2
)
 
(246
)
Income before income taxes
1,378

 
—

 
1,378

 
1,235

 
—

 
1,235

Income tax expense
496

 
—

 
496

 
338

 
—

 
338

Net income
882

 
—

 
882

 
897

 
—

 
897

Dividends on preferred and preference stock
44

 
—

 
44

 
39

 
—

 
39

Net income available for common stock
$
838

 
$
—

 
$
838

 
$
858

 
$
—

 
$
858

Core Earnings1
 

 
 

 
$
838

 
 

 
 

 
$
802

Non-Core Earnings:
 
 
 
 
 
 
 
 
 
 
 
Global Settlement
 

 
 

 
—

 
 

 
 

 
95

Tax impact of health care legislation
 

 
 

 
—

 
 

 
 

 
(39
)
Total SCE GAAP Earnings
 

 
 

 
$
838

 
 

 
 

 
$
858

1 
See use of Non-GAAP financial measures in "Edison International Management Overview—Highlights of Operating Results."
Utility Earning Activities
Utility earning activities were primarily affected by the following:
•
Higher operating revenue of $267 million primarily due to the following:
•
$130 million increase primarily due to a 4.35% increase in 2011 authorized revenue approved in the 2009 CPUC GRC decision.
•
$90 million increase in FERC-related revenue primarily due to CWIP incentive revenue for the Tehachapi transmission project and the implementation of the 2010 FERC rate case effective March 1, 2010.
•
$50 million increase related to capital-related revenue requirements primarily related to the steam generator replacement project and EdisonSmartConnectTM.
•
Higher depreciation, decommissioning and amortization expense of $59 million primarily related to increased transmission and distribution investments.
•
Higher net interest expense and other of $25 million primarily due to higher outstanding balances on long-term debt.
•
Higher income taxes primarily due to benefits recorded in 2010 related to the Global Settlement. See "—Income Taxes" below for more information.


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Utility Cost-Recovery Activities
Utility cost-recovery activities were primarily affected by the following:
•
Higher purchased power expense of $85 million primarily driven by the cost to replace CDWR contracts that expired in 2011 and higher average prices from a shift to renewable contracts. The increase was partially offset by increased purchased power in 2010 during the outages at San Onofre and Four Corners.
•
Higher operation and maintenance expense of $157 million resulting primarily from increased energy efficiency program costs.
•
Higher depreciation, decommissioning and amortization expense of $54 million primarily related to the steam generator replacement project and the EdisonSmartConnect™ project.
Supplemental Operating Revenue Information
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $3.3 billion and $7.8 billion for the three- and nine-month periods ended September 30, 2011, respectively, compared to $3.4 billion and $7.8 billion for the respective periods in 2010. The quarterly decrease reflects a rate decrease of $186 million and a sales volume increase of $103 million. The $186 million rate decrease primarily reflects lower generation rates for 2011 due to the refunding of prior period purchased power overcollections in 2011. The $103 million sales volume increase was primarily due to serving generation load that was previously served by CDWR contracts which expired in 2011. As a result of a CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk or benefit related to retail electricity sales (see "Item 1. Business—Overview of Ratemaking Mechanisms" in the 2010 Form 10-K).
SCE remits to CDWR and does not recognize as revenue the amounts that SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, CDWR bond-related costs and a portion of direct access exit fees. The amounts collected and remitted to CDWR were $319 million and $873 million for the three- and nine-month periods ended September 30, 2011, respectively, and $315 million and $896 million for the respective periods in 2010. The CDWR-related rates in 2011 continue to reflect an approximately $585 million refund of operating reserves that CDWR can release as their contracts terminate. Total customer rates are expected to increase as CDWR operating reserves are fully refunded. The power contracts that CDWR allocated to SCE will terminate by the end of 2011; however, the refund of operating reserves is expected to continue through 2012. SCE's revenue and related purchased power expense is expected to increase as these CDWR contracts are replaced by power purchase agreements entered into by SCE.
Income Taxes
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision.
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Income before income taxes
$
666

 
$
612

 
$
1,378

 
$
1,235

Provision for income tax at federal statutory rate of 35%
$
233

 
$
214

 
$
482

 
$
433

Increase (decrease) in income tax from:
 
 
 
 
 
 
 
Items presented with related state income tax, net
 
 
 
 
 
 
 
Global settlement related1
—

 
(42
)
 
—

 
(95
)
Change in tax accounting method for asset removal costs2
—

 
—

 
—

 
(40
)
State tax – net of federal benefit
31

 
26

 
61

 
47

Health care legislation3
—

 
—

 
—

 
39

Property-related and other
(19
)
 
7

 
(47
)
 
(46
)
Total income tax expense
$
245

 
$
205

 
$
496

 
$
338

Effective tax rate
37
%
 
33
%
 
36
%
 
27
%
1 
During the nine months ended September 30, 2010, SCE recognized a $95 million earnings benefit relating to the California impact of the federal Global Settlement, including $53 million in the second quarter resulting from the acceptance by the California Franchise Tax


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Board of the tax positions finalized with the IRS in 2009 and $42 million in the third quarter resulting from receipt of the final interest determination for the Franchise Tax Board.
2 
During the second quarter of 2010, the IRS approved SCE's request to change its tax accounting method for asset removal costs primarily related to its infrastructure replacement program. As a result, SCE recognized a $40 million earnings benefit (of which $28 million relates to asset removal costs incurred prior to 2010) from deducting asset removal costs earlier in the construction cycle. These deductions are recorded on a flow-through basis.
3 
During the first quarter of 2010, SCE recorded a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.
For a discussion of the status of Edison International's income tax audits, see "Edison International Notes to Consolidated Financial Statements—Note 7. Income Taxes."
Repair Deductions
As discussed in the year ended 2010 MD&A, in 2009, Edison International made a voluntary election to change its tax accounting method for certain repair costs incurred on SCE's transmission, distribution and generation assets. The change in tax accounting method resulted in a $192 million cash benefit realized in the fourth quarter of 2009. In August of 2011 the IRS issued guidance on repair deductions and changes in accounting method related to transmission and distribution assets. Based on this guidance SCE will file a second change in tax accounting method in 2011 for all prior years. SCE does not expect any cash impact in 2011 due to its current net operating loss carry forward position. Regulatory treatment for the incremental deductions taken after the voluntary election to change SCE's tax accounting method for certain repair costs will be addressed in SCE's 2012 GRC. Due to the pending regulatory treatment SCE has not recognized an earnings benefit or regulatory asset related to this method change and incremental deductions taken in 2009, 2010 and 2011.
LIQUIDITY AND CAPITAL RESOURCES
SCE's ability to operate its business, complete planned capital projects, and implement its business strategy are dependent upon its cash flow and access to the capital markets to finance its activities. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, dividend payments made to Edison International, and the outcome of tax and regulatory matters.
SCE expects to fund its continuing obligations, projected capital expenditures for 2011 and dividends to Edison International through cash and equivalents on hand, operating cash flows, tax benefits (including bonus depreciation) and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities if additional funding and liquidity are necessary to meet operating and capital requirements.
Available Liquidity
SCE had two credit facilities: a $2.4 billion five-year credit facility that matures in February 2013, with four one-year options to extend by mutual consent, and a $500 million three-year credit facility that matures in March 2013.
(in millions)
Credit Facilities
Commitment
$
2,894

Outstanding borrowings supported by credit facilities
(550
)
Outstanding letters of credit
(83
)
Amount available
$
2,261

Debt Covenant
SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At September 30, 2011, SCE's debt to total capitalization ratio was 0.47 to 1.
Dividend Restrictions
The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of


