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SOUTHERN CALIFORNIA EDISON Co - 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 1-2313
____________________________________________________
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
____________________________________________________
California
(State or other jurisdiction of
incorporation or organization)
 
95-1240335
(I.R.S. Employer
Identification No.)
 
 
 
2244 Walnut Grove Avenue
(P. O. Box 800)
Rosemead, California
(Address of principal executive offices)
 
91770
(Zip Code)
 
 
 
(626) 302-1212
(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 o
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 o    No o
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 o
 
Accelerated filer o
 
Non-accelerated filer x
(Do not check if a smaller
reporting company)
 
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    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
 
434,888,104
 
Table of Contents

TABLE OF CONTENTS

 
 
 
 
 
 
 
 
 
 
 
 
 

i
Table of Contents

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


ii
Table of Contents

GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

2010 Form 10-K
 
SCE'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
APS
 
Arizona Public Service Company
ARO(s)
 
asset retirement obligation(s)
Bcf
 
Billion cubic feet
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
CPUC
 
California Public Utilities Commission
CRRs
 
congestion revenue rights
DOE
 
U. S. Department of Energy
ERRA
 
energy resource recovery account
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 resolves all of
SCE's federal income tax disputes and affirmative claims for tax years 1986
through 2002 and related matters with state tax authorities.
GRC
 
general rate case
IRS
 
Internal Revenue Service
ISO
 
Independent System Operator
kWh(s)
 
kilowatt-hour(s)
MD&A
 
Management's Discussion and Analysis of Financial Condition and Results
of Operations in this report
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 Technical Upgrade
MW
 
megawatts
MWh
 
megawatt-hours
NAAQS
 
national ambient air quality standards
NERC
 
North American Electric Reliability Corporation
Ninth Circuit
 
U.S. Court of Appeals for the Ninth Circuit



iii
Table of Contents

NOx
 
nitrogen oxide
NRC
 
Nuclear Regulatory Commission
NSR
 
New Source Review
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
PSD
 
Prevention of Significant Deterioration
QF(s)
 
qualifying facility(ies)
ROE
 
return on equity
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
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




iv
Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Statements of Income
Southern California Edison Company
 
 
 
 
 
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions, unaudited)
2011
 
2010
 
2011
 
2010
Operating revenue
$
3,386

 
$
3,098

 
$
8,063

 
$
7,504

Fuel
110

 
100

 
269

 
275

Purchased power
1,264

 
1,118

 
2,422

 
2,337

Operation and maintenance
819

 
803

 
2,450

 
2,272

Depreciation, decommissioning and amortization
358

 
316

 
1,058

 
945

Property and other taxes
71

 
65

 
217

 
195

Gain on sale of assets
—

 
—

 
—

 
(1
)
Total operating expenses
2,622

 
2,402

 
6,416

 
6,023

Operating income
764

 
696

 
1,647

 
1,481

Interest income
2

 
2

 
7

 
5

Other income
26

 
33

 
103

 
103

Interest expense
(116
)
 
(109
)
 
(344
)
 
(315
)
Other expenses
(10
)
 
(10
)
 
(35
)
 
(39
)
Income before income taxes
666

 
612

 
1,378

 
1,235

Income tax expense
245

 
205

 
496

 
338

Net income
421

 
407

 
882

 
897

Dividends on preferred and preference stock
15

 
13

 
44

 
39

Net income available for common stock
$
406

 
$
394

 
$
838

 
$
858


Consolidated Statements of Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
Three months ended
September 30,
 
Nine months ended
September 30,
(in millions, unaudited)
2011
 
2010
 
2011
 
2010
Net income
$
421

 
$
407

 
$
882

 
$
897

Other comprehensive income, net of tax:
 
 
 
 
 
 
 
Pension and postretirement benefits other than pensions:
 
 
 
 
 
 
 
Amortization of net loss included in net income, net of income tax expense of $1 million for the three months ended September 30, 2011, and $2 million and $1 million for the nine months ended September 30, 2011 and 2010, respectively. 
1

 
—

 
3

 
2

Comprehensive income
$
422

 
$
407

 
$
885

 
$
899





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

1
Table of Contents

Consolidated Balance Sheets
Southern California Edison Company
 
 
 
 
 
(in millions, unaudited)
September 30,
2011
 
December 31,
2010
ASSETS
 
 
 
Cash and cash equivalents
$
65

 
$
257

Receivables, less allowances of $97 and $85 for uncollectible accounts at respective dates
969

 
715

Accrued unbilled revenue
709

 
442

Inventory
340

 
332

Prepaid taxes
120

 
168

Derivative assets
68

 
87

Regulatory assets
454

 
378

Other current assets
107

 
81

Total current assets
2,832

 
2,460

Nuclear decommissioning trusts
3,393

 
3,480

Other investments
85

 
68

Total investments
3,478

 
3,548

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

 
24,778

Nonutility property, plant and equipment, less accumulated depreciation of $104 and $100 at respective dates
73

 
71

Total property, plant and equipment
26,563

 
24,849

Derivative assets
132

 
367

Regulatory assets
4,777

 
4,347

Other long-term assets
340

 
335

Total long-term assets
5,249

 
5,049

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
38,122

 
$
35,906






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

2
Table of Contents

Consolidated Balance Sheets
Southern California Edison Company
 
 
 
 
 
(in millions, except share amounts, unaudited)
September 30,
2011
 
December 31,
2010
LIABILITIES AND EQUITY
 
 
 
Short-term debt
$
550

 
$
—

Accounts payable
1,128

 
1,271

Accrued taxes
122

 
45

Accrued interest
102

 
169

Customer deposits
203

 
217

Derivative liabilities
287

 
212

Regulatory liabilities
734

 
738

Other current liabilities
511

 
663

Total current liabilities
3,637

 
3,315

Long-term debt
8,032

 
7,627

Deferred income taxes
5,483

 
4,829

Deferred investment tax credits
86

 
118

Customer advances
133

 
112

Derivative liabilities
554

 
449

Pensions and benefits
1,863

 
1,838

Asset retirement obligations
2,583

 
2,507

Regulatory liabilities
4,481

 
4,524

Other deferred credits and other long-term liabilities
1,438

 
1,380

Total deferred credits and other liabilities
16,621

 
15,757

Total liabilities
28,290

 
26,699

Commitments and contingencies (Note 9)
 
 
 
Common stock, no par value (560,000,000 shares authorized; 434,888,104 shares issued and outstanding at each date)
2,168

 
2,168

Additional paid-in capital
587

 
572

Accumulated other comprehensive loss
(22
)
 
(25
)
Retained earnings
6,054

 
5,572

Total common shareholder's equity
8,787

 
8,287

Preferred and preference stock
1,045

 
920

Total equity
9,832

 
9,207

Total liabilities and equity
$
38,122

 
$
35,906





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

3
Table of Contents

Consolidated Statements of Cash Flows
Southern California Edison Company
 
 
 
 
 
 
 
Nine months ended
September 30,
(in millions, unaudited)
2011
 
2010
Cash flows from operating activities:
 
 
 
Net income
$
882

 
$
897

Adjustments to reconcile to net cash provided by operating activities:
 
 
 
Depreciation, decommissioning and amortization
1,058

 
945

Regulatory impacts of net nuclear decommissioning trust earnings
131

 
106

Other amortization
97

 
82

Stock-based compensation
12

 
12

Deferred income taxes and investment tax credits
526

 
336

Changes in operating assets and liabilities:
 
 
 
Receivables
(253
)
 
(197
)
Inventory
(8
)
 
(5
)
Margin and collateral deposits – net of collateral received
(9
)
 
1

Prepaid taxes
48

 
33

Other current assets
(280
)
 
(279
)
Accounts payable
142

 
(3
)
Accrued taxes
77

 
140

Other current liabilities
(230
)
 