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48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At September 30, 2011, SCE's 13-month weighted-average common equity component of total capitalization was 50.5% resulting in the capacity to pay $436 million in additional dividends.
During the first nine months of 2011, SCE made $345 million in dividend payments to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the actual level of capital expenditures, operating cash flows and earnings.
Regulatory Proceedings
Energy Efficiency Shareholder Risk/Reward Mechanism
As discussed in the 2010 Form 10-K under the heading "Overview of Ratemaking Mechanisms—Energy Efficiency Shareholder Risk/Reward Mechanism," the CPUC intended to review the framework of the Energy Efficiency Mechanism and to establish a mechanism applicable to performance during the 2010 - 2012 energy efficiency program cycle. In September 2011 the CPUC requested comments from SCE and other interested parties on an Energy Efficiency Mechanism applicable to the 2010-2012 program cycle. SCE recommended using the remainder of 2011 and 2012 for development of a new mechanism that would focus on reliability, affordability, and benefits to the environment that would be applicable for 2013 and beyond.
Cost of Capital
As discussed in the 2010 Form 10-K under the heading "Overview of Ratemaking Mechanisms—CPUC Base Rates," the CPUC extended through 2012 a multi-year cost of capital mechanism which set SCE's authorized rate of return on equity at 11.5%, subject to annual adjustments if certain thresholds are reached. The 2012 measurement period (October 2010 - September 2011) did not trigger an annual adjustment and therefore the 11.5% authorized rate of return on equity will remain in effect through 2012. In April 2012, SCE is scheduled to file a new cost of capital mechanism at the CPUC that, once approved, will establish SCE's authorized rate of return for 2013. If the current interest rate environment continues, SCE's 2013 authorized rate of return could decrease from 11.5%.
Margin and Collateral Deposits
Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of September 30, 2011.
(in millions)
Collateral posted as of September 30, 20111
$
106

Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade
135

Posted and potential collateral requirements2
$
241

1 
Collateral provided to counterparties and other brokers consisted of $14 million which was offset against net derivative liabilities and $92 million, which consisted of $9 million in cash reflected in “Other current assets” on the consolidated balance sheets and $83 million in letters of credit.
2 
Total posted and potential collateral requirements may increase by an additional $2 million based on SCE's forward positions as of September 30, 2011 due to adverse market price movements over the remaining lives of the existing power procurement contracts using a 95% confidence level.
Workers Compensation Self-Insurance Fund
SCE is self-insured for workers compensation claims. SCE assesses workers compensation claims that have been asserted and those that have been incurred but not reported to determine the probable amount of losses that should be recorded. The Department of Industrial Relations for the State of California requires companies that are self-insured for workers compensation to post collateral (in the form of cash and/or letters of credits) based on the estimated workers' compensation liability if a company's bond rating were to fall below "B." As of September 30, 2011, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $202 million for its workers compensation self-insurance plan.


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Historical Consolidated Cash Flows
Condensed Consolidated Statement of Cash Flows
The table below sets forth condensed historical cash flow information for SCE.
 
Nine months ended
September 30,
(in millions)
2011
 
2010
Net cash provided by operating activities
$
2,272

 
$
2,656

Net cash provided by financing activities
672

 
622

Net cash used by investing activities
(3,136
)
 
(2,883
)
Net increase (decrease) in cash and cash equivalents
$
(192
)
 
$
395

Net Cash Provided by Operating Activities
Net cash provided by operating activities decreased $384 million in the first nine months of 2011 compared to the first nine months of 2010. The decrease reflects net cash outflows related to regulatory balancing account activities and higher net tax receipts in 2010 primarily resulting from the impacts of the Global Settlement. As a result of the Global Settlement, SCE received net tax allocation payments from Edison International of approximately $295 million in 2010. These decreases were partially offset by higher receipts from customers due to increases in authorized revenues. The operating cash flows were also impacted by the timing of cash receipts and disbursements related to working capital.
Net Cash Provided by Financing Activities
Net cash provided by financing activities for the first nine months of 2011 was $672 million consisting of the following significant events:
•
Issued $500 million of 3.875% first and refunding mortgage bonds due in 2021. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.
•
Issued $550 million of commercial paper supported by SCE's line of credit to fund interim working capital requirements.
•
Issued $125 million of 6.5% Series D preference stock. The proceeds from the issuance were used for general corporate purposes.
•
Paid $345 million of dividends to Edison International.
•
Purchased $86 million of its variable rate tax-exempt bonds.
Net cash provided by financing activities for the first nine months of 2010 was $622 million consisting of the following significant events:
•
Issued $1 billion of first refunding mortgage bonds due in 2040 to fund SCE's capital program.
•
Reissued $144 million of tax-exempt pollution control bonds due in 2035 to fund SCE's capital program.
•
Repaid $250 million of senior unsecured notes.
•
Paid $200 million in dividends to Edison International.
Net Cash Used by Investing Activities
Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $3.0 billion and $2.7 billion for the nine months ended September 30, 2011 and 2010, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $146 million and $133 million for the nine months ended September 30, 2011 and 2010, respectively.


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Contractual Obligations and Contingencies
Contractual Obligations
SCE has power purchase commitments and firm transmission commitments which are discussed in "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
Contingencies
SCE has contingencies related to an Order Instituting Investigation ("OII") related to a 2007 wildfire in Malibu, California, nuclear insurance and spent nuclear fuel, which are discussed in "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
Environmental Remediation
As of September 30, 2011, SCE had 24 identified material sites for remediation and recorded an estimated minimum liability of $51 million. SCE expects to recover 90% of its remediation costs at certain sites. See "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies" for further discussion.
MARKET RISK EXPOSURES
SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. SCE uses derivative instruments, as appropriate, to manage its market risks. For a further discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Edison International Notes to Consolidated Financial Statements—Note 6. Derivative and Hedging Activities" and "Note 4. Fair Value Measurements" and see "SCE: Market Risk Exposures—Commodity Price Risk" in the year-ended 2010 MD&A.
Commodity Price Risk
The fair value of outstanding derivative instruments used to mitigate SCE's exposure to commodity price risk was a net liability of $641 million and $207 million at September 30, 2011 and December 31, 2010, respectively. For further discussion of fair value measurements and the fair value hierarchy, see "Edison International Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."
Credit Risk
Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these agreements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual agreements, including master netting agreements. As of September 30, 2011, the amount of balance sheet exposure as described above, by the credit ratings of SCE's counterparties, was as follows:
 
September 30, 2011
(in millions)
Exposure2
 
Collateral
 
Net Exposure
S&P Credit Rating1
 
 
 
 
 
A or higher
$
98

 
$
—

 
$
98

Not rated3
5

 
(1
)
 
4

Total
$
103

 
$
(1
)
 
$
102

1 
SCE assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.


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2 
Exposure excludes amounts related to contracts classified as normal purchases and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheets, except for any related net accounts receivable.
3 
The exposure in this category relates to long-term power purchase agreements. SCE's exposure is mitigated by regulatory treatment.
The credit risk exposure set forth in the table above is composed of $2 million of net accounts receivable and $101 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.



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EDISON MISSION GROUP
RESULTS OF OPERATIONS
Results of Continuing Operations
This section discusses operating results for the three- and nine-month periods ended September 30, 2011 and 2010. EMG's continuing operations include the coal plants, renewable energy and gas-fired projects and energy trading. EMG's discontinued operations include all international operations, except the Doga project.
The following table is a summary of competitive power generation results of operations for the periods indicated.
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Competitive power generation operating revenues
$
596

 
$
691

 
$
1,686

 
$
1,838

Fuel
242

 
228

 
597

 
602

Operation and maintenance
221

 
224

 
832

 
794

Depreciation and amortization
78

 
62

 
229

 
182

Other
—

 
—

 
8

 
3

Total operating expenses
541

 
514

 
1,666

 
1,581

Operating income
55

 
177

 
20

 
257

Interest and dividend income
1

 
4

 
31

 
28

Equity in income from unconsolidated affiliates – net
56

 
62

 
68

 
101

Other income, net
1

 
—

 
7

 
—

Interest expense
(81
)
 
(65
)
 
(244
)
 
(198
)
Income (loss) from continuing operations before income taxes
32

 
178

 
(118
)
 
188

Income tax expense (benefit)
(1
)
 
64

 
(103
)
 
(22
)
Income (loss) from continuing operations
33

 
114

 
(15
)
 
210

Income (loss) from discontinued operations – net of tax
—

 
(4
)
 
(3
)
 
4

Net income (loss)
33

 
110

 
(18
)
 
214

Less: Net income attributable to noncontrolling interests
—

 
—

 
(1
)
 
—

Net income (loss) available for common shareholder
$
33

 
$
110

 
$
(17
)
 
$
214

Core Earnings (Losses)1
$
33

 
$
120

 
$
(14
)
 
$
158

Non-Core Earnings (Losses)
 
 
 
 
 
 
 
Global Settlement
—

 
(6
)
 
—

 
52

Discontinued Operations
—

 
(4
)
 
(3
)
 
4

Total EMG GAAP Earnings (Losses)
$
33

 
$
110

 
$
(17
)
 
$
214

1 
See use of Non-GAAP financial measures in "Edison International Management Overview—Highlights of Operating Results."
EMG's third quarter 2011 core earnings were lower than third quarter 2010 core earnings primarily due to the following pre-tax items:
•
$81 million decrease in Midwest Generation adjusted operating income primarily due to lower capacity revenues, average realized energy prices and generation, and a gain in 2010 from the sale of bankruptcy claims against Lehman Brothers Commodity Services, Inc. and Lehman Brothers Holdings Inc. (“Lehman”).
•
$22 million decrease in Homer City adjusted operating income primarily due to lower capacity revenues and higher coal costs.
•
$16 million increase in interest expense primarily due to higher interest related to the new energy projects financings in 2011 of $6 million and lower capitalized interest of $11 million.
•
$16 million decrease in energy trading revenues partially due to reduced revenues from power trading activities. The


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decrease is also partially due to the allocation to Homer City the benefit of an arrangement that allows EMMT to deliver power into the New York Independent System Operator (“NYISO”) from Homer City. However, such decrease resulting from that allocation is offset by the increase recognized at Homer City due to the arrangement.
•
$10 million decrease in renewable energy adjusted operating income primarily due to lower capacity factors driven by wind conditions.
EMG's core earnings for the nine months ended September 30, 2011 were lower than core earnings for the nine months ended September 30, 2010 primarily due to the following pre-tax items:
•
$126 million decrease in Midwest Generation adjusted operating income primarily due to lower average realized energy prices and generation, and a gain in 2010 from the sale of bankruptcy claims against Lehman.
•
$85 million decrease in Homer City adjusted operating income primarily due to lower energy revenues driven by lower generation, lower capacity revenues and higher plant maintenance costs from outages. Partially offsetting the decrease were unrealized derivative gains of $3 million in 2011 compared to losses of $13 million in 2010.
•
$46 million increase in interest expense due to higher interest expense primarily related to the new energy projects financings in 2011 of $28 million and lower capitalized interest of $18 million.
•
$38 million decrease in energy trading revenue partially due to reduced revenues from power trading activities. The decrease is also partially due to the allocation to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. However, such decrease resulting from that allocation is offset by the increase recognized at Homer City due to the arrangement.
•
$12 million decrease in adjusted operating income from the Big 4 projects due to lower capacity prices under Midway-Sunset's new power purchase agreement and lower capacity and energy sales margin.
These decreases were partially offset by the following:
•
$11 million higher income from a distribution received from the Doga project in 2011, compared to 2010.
•
$6 million increase in renewable energy adjusted operating income due to the increase in wind projects in operation coupled with higher generation, partially offset by lower realized energy prices at the merchant wind projects.
Non-core item for EMG included:
•
An earnings benefit of $52 million recorded in the nine months ended September 30, 2010 related to the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service in 2009 for tax years 1986 through 2002 as part of the federal settlement of tax disputes and a revision to the interest on federal disputed tax items. See “-Income Taxes” below for more information.


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Adjusted Operating Income ("AOI")—Overview
The following section and table provide a summary of results of EMG's operating projects and corporate expenses for the third quarters of 2011 and 2010 and nine months ended September 30, 2011 and 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.
The following table shows the adjusted operating income (loss) of EMG's projects:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Midwest Generation plants
$
69

 
$
150

 
$
72

 
$
198

Homer City plant1
26

 
48

 
—

 
85

Renewable energy projects
(2
)
 
8

 
43

 
37

Energy trading1
11

 
27

 
67

 
105

Big 4 projects
26

 
33

 
37

 
49

Sunrise
29

 
27

 
28

 
30

Doga
—

 
—

 
26

 
15

Other projects2
1

 
—

 
10

 
24

Leveraged lease income
1

 
2

 
4

 
4

Other operating income (expense)
(1
)
 
(3
)
 
1

 
(2
)
 
160

 
292

 
288

 
545

Corporate administrative and general
(32
)
 
(37
)
 
(101
)
 
(111
)
Corporate depreciation and amortization
(6
)
 
(5
)
 
(18
)
 
(13
)
AOI3
$
122

 
$
250

 
$
169

 
$
421

1 
Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City.
2 
Includes March Point which was sold in 2010.
3 
AOI is equal to operating income (loss) under GAAP, plus equity in income (loss) of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests in AOI is meaningful for investors as these components are integral to the operating results of EMG.
The following table reconciles AOI to operating income as reflected on EMG's consolidated statements of operations:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
AOI
$
122

 
$
250

 
$
169

 
$
421

Less:
 
 
 
 
 
 
 
Equity in income of unconsolidated affiliates
56

 
61

 
68

 
100

Dividend income from projects
—

 
—

 
27

 
18

Production tax credits
10

 
12

 
47

 
45

Other income, net
1

 
—

 
7

 
1

Operating Income
$
55

 
$
177

 
$
20

 
$
257




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Adjusted Operating Income from Consolidated Operations
Midwest Generation Plants
The following table presents additional data for the Midwest Generation plants:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Operating Revenues
$
366

 
$
444

 
$
997

 
$
1,104

Operating Expenses
 
 
 
 
 
 
 
Fuel1
157

 
151

 
390

 
390

Plant operations
86

 
93

 
368

 
358

Plant operating leases
19

 
19

 
56

 
56

Depreciation and amortization
29

 
28

 
87

 
84

Asset retirements
—

 
—

 
9

 
3

Administrative and general
6

 
3

 
17

 
15

Total operating expenses
297

 
294

 
927

 
906

Operating Income
69

 
150

 
70

 
198

Other Income
—

 
—

 
2

 
—

AOI
$
69

 
$
150

 
$
72

 
$
198

Statistics
 
 
 
 
 
 
 
Generation (in GWh)
7,957

 
8,449

 
20,987

 
22,091

1 
Included in fuel costs were $1 million and $5 million during the third quarters of 2011 and 2010, respectively, and $3 million and $10 million during the nine months ended September 30, 2011 and 2010, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of NOx emission allowances to Midwest Generation were $0.4 million during each of the nine months ended September 30, 2011 and 2010, respectively. Transfers of SO2 emission allowances from Midwest Generation were none and $5 million during the nine months ended September 30, 2011 and 2010, respectively. For more information regarding the price of emission allowances, see "EMG: Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."
AOI from the Midwest Generation plants decreased $81 million for the third quarter ended September 30, 2011, compared to the corresponding period of 2010. The third quarter decrease in AOI was primarily attributable to lower energy and capacity revenues and a gain in 2010 from the sale of bankruptcy claims against Lehman. During the third quarter of 2010, EME sold its bankruptcy claims against Lehman and recorded a gain of $24 million. The decline in energy revenues was due to lower generation and lower average realized energy prices and the decline in capacity revenues was due to lower capacity prices from the RPM auction.

AOI from the Midwest Generation plants decreased $126 million for the nine months ended September 30, 2011, compared to the corresponding period of 2010. The 2011 decrease in AOI was primarily attributable to lower energy revenues and a gain in 2010 from the sale of the bankruptcy claims discussed above. The decline in energy revenues was due to lower average realized energy prices and lower generation due to the permanent shutdown of Will County Units 1 and 2 at the end of 2010 in accordance with the CPS.

Included in operating revenues were unrealized losses from hedge activities of $3 million and $16 million for the third quarters of 2011 and 2010, respectively, and $1 million and $12 million for the nine months ended September 30, 2011 and 2010, respectively. Unrealized losses in 2011 and 2010 were primarily attributable to economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of operations.

Included in fuel costs were unrealized gains (losses) of $(4) million and $2 million during the third quarters of 2011 and 2010, respectively, and $(6) million and $(5) million for the nine months ended September 30, 2011 and 2010, respectively. Unrealized gains (losses) were due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into in 2010 and 2009 to hedge variable fuel oil components of rail transportation costs.