(103
)
Derivative assets and liabilities – net
433

 
1,012

Regulatory assets and liabilities – net
(363
)
 
(530
)
Other assets
(21
)
 
(26
)
Other liabilities
30

 
235

Net cash provided by operating activities
2,272

 
2,656

Cash flows from financing activities:
 
 
 
Long-term debt issued
497

 
1,135

Long-term debt issuance costs
(5
)
 
(16
)
Long-term debt repaid
(12
)
 
(256
)
Bonds purchased
(86
)
 
—

Preference stock issued – net
123

 
—

Short-term debt financing – net
550

 
—

Settlements of stock-based compensation – net
(7
)
 
(2
)
Dividends paid
(388
)
 
(239
)
Net cash provided by financing activities
672

 
622

Cash flows from investing activities:
 
 
 
Capital expenditures
(3,014
)
 
(2,659
)
Proceeds from sale of nuclear decommissioning trust investments
2,108

 
903

Purchases of nuclear decommissioning trust investments and other
(2,254
)
 
(1,036
)
Customer advances for construction and other investments
24

 
1

Effect of deconsolidation of variable interest entities
—

 
(92
)
Net cash used by investing activities
(3,136
)
 
(2,883
)
Net increase (decrease) in cash and cash equivalents
(192
)
 
395

Cash and cash equivalents, beginning of period
257

 
462

Cash and cash equivalents, end of period
$
65

 
$
857



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

4
Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1. Summary of Significant Accounting Policies
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. SCE is a wholly owned subsidiary of Edison International.
Basis of Presentation
SCE's significant accounting policies were described in Note 1 of "SCE Notes to Consolidated Financial Statements" included in the 2010 Form 10-K. SCE 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 $15 million and $243 million at September 30, 2011 and December 31, 2010, respectively. Generally, the carrying value of cash equivalents equals the fair value, as all investments have maturities of three months or less.
SCE temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. SCE reclassified $215 million and $196 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 average cost method for fuel and materials and supplies. Inventory consisted of the following:
(in millions)
September 30,
2011
 
December 31,
2010
Fuel
$
24

 
$
21

Materials and supplies, spare parts
316

 
311

Total inventory
$
340

 
$
332

New Accounting Guidance
Accounting Guidance Adopted in 2011
Fair Value Measurements and Disclosures
The Financial Accounting Standards Board ("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. SCE 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



5
Table of Contents

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. SCE will adopt this guidance effective January 1, 2012 and does not expect the adoption of this standard will have a material impact on SCE'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. SCE will adopt this guidance effective January 1, 2012. SCE 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 SCE
 
 
(in millions)
Common
Stock
 
Additional
Paid-in
Capital
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Retained
Earnings
 
Preferred
and
Preference
Stock
 
Total Equity
Balance at December 31, 2010
$
2,168

 
$
572

 
$
(25
)
 
$
5,572

 
$
920

 
$
9,207

Net income
—

 
—

 
—

 
882

 
—

 
882

Other comprehensive income
—

 
—

 
3

 
—

 
—

 
3

Dividends declared on common stock
—

 
—

 
—

 
(345
)
 
—

 
(345
)
Dividends declared on preferred and preference stock
—

 
—

 
—

 
(44
)
 
—

 
(44
)
Stock-based compensation and other
—

 
5

 
—

 
(12
)
 
—

 
(7
)
Noncash stock-based compensation and other
—

 
12

 
—

 
1

 
—

 
13

Issuance of preference stock
—

 
(2
)
 
—

 
—

 
125

 
123

Balance at September 30, 2011
$
2,168

 
$
587

 
$
(22
)
 
$
6,054

 
$
1,045

 
$
9,832

The following table provides the changes in equity for the nine months ended September 30, 2010.
 