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Homer City
The following table presents additional data for the Homer City plant:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Operating Revenues1
$
159

 
$
173

 
$
410

 
$
477

Operating Expenses
 
 
 
 
 
 
 
Fuel2
81

 
74

 
196

 
201

Plant operations
21

 
20

 
118

 
95

Plant operating leases
25

 
25

 
76

 
77

Depreciation and amortization
6

 
5

 
16

 
14

Asset retirements
—

 
—

 
—

 
1

Administrative and general
—

 
1

 
4

 
4

Total operating expenses
133

 
125

 
410

 
392

Operating Income
26

 
48

 
—

 
85

AOI
$
26

 
$
48

 
$
—

 
$
85

Statistics
 
 
 
 
 
 
 
Generation (in GWh)
2,800

 
2,984

 
6,969

 
8,227

1 
Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City.
2 
Included in fuel costs were $2 million and $1 million during the third quarters of 2011 and 2010, respectively, and $3 million and $6 million during the nine months ended September 30, 2011 and 2010, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of SO2 emission allowances to Homer City were none and $5 million during the nine months ended September 30, 2011 and 2010, respectively. Transfers of NOx emission allowances from Homer City were $0.4 million during each of the nine months ended September 30, 2011 and 2010. For more information regarding the price of emission allowances, see "EMG: Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."
AOI from the Homer City plant decreased $22 million for the third quarter ended September 30, 2011, compared to the corresponding period of 2010. The third quarter decrease in AOI was primarily attributable to lower capacity revenues and higher coal costs.

AOI from the Homer City plant decreased $85 million for nine months ended September 30, 2011, compared to the corresponding period of 2010. The 2011 decrease in AOI was attributable to lower energy revenues driven by lower generation, lower capacity revenues, and higher plant maintenance costs from outages at Units 1 and 2, partially offset by unrealized gains in 2011 compared to unrealized losses in 2010 related to hedge contracts and lower fuel costs. The decline in fuel costs was primarily due to lower generation, mostly offset by higher coal costs.

Included in operating revenues were unrealized gains (losses) from hedge activities of $(2) million and $1 million for the third quarters of 2011 and 2010, respectively, and $3 million and $(13) million for the nine months ended September 30, 2011 and 2010, respectively. Unrealized gains (losses) in 2011 were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the statements of operations and the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. Unrealized gains (losses) in 2010 were attributable to the ineffective portion of forward and futures contracts. The ineffective portion of hedge contracts at Homer City was attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City plant is delivered into the transmission system).
Seasonality—Coal Plants
Due to fluctuations in electric demand resulting from warm weather during the summer months and cold weather during the winter months, electric revenues from the coal plants normally vary substantially on a seasonal basis. In addition, maintenance


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outages generally are scheduled during periods of lower projected electric demand (spring and fall), further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, income from the coal plants is seasonal and has significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. For further discussion regarding market prices, see "EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk."
Renewable Energy Projects
The following table presents additional data for EMG's renewable energy projects:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Operating Revenues
$
44

 
$
29

 
$
155

 
$
93

Production Tax Credits
10

 
12

 
47

 
45

 
54

 
41

 
202

 
138

Operating Expenses
 
 
 
 
 
 
 
Plant operations
20

 
11

 
56

 
35

Depreciation and amortization
35

 
21

 
103

 
64

Administrative and general
1

 
1

 
3

 
2

Total operating expenses
56

 
33

 
162

 
101

Equity in loss from unconsolidated affiliates
(1
)
 
—

 
—

 
—

Other Income
1

 
—

 
3

 
—

AOI1
$
(2
)
 
$
8

 
$
43

 
$
37

Statistics
 
 
 
 
 
 
 
Generation (in GWh)2
953

 
764

 
3,893

 
2,599

1 
AOI is equal to operating income (loss) under GAAP plus equity in income (loss) of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expense, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based upon a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Under GAAP, production tax credits generated by wind projects are recorded as a reduction in income taxes. Accordingly, AOI represents a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in AOI for wind projects is meaningful for investors as federal and state subsidies are an integral part of the economics of these projects.
2 
Includes renewable energy projects that are unconsolidated at EME. Generation, excluding unconsolidated projects, was 819 GWh and 643 GWh in the third quarters of 2011 and 2010, respectively, and 3,356 GWh and 2,156 GWh in the nine months ended September 30, 2011 and 2010, respectively.
AOI from renewable energy projects decreased $10 million in the third quarter and increased $6 million in the nine months ended September 30, 2011, compared to the corresponding periods of 2010. The decrease in the third quarter was primarily due to lower capacity factors driven by wind conditions. The year-to-date increase was primarily due to projects that achieved commercial operation in late 2010 and 2011 and increased generation at other projects due to higher availability and favorable wind conditions during the first half of 2011, partially offset by lower realized prices from the merchant wind projects.
Energy Trading
AOI from energy trading activities decreased $16 million and $38 million for the third quarter and nine months ended September 30, 2011, respectively, compared to the corresponding periods of 2010. The third quarter and year-to-date decreases were partially due to reduced revenues from power trading activities and partially due to the allocation to Homer City of the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City.
Adjusted Operating Income from Other Projects
Big 4 Projects.    AOI from the Big 4 projects decreased in 2011, compared to the corresponding periods in 2010, primarily due to lower capacity prices under Midway-Sunset's new power purchase agreement and lower capacity and energy sales margin.



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Doga.    EMG received distributions of $26 million from the Doga project in the second quarter of 2011 and $15 million in the first quarter of 2010. The increase in distribution is primarily due to elimination of restricted cash as a result of the repayment of the remaining project debt. AOI is recognized when cash is distributed from the project as the Doga project is accounted for on the cost method.
March Point.    During the first quarter of 2010, AOI from the March Point project was $17 million due to an equity distribution received from the project. EMG subsequently sold its ownership interest in the March Point project to its partner in February 2010.
Seasonality.    EMG's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.
Interest Expense
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Interest expense, net of capitalized interest
 
 
 
 
 
 
 
EME debt
$
(66
)
 
$
(56
)
 
$
(191
)
 
$
(174
)
Non-recourse debt
(15
)
 
(9
)
 
(53
)
 
(24
)
 
$
(81
)
 
$
(65
)
 
$
(244
)
 
$
(198
)
EMG's interest expense increased primarily due to higher debt balances for wind project financing and lower capitalized interest. Capitalized interest for renewable energy projects under construction was $4 million and $20 million for the third quarter and nine months ended September 30, 2011, respectively, compared to $15 million and $38 million for the third quarter and nine months ended September 30, 2010, respectively.
Income Taxes
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Income (loss) from continuing operations before income taxes
$
32

 
$
178

 
$
(118
)
 
$
188

Provision (benefit) for income taxes at federal statutory rate of 35%
$
11

 
$
62

 
$
(41
)
 
$
66

Increase (decrease) in income tax from:
 
 
 
 
 
 
 
State tax – net of federal provision (benefit)
1

 
8

 
(8
)
 
9

Tax credits, net
(12
)
 
(16
)
 
(49
)
 
(50
)
Global Settlement related
—

 
6

 
—

 
(52
)
Other
(1
)
 
4

 
(5
)
 
5

Total income tax expense (benefit)
$
(1
)
 
$
64

 
$
(103
)
 
$
(22
)
Effective tax rate
(3
)%
 
36
%
 
87
%
 
(12
)%
For a discussion of the status of Edison International's income tax audits, see "Edison International Notes to Consolidated Financial Statements—Note 7. Income Taxes."


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LIQUIDITY AND CAPITAL RESOURCES
Available Liquidity
The following table summarizes available liquidity at September 30, 2011:
(in millions)
Cash and Cash
Equivalents
 
Available
Under Credit
Facilities
 
Total
Available
Liquidity
EME as a holding company
$
539

 
$
499

 
$
1,038

EME subsidiaries without contractual dividend restrictions
195

 
—

 
195

EME corporate cash and cash equivalents
734

 
499

 
1,233

EME subsidiaries with contractual dividend restrictions
 
 
 
 
 
Midwest Generation1
333

 
497

 
830

Homer City
108

 
—

 
108

Other EME subsidiaries
60

 
—

 
60

Other EMG subsidiaries
41

 
 
 
41

Total
$
1,276

 
$
996

 
$
2,272

1 
Cash and cash equivalents are available to meet Midwest Generation's operating and capital expenditure requirements.
EME, as a holding company, does not directly operate any revenue-producing generation facilities. EME relies on cash distributions and tax payments from its projects to meet its obligations, including debt service obligations on long-term debt. The timing and amount of distributions from EME's subsidiaries may be restricted. For further details, see "—Debt Covenants and Dividend Restrictions."
The following table summarizes the status of the EME and Midwest Generation credit facilities at September 30, 2011, which mature in June 2012:
(in millions)
EME
 
Midwest
Generation
Commitments
$
564

 
$
500

Outstanding borrowings
—

 
—

Outstanding letters of credit
(65
)
 
(3
)
Amount available
$
499

 
$
497

EME and Midwest Generation may seek to extend or replace credit facilities or retire them by other means. The terms and conditions of any refinancing could be substantially different than those in the current credit facilities. Senior notes in the principal amount of $500 million, which bear interest at 7.50% per annum, are due in June 2013. EME may also from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, open market purchases, privately negotiated transactions or otherwise, depending on prevailing market conditions, EME's liquidity requirements, contractual restrictions and other factors.
Homer City Outage
During the first half of 2011, Homer City Units 1 and 2 were off line due to a steam pipe rupture at Unit 1 and precautionary maintenance at Unit 2. While Unit 1 returned to service on April 5, 2011 and Unit 2 on May 25, 2011, the outages and the continuation of low power prices impacted Homer City's liquidity. As a result, in order to have sufficient working capital available for operating expenses and to pay the equity portion of Homer City's rent payment that was due April 1, 2011 to the owner-lessors, Homer City had to defer certain fuel deliveries, arrange for accelerated payments by EMMT for future energy deliveries under an intercompany arrangement in place between EMMT and Homer City, and draw $12 million from the $20 million equity rent reserve established under its sale-leaseback transaction documents. At September 30, 2011, the equity rent reserve balance was restored back to $20 million, and Homer City had delivered energy sufficient to eliminate the accelerated payments by EMMT. Homer City must continue to make equity rent payments in order to be entitled to make future distributions. Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. Accordingly, since April 1, 2011, these revenues have been recorded as part of


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Homer City's revenues in lieu of their prior classification as EMMT trading revenues. EMMT realized trading revenues of $28 million under this arrangement in 2010.

The actions described above also resulted in Homer City being in compliance with the covenant requirements of its sale-leaseback documents relating to the payment of equity rent at April 1, 2011. For additional discussion regarding Homer City's liquidity, see "Edison International Management Overview—Management Overview of EMG—Cross-State Air Pollution Rule" and "—Homer City Capital Needs."
Capital Investment Plan
Forecasted capital expenditures through 2013 by EMG's subsidiaries for existing projects, corporate activities and turbine commitments are as follows:
(in millions)
October through
December 2011
 
2012
 
2013
Midwest Generation Plants
 
 
 
 
 
Environmental1
$
26

 
$
172

 
$
316

Plant capital
5

 
22

 
29

Homer City Plant
 
 
 
 
 
Environmental1
13

 
—

 
—

Plant capital
1

 
26

 
16

Walnut Creek Project
78

 
223

72

72

Renewable Energy Projects
 
 
 
 
 
Capital and construction
92

 
108

 
—

Other capital
5

 
14

 
14

Total
$
220

 
$
565

 
$
447

1 
For additional information, see "Edison International Management Overview—Management Overview of EMG—Cross-State Air Pollution Rule."
Environmental Capital Expenditures
Midwest Generation plants' environmental expenditures include $13 million for remaining expenditures in 2011 related to selective non-catalytic reduction ("SNCR") equipment and $501 million for expenditures for the remainder of 2011 to 2013 to begin to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions, assuming all units are retrofitted for an estimated aggregate cost of $1.2 billion. EMG believes that Midwest Generation's current environmental remediation plan developed to comply with the CPS, along with the allowances allocated to it under CSAPR, will be sufficient to comply with the requirements of CSAPR and the US EPA's proposed regulation on HAP emissions. In order to achieve compliance, Midwest Generation has begun work to install SO2 controls at certain of its plants. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with CPS and other requirements, 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. Accordingly, the environmental expenditures for Midwest Generation in the preceding table represent current projects only and are subject to change based upon a number of considerations. Actual expenditures could be higher or lower. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to continue or complete the project. For additional discussion, see "Edison International Management Overview—Management Overview of EMG—Midwest Generation Environmental Compliance Plans and Costs."
The capital investment plan set forth in the previous table does not include environmental capital expenditures that Homer City will be required to undertake to meet the requirements of CSAPR. The timing, selection of technology and ultimate capital costs remain uncertain. For a discussion of environmental regulations, see "Edison International Management Overview—Management Overview of EMG—Cross-State Air Pollution Rule" and "—Homer City Capital Needs" in this MD&A, and "Item 1. Environmental Regulation of Edison International and Subsidiaries" and "Item 1A. Risk Factors—Risks Relating to EMG—Regulatory and Environmental Risks" in the 2010 Form 10-K.


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Plant Capital Expenditures
Plant capital expenditures in the preceding table relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, generator stator rewinds, and development of a coal-cleaning plant refuse site and a new ash disposal site.
Renewable Energy Projects
In the third quarter of 2011, EMG acquired the 80 MW Broken Bow I and the 40 MW Crofton Bluffs wind projects. Commercial operations of the Broken Bow I and the Crofton Bluffs projects are expected in the fourth quarter of 2012. The Taloga wind project achieved commercial operation on July 13, 2011.

At September 30, 2011, EMG had a development pipeline of potential wind projects with projected installed capacity of approximately 3,800 MW. The development pipeline represents potential wind projects with respect to which EMG either owns the project rights or has exclusive acquisition rights. The pace of additional growth in EMG's renewable program will be subject to the availability of third-party equity capital. At September 30, 2011, EMG had capitalized costs and turbine deposits totaling $26 million related to renewable energy development efforts. To the extent that the renewable energy projects are not successful, EMG would record a charge to write down the carrying amount of these assets.
Funding of Capital Expenditures
In July, EME secured $495 million in construction and term financing for the Walnut Creek project. For additional information on the Walnut Creek project, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Project Financings—Walnut Creek." EMG anticipates that the capital investment for renewable energy projects under construction will be funded using a combination of construction and term financings, U.S. Treasury grants and cash on hand. EMG received a total of $310 million of U.S. Treasury grants in the third quarter of 2011 and used $57 million to repay the Laredo Ridge bridge loan. Additional U.S. Treasury grants of approximately $135 million are anticipated for the remainder of 2011 and in 2012 based on estimated eligible construction costs for renewable energy projects.
Historical Segment Cash Flows
The table below sets forth condensed historical cash flow information for EMG.
Condensed Statement of Cash Flows
 
Nine months ended
September 30,
(in millions)
2011
 
2010
Operating cash flow from continuing operations
$
567

 
$
289

Operating cash flow from discontinued operations
(3
)
 
4

Net cash provided by operating activities
564

 
293

Net cash provided by financing activities
112

 
83

Net cash used by investing activities
(498
)
 
(443
)
Net increase (decrease) in cash and cash equivalents
$
178

 
$
(67
)
Net Cash Provided by Operating Activities
The increase in the first nine months of 2011 as compared to the first nine months of 2010 in cash provided by operating activities from continuing operations was primarily attributable to a $253 million deposit paid by Edison Capital to the IRS in 2010 related to the Global Settlement, tax-allocation payments received by EME in 2011 of $182 million compared to $100 million in 2010, and $310 million of U.S. Treasury grants received in 2011 compared to $92 million in 2010. These increases were partially offset by lower pre-tax income.
Net Cash Provided by Financing Activities
The increase in the first nine months of 2011 as compared to the first nine months of 2010 in cash provided by financing activities from continuing operations was primarily attributable to borrowings at the Walnut Creek gas project in 2011, partially offset by higher borrowings at wind projects in 2010 than in 2011.