Equity Attributable to SCE
 
 
 
 
(in millions)
Common
Stock
 
Additional
Paid-in
Capital
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Retained
Earnings
 
Preferred
and
Preference
Stock
 
Noncontrolling
Interest
 
Total
Equity
Balance at December 31, 2009
$
2,168

 
$
551

 
$
(19
)
 
$
4,746

 
$
920

 
$
349

 
$
8,715

Net income
—

 
—

 
—

 
897

 
—

 
—

 
897

Other comprehensive income
—

 
—

 
2

 
—

 
—

 
—

 
2

Deconsolidation of variable interest entities
—

 
—

 
—

 
—

 
—

 
(349
)
 
(349
)
Dividends declared on common stock
—

 
—

 
—

 
(100
)
 
—

 
—

 
(100
)
Dividends declared on preferred and preference stock
—

 
—

 
—

 
(39
)
 
—

 
—

 
(39
)
Stock-based compensation and other
—

 
3

 
—

 
(5
)
 
—

 
—

 
(2
)
Noncash stock-based compensation and other
—

 
12

 
—

 
(3
)
 
—

 
—

 
9

Balance at September 30, 2010
$
2,168

 
$
566

 
$
(17
)
 
$
5,496

 
$
920

 
$
—

 
$
9,133




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Table of Contents

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 SCE has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.
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 $447 million for the nine months ended September 30, 2011 and 2010, respectively. These amounts are recovered in customer rates.
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.
SCE 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).



7
Table of Contents

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
 
Collateral
 
Total
Assets at Fair Value
 
 
 
 
 
 
 
 
 
Money market funds1
$
15

 
$
—

 
$
—

 
$
—

 
$
15

Derivative contracts2:
 
 
 
 
 
 
 
 
 
Electricity
—

 
—

 
34

 
—

 
34

Natural gas
—

 
61

 
10

 
(4
)
 
67

CRRs
—

 
—

 
95

 
—

 
95

Tolling
—

 
—

 
4

 
—

 
4

Subtotal of derivative contracts
—

 
61

 
143

 
(4
)
 
200

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

Sub-total of nuclear decommissioning trusts
2,101

 
1,359

 
—

 
—

 
3,460

Total assets6
2,125

 
1,420

 
143

 
(4
)
 
3,684

Liabilities at Fair Value
 
 
 
 
 
 
 
 
 
Derivative contracts2:
 
 
 
 
 
 
 
 
 
Electricity
—

 
6

 
80

 
(6
)
 
80

Natural gas
—

 
240

 
12

 
(12
)
 
240

Tolling
—

 
—

 
521

 
—

 
521

Subtotal of derivative contracts
—

 
246

 
613

 
(18
)
 
841

Total liabilities
—

 
246

 
613

 
(18
)
 
841

Net assets (liabilities)
$
2,125

 
$
1,174

 
$
(470
)
 
$
14

 
$
2,843




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Table of Contents

 
As of December 31, 2010
(in millions)
Level 1
 
Level 2
 
Level 3
 
Collateral
 
Total
Assets at Fair Value
 
 
 
 
 
 
 
 
 
Money market funds1
$
243

 
$
—

 
$
—

 
$
—

 
$
243

Derivative contracts2:
 
 
 
 
 
 
 
 
 
Electricity
—

 
—

 
119

 
—

 
119

Natural gas
—

 
69

 
11

 
—

 
80

CRRs
—

 
—

 
137

 
—

 
137

Tolling
—

 
—

 
118

 
—

 
118

Subtotal of derivative contracts
—

 
69

 
385

 
—

 
454

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

Sub-total of nuclear decommissioning trusts
2,245

 
1,240

 
—

 
—

 
3,485

Total assets6
2,497

 
1,309

 
385

 
—

 
4,191

Liabilities at Fair Value
 
 
 
 
 
 
 
 
 
Derivative contracts2:
 
 
 
 
 
 
 
 
 
Electricity
—

 
1

 
24

 
—

 
25

Natural gas
—

 
285

 
11

 
(4
)
 
292

Tolling
—

 
—

 
344

 
—

 
344

Subtotal of derivative contracts
—

 
286

 
379

 
(4
)
 
661

Total liabilities
—

 
286

 
379

 
(4
)
 
661

Net assets
$
2,497

 
$
1,023

 
$
6

 
$
4

 
$
3,530

1 
Money market funds are included in cash and cash equivalents on SCE's consolidated balance sheets.
2 
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.
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.