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Net Cash Provided by Investing Activities
Cash used in investing activities for the first nine months of 2011 and 2010 primarily consisted of capital expenditures for construction of energy projects and other plant improvements.
Credit Ratings
Overview
Credit ratings for EME, Midwest Generation and EMMT as of September 30, 2011 were as follows:
 
Moody's Rating
 
S&P Rating
 
Fitch Rating
EME1
Caa1
 
B-
 
CCC
Midwest Generation2
Ba3
 
B+
 
BB-
EMMT
Not Rated
 
B-
 
Not Rated
1 
Senior unsecured rating.
2 
First priority senior secured rating.
All the above ratings are on negative outlook. EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.
EMG does not have any "rating triggers" contained in subsidiary financings that would result in a requirement to make equity contributions or provide additional financial support to its subsidiaries, including EMMT. However, coal contracts at Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. As of September 30, 2011, there were no open positions under hedge contracts that would require EMMT to provide adequate assurance in the form of additional credit support.
Credit Rating of EMMT
For a discussion of the effect of EMMT's credit rating on EMG's ability to sell forward the output of the Homer City plant through EMMT, refer to "EMG: Liquidity and Capital Resources—Credit Ratings—Credit Rating of EMMT" in the year-ended 2010 MD&A.
Margin, Collateral Deposits and Other Credit Support for Energy Contracts
To reduce its exposure to market risk, EME hedges a portion of its electricity price exposure through EMMT. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EME has entered into guarantees in support of EMMT's hedging and trading activities. However, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses, and unrealized gains in connection with these hedging and trading activities. For further details, see "Edison International Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."
Future cash collateral requirements may be higher than the margin and collateral requirements at September 30, 2011 if wholesale energy prices change or if EMMT enters into additional transactions. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding at September 30, 2011 could increase by approximately $82 million over the remaining life of the contracts using a 95% confidence level.


67
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Debt Covenants and Dividend Restrictions
Credit Facility Financial Ratios
EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-capital ratio as such terms are defined in the credit facility.
The following table sets forth the interest coverage ratio:
 
Twelve months ended
 
September 30,
2011
 
December 31,
2010
Ratio
2.49

 
2.07

Covenant threshold (not less than)
1.20

 
1.20

The following table sets forth the corporate-debt-to-capital ratio:
 
September 30,
2011
 
December 31,
2010
Corporate-debt-to-capital ratio
0.52

 
0.52

Covenant threshold (not more than)
0.75

 
0.75

Key Ratios of EMG's Principal Subsidiaries Affecting Dividends
Set forth below are key ratios of EMG's principal subsidiaries required by financing arrangements at September 30, 2011 or for the 12 months ended September 30, 2011:
Subsidiary
Financial Ratio
 
Covenant
 
Actual
Midwest Generation (Midwest Generation plants)
Debt to Capitalization Ratio
 
Less than or equal to 0.60 to 1
 
0.13 to 1
Homer City (Homer City plant)
Senior Rent Service Coverage Ratio
 
Greater than 1.7 to 1
 
1.64 to 1
As indicated above, the actual senior rent service coverage ratio was below the covenant threshold for the 12 months ended September 30, 2011, which currently precludes Homer City from making distributions, including repayment of certain intercompany loans. For additional information, see “Management's Overview of EMG—Homer City Capital Needs and Liquidity” and "Edison Mission Group—Liquidity and Capital Resources—Available Liquidity—Homer City Outage" in this MD&A.
For a more detailed description of the covenants binding EMG's principal subsidiaries that may restrict the ability of those entities to make distributions to EMG directly or indirectly through the other holding companies owned by EMG, refer to "EMG: Liquidity and Capital Resources—Debt Covenants and Dividend Restrictions" in the year ended 2010 MD&A.
EME's Senior Notes and Guaranty of Powerton-Joliet Leases
EME is restricted under applicable agreements from selling or disposing of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding the sale or disposition in question. At September 30, 2011, the maximum permissible sale or disposition of EME assets was $898 million.
This limitation does not apply if the proceeds are invested in assets in similar or related lines of business of EME. Furthermore, EME may sell or otherwise dispose of assets in excess of such 10% limitation if the proceeds from such sales or dispositions, which are not reinvested as provided above, are retained as cash or cash equivalents or are used to repay debt.


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Contractual Obligations and Contingencies
Fuel Supply Contracts and Coal Transportation Agreements
For a discussion of fuel supply contracts and coal transportation agreements, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments—Fuel Supply Contracts and Coal Transportation Agreements."
Turbine Commitments
For a discussion of turbine commitments, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments—Turbine Commitments."
Capital Commitments
For a discussion of capital commitments, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments—Capital Commitments."
Midwest Generation New Source Review and Other Litigation
For a discussion of the Midwest Generation New Source Review lawsuit, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review and Other Litigation."
Homer City New Source Review and Other Litigation
For a discussion of the Homer City New Source Review lawsuit, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies—Homer City New Source Review and Other Litigation."
Off-Balance Sheet Transactions
For a discussion of EMG's off-balance sheet transactions, refer to "EMG: Liquidity and Capital Resources—Off-Balance Sheet Transactions" in the year ended 2010 MD&A. There have been no significant developments with respect to EMG's off-balance sheet transactions that affect disclosures presented in the 2010 Form 10-K.
MARKET RISK EXPOSURES
For a detailed discussion of EMG's market risk exposures, including commodity price risk, credit risk and interest rate risk, refer to "EMG: Market Risk Exposures" in the year ended 2010 MD&A.


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Derivative Instruments
Unrealized Gains and Losses
EMG classifies unrealized gains and losses from derivative instruments (other than the effective portion of derivatives that qualify for hedge accounting) as part of operating revenues or fuel costs. The following table summarizes unrealized gains (losses) from non-trading activities:
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions)
2011
 
2010
 
2011
 
2010
Midwest Generation plants
 
 
 
 
 
 
 
Non-qualifying hedges
$
(8
)
 
$
(12
)
 
$
(7
)
 
$
(18
)
Ineffective portion of cash flow hedges
1

 
(2
)
 
—

 
1

Homer City plant
 
 
 
 
 
 
 
Non-qualifying hedges
(6
)
 
—

 
(3
)
 
—

Ineffective portion of cash flow hedges
4

 
1

 
6

 
(13
)
Total unrealized losses
$
(9
)
 
$
(13
)
 
$
(4
)
 
$
(30
)
At September 30, 2011, cumulative unrealized losses of $2 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods (unrealized losses of $5 million for the remainder of 2011 and unrealized gains of $3 million for 2012).
Fair Value Disclosures
In determining the fair value of EMG's derivative positions, EMG uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EMG's derivative instruments, see "Edison International Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements" and "Note 6. Derivative Instruments and Hedging Activities," respectively.
Commodity Price Risk
Energy Price Risk
Energy and capacity from the coal plants are sold under terms, including price, duration and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Power is sold into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to generation are generally entered into at the Northern Illinois Hub, and to a lesser extent, the AEP/Dayton and Cinergy Hubs, all in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City plant. In addition, energy hedging transactions may be entered into using natural gas. Energy from 428 MW of merchant renewable energy projects is sold in the energy markets, primarily at spot prices in PJM and the Electric Reliability Council of Texas (ERCOT).
The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first nine months of 2011 and 2010:
 
24-Hour Average
Historical Market Prices1
 
2011
 
2010
Midwest Generation plants
 
 
 
Northern Illinois Hub
$
35.39

 
$
35.02

Homer City plant
 
 
 
PJM West Hub
46.38

 
46.65

Homer City Busbar
42.14

 
39.80

1 
Energy prices were calculated at the Northern Illinois Hub and Homer City Busbar delivery points and the PJM West Hub using historical hourly real-time prices as published by PJM or provided on the PJM web-site.