9
Table of Contents

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 of derivative contracts, net assets (liabilities) at beginning of period
$
(359
)
 
$
(869
)
 
$
6

 
$
(111
)
Total realized/unrealized losses, net:
 
 
 
 
 
 
 
Included in regulatory assets and liabilities1
(128
)
 
(142
)
 
(510
)
 
(924
)
Purchases
19

 
9

 
35

 
33

Settlements
(2
)
 
3

 
(1
)
 
3

Transfers into Level 3
—

 
—

 
—

 
—

Transfers out of Level 3
—

 
(16
)
 
—

 
(16
)
Fair value of derivative contracts, net liabilities at end of period
$
(470
)
 
$
(1,015
)
 
$
(470
)
 
$
(1,015
)
Change during the period in unrealized losses related to assets and liabilities held at the end of period
$
(135
)
 
$
(160
)
 
$
(502
)
 
$
(883
)
1 
Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.
SCE 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 in which observable inputs are not available. In circumstances where SCE 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, SCE continues to assess valuation methodologies used to determine fair value.
For derivative contracts that trade infrequently (CRRs), changes in fair value are based on models forecasting the value of those



10
Table of Contents

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. 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
$
8,032

 
$
9,826

 
$
7,627

 
$
8,285

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.
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.



11
Table of Contents

Note 6. Derivative Instruments and Hedging Activities
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 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 Liabilities
 
 
(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




12
Table of Contents

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.
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.



13
Table of Contents

Margin and Collateral Deposits
Margin and collateral deposits include cash deposited with 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. SCE nets counterparty receivables and payables where balances exist under master netting agreements. SCE 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 counterparties:
(in millions)
September 30,
2011
 
December 31,
2010
Collateral provided to counterparties:
 
 
 
Offset against derivative liabilities
$
14

 
$
4

Reflected in other current assets
9

 
5

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.
 
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 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 were 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.
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.



14
Table of Contents

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,
$
329

 
$
482

Tax positions taken during the current year
 
 
 
Increases
58

 
65

Tax positions taken during a prior year
 
 
 
Increases
44

 
185

Decreases
(34
)
 
(14
)
Decreases for settlements during the period
—

 
(68
)
Balance at September 30,
$
397

 
$
650

As of September 30, 2011 and December 31, 2010 $266 million and $225 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. This included 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 adjustment 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 SCE's income tax liabilities was $69 million and $61 million as of September 30, 2011 and December 31, 2010, respectively.
The net after-tax interest and penalties recognized in income tax expense was $2 million and $5 million for the three- and nine-month periods ended September 30, 2011, respectively, compared to a benefit of $27 million and $48 million for the same periods in 2010.



15
Table of Contents

Note 8. Compensation and Benefit Plans
Pension Plans and Postretirement Benefits Other Than Pensions
Pension Plans
During the nine months ended September 30, 2011, SCE made contributions of $90 million and during the remainder of 2011, expects to make $24 million of additional contributions. SCE's 2011 annual contributions made to most of its 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
$
38

 
$
29

 
$
114

 
$
87

Interest cost
47

 
49

 
141

 
147

Expected return on plan assets
(56
)
 
(49
)
 
(168
)
 
(147
)
Amortization of prior service cost
2

 
2

 
6

 
6

Amortization of net loss
4

 
6

 
12

 
18

Expense under accounting standards
35

 
37

 
105

 
111

Regulatory adjustment – deferred
(6
)
 
(14
)
 
(18
)
 
(42
)
Total expense recognized
$
29

 
$
23

 
$
87

 
$
69

Postretirement Benefits Other Than Pensions
During the nine months ended September 30, 2011, SCE made contributions of $17 million and during the remainder of 2011, expects to make $37 million of additional contributions. SCE's annual contributions 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
$
10

 
$
7

 
$
30

 
$
21

Interest cost
31

 
30

 
93

 
90

Expected return on plan assets
(27
)
 
(25
)
 
(81
)
 
(75
)
Amortization of prior service cost (credit)
(9
)
 
(9
)
 
(27
)
 
(27
)
Amortization of net loss
9

 
8

 
27

 
24

Total expense
$
14

 
$
11

 
$
42

 
$
33




16
Table of Contents

Stock-Based Compensation
During 2011, Edison International granted stock-based compensation awards to SCE employees, 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 granted to SCE employees:
 
 
 
Weighted-Average
 
 
 
Stock Options
 
Exercise
Price
 
Remaining
Contractual
Term
(Years)
 
Aggregate
Intrinsic
Value
(in millions)
Outstanding at December 31, 2010
10,064,736

 
$
32.86

 
 

 
 

Granted
1,850,749

 
37.98

 
 

 
 

Expired
(50,811
)
 
48.90

 
 

 
 

Forfeited
(288,776
)
 
33.54

 
 

 
 

Exercised
(677,595
)
 
24.32

 
 

 
 

Affiliate transfers – net
110,287

 
31.98

 
 

 
 

Outstanding at September 30, 2011
11,008,590

 
34.15

 
6.11

 
 

Vested and expected to vest at September 30, 2011
10,752,504

 
34.15

 
6.06

 
$
69

Exercisable at September 30, 2011
6,300,938

 
34.42

 
4.51

 
46

At September 30, 2011, there was $12 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 granted to SCE employees:
 
Equity Awards
 
Liability Awards
 
 
 
Weighted-Average
Grant Date
Fair Value
 
 
 
Weighted-Average
Fair Value
 
Shares
 
 
Shares
 
Nonvested at December 31, 2010
219,904

 
$
32.15

 
219,904

 
$
37.68

Granted
83,235

 
29.66

 
83,235

 
 

Forfeited1
(54,654
)
 
49.94

 
(54,654
)
 
 

Affiliate transfers – net
3,496

 
26.90

 
3,496

 
 

Nonvested at September 30, 2011
251,981

 
27.96

 
251,981

 
23.35

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 $3 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.



17
Table of Contents

Restricted Stock Units
The following is a summary of the status of Edison International nonvested restricted stock units granted to SCE employees:
 
Restricted
Stock Units
 
Weighted-Average
Grant Date
Fair Value
Nonvested at December 31, 2010
385,877

 
$
32.90

Granted
137,445

 
37.98

Forfeited
(23,243
)
 
31.83

Paid Out
(96,802
)
 
48.20

Affiliate transfers – net
6,747

 
30.56

Nonvested at September 30, 2011
410,024

 
32.06

At September 30, 2011, there was $5 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $1 million in 2011, $3 million in 2012 and $1 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
$
4

 
$
6

 
$
13

 
$
16

Income tax benefits related to stock compensation expense
1

 
2

 
5

 
6

Excess tax benefits2
2

 
1

 
5

 
3

Stock options
 
 
 
 
 
 
 
Cash used to purchase shares to settle options
4

 
5

 
26

 
12

Cash from participants to exercise stock options
3

 
3

 
17

 
8

Value of options exercised
1

 
2

 
9

 
4

Restricted stock units
 
 
 
 
 
 
 
Value of shares settled
1

 
—

 
5

 
—

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
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.