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The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at September 30, 2011:
 
24-Hour Forward Energy Prices1
 
Northern
Illinois Hub
 
PJM West Hub
2011
 
 
 
October
$
26.05

 
$
38.10

November
27.27

 
38.97

December
31.10

 
46.02

2012 calendar "strip"2
33.67

 
45.46

2013 calendar "strip"2
36.48

 
48.46

1 
Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub and PJM West Hub delivery points.
2 
Market price for energy purchases for the entire calendar year.
Forward market prices at the Northern Illinois Hub and PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the coal plants into these markets may vary materially from the forward market prices set forth in the preceding table.
EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services contracts and forward contracts accounted for on the accrual basis) at September 30, 2011 for electricity expected to be generated during the remainder of 2011 and in 2012 and 2013:
 
2011
 
2012
 
2013
 
MWh (in
thousands)
 
Average
price/
MWh1
 
MWh (in
thousands)
 
Average
price/
MWh1
 
MWh (in
thousands)
 
Average
price/
MWh1
Midwest Generation plants2
 
 
 
 
 
 
 
 
 
 
 
Northern Illinois
3,959

 
$
38.61

 
8,206

 
$
37.60

 
1,020

 
$
39.11

Homer City plant3,4
 
 
 
 
 
 
 
 
 
 
 
PJM West Hub
1,145

 
51.37

 
1,319

 
51.79

 
204

 
51.85

Total
5,104

 
 

 
9,525

 
 

 
1,224

 
 

1 
The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions are not directly comparable to the 24-hour Northern Illinois Hub or PJM West Hub prices set forth above.
2 
Includes hedging transactions primarily at the Northern Illinois Hub and to a lesser extent the AEP/Dayton and Cinergy Hubs.
3 
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.
4 
The average price/MWh includes 165 MW of capacity for periods ranging from October 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.


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Capacity Price Risk
The following table summarizes the status of capacity sales for Midwest Generation and Homer City at September 30, 2011:
 
Installed
Capacity
MW
 
Unsold
Capacity1
MW
 
Capacity
Sold2
MW
 
RPM Capacity
Sold in Base
Residual Auction
 
Other Capacity Sales,
Net of Purchases3
 
Aggregate
Average
Price per
MW-day
 
 
 
 
 
MW
 
Price per
MW-day
 
MW
 
Average
Price per
MW-day
 
 
October 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

 
(163
)
 
1,721

 
1,771

 
110.00

 
(50
)
 
30.00

 
112.32

 
June 1, 2012 to May 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midwest Generation
5,477

 
(773
)
 
4,704

 
4,704

 
16.46

 
—

 
—

 
16.46

 
Homer City
1,884

 
(232
)
 
1,652

 
1,736

 
133.37

 
(84
)
 
16.46

 
139.31

 
June 1, 2013 to May 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midwest Generation
5,477

 
(827
)
 
4,650

 
4,650

 
27.73

 
—

 
—

 
27.73

 
Homer City
1,884

 
(104
)
 
1,780

 
1,780

 
226.15

 
—

 
—

 
221.03

4 
June 1, 2014 to May 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midwest Generation
5,477

 
(852
)
 
4,625

 
4,625

 
125.99

 
—

 
—

 
125.99

 
Homer City
1,884

 
(190
)
 
1,694

 
1,694

 
136.50

 
—

 
—

 
136.50

 
1 
Capacity not sold arises from: (i) capacity retained to meet forced outages under the RPM auction guidelines, and (ii) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.
2 
Excludes 165 MW of capacity for periods ranging from October 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.
The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 and June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the prices of $16.46 per MW-day and $27.73 per MW-day were substantially lower than other areas' capacity prices. The impact of lower capacity prices for these periods compared to previous years will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by an unavailability of competing resources and increased energy prices.
Basis Risk
During the nine months ended September 30, 2011 and 2010, prices at the Homer City busbar were lower than the PJM West Hub by an average of 9% and 15%, respectively, due to transmission congestion in PJM. During the nine months ended September 30, 2011, prices at the individual busbars of the Midwest Generation plants were lower than the AEP/Dayton Hub, Cinergy Hub and Northern Illinois Hub by an average of 12%, 1% and 1%, respectively, compared to 10%, 1% and 1%, respectively, during the nine months ended September 30, 2011, due to transmission congestion in PJM.


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Coal and Transportation Price Risk
The Midwest Generation plants and Homer City plant purchase coal primarily from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at September 30, 2011 for the remainder of 2011 and the following three years:
 
Amount of Coal Under Contract
in Millions of Equivalent Tons1
 
October through
December 2011
 
2012
 
2013
 
2014
Midwest Generation plants
5.0

 
13.7

 
9.8

 
9.8

Homer City plant
1.8

 
2.2

 
0.8

 
—

1 
The amount of coal under contract in equivalent tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Midwest Generation plants and 13,000 Btu equivalent for the Homer City plant.
EMG is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal are related to the price of coal purchased for the Homer City plant. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) increased to a price of $77.25 per ton at September 30, 2011, compared to a price of $70 per ton at December 31, 2010, as reported by the Energy Information Administration.

Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content) purchased for the Midwest Generation plants fluctuated between $12.35 per ton and $15 per ton during the first nine months of 2011. The market price of PRB coal increased to a price of $15 per ton at September 30, 2011, compared to a price of $13.60 per ton at December 31, 2010, as reported by the Energy Information Administration.

EMG has contracts for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various short-haul carriers), which extends through December 31, 2011. EMG is exposed to price risk related to transportation rates after the expiration of its existing transportation contracts. Current market transportation rates for PRB coal are materially higher than the existing rates under contract. EMG expects to finalize a new long-term contract for the transport of coal during the fourth quarter of 2011.
Emission Allowances Price Risk
Under CSAPR, beginning January 1, 2012, the amount of SO2 that a plant emits in its operation will need to be matched by a sufficient amount of SO2 allowances designated under this program (CSAPR SO2 allowances) that are either allocated to the plant under the CSAPR program or purchased in the open market. SO2 allowances under the federal Acid Rain Program cannot be used to satisfy the requirements under CSAPR. EMG will be impacted by market prices for additional CSAPR SO2 allowances required, but availability and market prices are uncertain. For additional information on CSAPR, see “Edison International Management Overview—Management Overview of EMG—Cross-State Air Pollution Rule” and "Edison International Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments—Environmental Developments—Cross-State Air Pollution Rule."


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Credit Risk
The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EMG's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At September 30, 2011, the balance sheet exposure as described above, by the credit ratings of EMG's counterparties, was as follows:
 
September 30, 2011
(in millions)
Exposure2
 
Collateral
 
Net Exposure
Credit Rating1
 
 
 
 
 
A or higher
$
105

 
$
(7
)
 
$
98

A-
2

 
—

 
2

BBB+
15

 
—

 
15

BBB-
7

 
—

 
7

Below investment grade
24

 
(23
)
 
1

Total
$
153

 
$
(30
)
 
$
123

1 
EMG assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.
2 
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.
The credit risk exposure set forth in the above table is composed of $87 million of net accounts receivable and payables and $67 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EMG's subsidiaries have posted a $44 million cash margin in the aggregate with PJM, NYISO, Midwest Independent Transmission System Operator (MISO), clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EMG to credit risk of the related entities.
The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 70% of EMG's consolidated operating revenues for the nine months ended September 30, 2011. At September 30, 2011, EMG's account receivable due from PJM was $58 million.
EMG's wind turbine supply agreements contain significant suppliers' obligations related to the manufacturing and delivery of turbines, and payments, for delays in delivery and for failure to meet performance obligations and warranty agreements. EMG's reliance on these contractual provisions is subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to EMG's turbine suppliers may have a material impact on EMG's wind projects and development efforts.
Interest Rate Risk
Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EMG mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. For details, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements," and refer to "Note 5 Debt and Credit Agreements" in Item 8 of Edison International's 2010 Form 10-K.



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EDISON INTERNATIONAL PARENT AND OTHER
RESULTS OF OPERATIONS
Results of operations for Edison International Parent and Other includes amounts from other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.
Edison International Parent and Other income (loss) from continuing operations was $(13) million and $6 million for the three months ended September 30, 2011 and 2010, respectively, and $(19) million and $18 million for the nine months ended September 30, 2011 and 2010, respectively. Results for the three- and nine-month periods ended September 30, 2010 included consolidated tax benefits from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement of $1 million and $28 million, respectively.
Results for the three- and nine-month periods ended September 30, 2011 included consolidated tax expense (benefit) of $4 million and $(7) million, respectively, compared to $(14) million and $(10) million for the respective periods in 2010, from differences in the allocation of state income taxes to subsidiaries under tax allocation agreements.
LIQUIDITY AND CAPITAL RESOURCES
Edison International Parent liquidity and its ability to pay operating expenses and dividends to common shareholders is dependent on dividends from SCE, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capital markets.
At September 30, 2011, Edison International (parent) had $21 million of cash and equivalents on hand. The following table summarizes the status of the Edison International (parent) credit facility at September 30, 2011:
(in millions)
Edison
International
(parent)
Commitment
$
1,426

Outstanding borrowings
(10
)
Outstanding letters of credit
—

Amount available
$
1,416

Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1. At September 30, 2011, Edison International's consolidated debt to total capitalization ratio was 0.54 to 1.
Historical Cash Flows
Condensed Statement of Cash Flows
The table below sets forth condensed historical cash flow information for Edison International Parent and Other.
 
Nine months ended
September 30,
(in millions)
2011
 
2010
Net cash used by operating activities
$
(13
)
 
$
(200
)
Net cash provided by financing activities
21

 
200

Net cash provided by investing activities
1

 
7

Net increase in cash and cash equivalents
$
9

 
$
7

Net Cash Used by Operating Activities
Net cash used by operating activities primarily relates to interest, operating costs and income taxes of Edison International (parent). During the nine months ended September 30, 2010, Edison International received $134 million in taxes related to the Global Settlement and made tax allocation payments to SCE of $295 million.


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Net Cash Provided (Used) by Financing Activities
Financing activities for the first nine months of 2011 were as follows:
•
Paid $313 million of dividends to Edison International common shareholders.
•
Received $345 million of dividend payments from SCE.
•
Repaid $9 million under Edison International's line of credit.
Financing activities for the first nine months of 2010 were as follows:
•
Issued $400 million of senior notes due in 2017. The proceeds from these bonds were used to repay short-term borrowings under the revolving credit facility and the remainder for corporate liquidity purposes.
•
Paid $308 million of dividends to Edison International common shareholders.
•
Received $200 million of dividend payments from SCE.
•
Repaid $85 million under Edison International's line of credit.



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EDISON INTERNATIONAL (CONSOLIDATED)
LIQUIDITY AND CAPITAL RESOURCES
Contractual Obligations
Significant changes with respect to Edison International (Consolidated) contractual obligations since the filing of the 2010 Form 10-K are discussed in "EMG: Liquidity and Capital Resources—Contractual Obligations and Contingencies" and "SCE: Liquidity and Capital Resources—Contractual Obligations and Contingencies."
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
For a discussion of Edison International's critical accounting estimates and policies, see "Critical Accounting Estimates and Policies" in the year ended 2010 MD&A.
NEW ACCOUNTING GUIDANCE
New accounting guidance is discussed in "Edison International Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to this item is included in the MD&A under the headings "SCE: Market Risk Exposures" and "EMG: Market Risk Exposures" and is incorporated herein by reference.
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Edison International's management, under the supervision and with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of Edison International's disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, Edison International's disclosure controls and procedures are effective.
Internal Control Over Financial Reporting

There were no changes in Edison International’s internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the period to which this report relates that have materially affected, or are reasonably likely to materially affect, Edison International’s internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For a discussion of Edison International's legal proceedings, refer to "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies" in the 2010 Form 10-K. There have been no significant developments with respect to legal proceedings specifically affecting Edison International since the filing of the 2010 Form 10-K, except as follows:
California Coastal Commission Potential Environmental Proceeding
In May 2010, the California Coastal Commission issued an NOV to SCE, its contractor, and property owners ("NOV Recipients") related to activity on a property that was used for equipment storage related to a nearby SCE electricity line undergrounding construction project. The NOV alleged that SCE, through its contractor, violated the California Coastal Act by removing without the appropriate permits approximately one acre of vegetation from the property, which was located in a protected coastal zone within and adjacent to the City of Newport Beach, California. In late 2010, SCE tendered an indemnification claim to its contractor for liability associated with the NOV, which the contractor accepted. In April 2011, the NOV Recipients entered into a Consent Order with the Coastal Commission to resolve the NOV Recipients' liability to the Coastal Commission under the Coastal Act. On June 10, 2011, the NOV Recipients entered into a Settlement Agreement to


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resolve any remaining claims among themselves pertaining to the NOV.
Navajo Nation Litigation
Developments related to the Navajo Nation litigation are discussed in "SCE Notes to Consolidated Financial Statements Note 9. Commitments and Contingencies—Contingencies—Navajo Nation Litigation."
Midwest Generation New Source Review and Other Litigation
Nine of ten PSD claims in the US EPA's New Source Review litigation have been dismissed, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court has also dismissed all claims asserted against Commonwealth Edison and EME. The court denied a motion to dismiss a claim by the Chicago-based environmental action groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the court that the statute of limitations should be equitably tolled. The court did not address other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA. Trial of the liability portion of the case is scheduled to commence June 3, 2013. A motion filed by the plaintiffs requesting that the dismissals be certified as “partial final judgments” capable of appeal, and requesting that the remaining claims be stayed pending such an appeal, is pending.
In May 2011, two complaints were filed against Midwest Generation in the Northern District of Illinois by residents living near the Crawford and Fisk facilities on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs sought to have their suits certified as a class action and requested injunctive relief, as well as compensatory and punitive damages. In October 2011, the complaints were dismissed for lack of federal jurisdiction.
Homer City New Source Review and Other Litigation
On October 12, 2011, all of the claims in the US EPA's New Source Review litigation were dismissed with prejudice. On October 13, 2011, the claims in the purported class action that were based on the federal CAA were dismissed with prejudice, while state law statutory and common law claims were dismissed without prejudice to re-file in state court should the plaintiffs choose to do so.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Period
(a) Total
Number of
Shares
(or Units)
Purchased1
 
(b) Average Price
Paid per Share
(or Unit)1
 
(c) Total
Number of
Shares
(or Units)
Purchased
as Part of
Publicly
Announced
Plans or
Programs
 
(d) Maximum
Number (or
Approximate
Dollar Value)
of Shares
(or Units) that
May Yet Be
Purchased
Under the Plans
or Programs
July 1, 2011 to July 31, 2011
160,830

 
$
38.44

 
—

 
—

August 1, 2011 to August 31, 2011
1,017,331

 
$
36.48

 
—

 
—

September 1, 2011 to September 30, 2011
485,092

 
$
36.66

 
—

 
—

Total
1,663,253

 
$
36.72

 
—

 
—

1 
The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill requirements in connection with Edison International's: (i) 401(k) Savings Plan; (ii) Dividend Reinvestment and Direct Stock Purchase Plan; and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan terms or participant elections. The shares were never registered in Edison International's name and none of the shares purchased were retired as a result of the transactions.


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ITEM 5. OTHER INFORMATION

On October 27, 2011, the Edison International Board of Directors amended the emergency provisions of the Edison International Bylaws to reduce the period of notice required to call a meeting in an emergency and to eliminate other special emergency provisions. In addition to the amendments to the emergency provisions, the Edison International Bylaws were amended to: (1) clarify that the place of shareholder and Board meetings may be designated in the meeting notice, and (2) shorten the normal Board meeting notice requirement from 48 to 24 hours.

ITEM 6. EXHIBITS
3.1

Bylaws of Edison International, as amended October 27, 2011
 
 
31.1

Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
 
 
31.2

Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
 
 
32

Statement Pursuant to 18 U.S.C. Section 1350
 
 
101

Financial statements from the quarterly report on Form 10-Q of Edison International for the quarter ended September 30, 2011, filed on November 2, 2011, formatted in XBRL: (i) the Consolidated Statements of Income; (ii) the Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; and (v) the Notes to the Consolidated Financial Statements
 

 
 


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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EDISON INTERNATIONAL
(Registrant)
By:
 
/s/ Mark C. Clarke
 
 
 
 
 
 
 
 
Mark C. Clarke
Vice President and Controller
(Duly Authorized Officer and
Principal Accounting Officer)
Date: November 2, 2011


80