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Indemnities
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 Indemnities
SCE 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. SCE's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties. SCE 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, SCE is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. SCE believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.
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 best available control technology ("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



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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
SCE 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. SCE 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, SCE 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, SCE's recorded estimated minimum liability to remediate its 24 identified material sites (sites in which the upper end of the range of costs is at least $1 million) was $51 million, of which $15 million was 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 SCE'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. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs at these identified material sites and immaterial sites could exceed its recorded liability by up to $195 million and $7 million, respectively. The upper limit of this range of costs was estimated using assumptions least favorable to SCE 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.
SCE'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 SCE 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, SCE 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



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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.
Note 10. Regulatory and Environmental Developments
Environmental Developments
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. SCE is evaluating the proposed standards and believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable 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 SCE is unable at this time to assess potential costs of compliance, which could be significant for San Onofre.
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



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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 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. 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 remains a defendant.
Note 11. Supplemental Cash Flows Information
SCE'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
$
369

 
$
339

Tax refunds – net
(126
)
 
(309
)
Noncash investing and financing activities:
 
 
 
Accrued capital expenditures
$
362

 
$
360

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

 
303

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

 
$
306

Liabilities and noncontrolling interests
—

 
(398
)
Dividends declared but not paid:
 
 
 
Preferred and preference stock
$
12

 
$
9

Note 12. Preferred and Preference Stock
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 13. 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
505

 
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
4,777

 
4,347

Total Regulatory Assets
$
5,231

 
$
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 14. 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.



24
Note 15. 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 allowance for 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 other income
$
26

 
$
33

 
$
103

 
$
103

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

 
$
7

 
$
21

 
$
21

Other
4

 
3

 
14

 
18

Total other expenses
$
10

 
$
10

 
$
35

 
$
39




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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 SCE's current expectations and projections about future events based on SCE'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 SCE 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 SCE, include, but are not limited to:
•
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;
•
environmental laws and regulations, both at the 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;
•
cost of capital and the ability to borrow funds and access to capital markets on reasonable terms;
•
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 natural gas and nuclear fuel, and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;
•
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;


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•
ability to provide sufficient collateral in support of hedging activities and power and fuel purchased;
•
weather conditions and natural disasters;
•
risks inherent in transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, construction, permitting, and governmental approvals; and
•
risks that competing transmission systems will be built by merchant transmission providers in SCE's territory.
Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in SCE'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 SCE's business. Forward-looking statements speak only as of the date they are made and SCE is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by SCE 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 SCE 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 SCE's MD&A for the calendar year 2010 (the "year-ended 2010 MD&A"), which was included in the 2010 Form 10-K.
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 available for common stock
$
406

 
$
394

 
$
12

 
$
838

 
$
858

 
$
(20
)
Less: Non-Core Earnings (Loss)
 
 
 
 
 
 
 
 
 
 
 
Global settlement
—

 
42

 
(42
)
 
—

 
95

 
(95
)
Tax impact of health care legislation
—

 
—

 
—

 
—

 
(39
)
 
39

Core Earnings
$
406

 
$
352

 
$
54

 
$
838

 
$
802

 
$
36

SCE's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings for financial planning and for analysis of performance. Core earnings are also used when communicating with analysts and investors regarding SCE's earnings results to facilitate comparisons of the performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to SCE less income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: settlement of certain tax, regulatory or legal matters 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.
Non-core items included:
•
An earnings benefit of $95 million recorded in 2010 relating to the California impact of the federal Global Settlement, including $53 million in the second quarter resulting from acceptance by the Franchise Tax 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 from the Franchise Tax Board.




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•
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.
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 this 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 refueling 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 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.



28
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.
Environmental Developments
For a discussion of environmental regulation developments regarding Greenhouse Gas Regulation, Greenhouse Gas Litigation Developments and Once-Through Cooling Issues, see "SCE Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments."
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-



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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 “Management Overview-Highlights of Operating Results.”
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



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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 EdisonSmartConnectTM project.
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 “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:



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•
$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.
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 EdisonSmartConnectTM 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.



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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 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 "SCE 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



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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 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%.



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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.
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 revenue. 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:



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•
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.
Contractual Obligations and Contingencies
Contractual Obligations
SCE has power purchase commitments and firm transmission commitments which are discussed in "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Third-Party Power Purchase Agreements."
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 "SCE 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 "SCE 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 "SCE Notes to Consolidated Financial Statements—Note 6. Derivative and Hedging Activities" and "Note 4. Fair Value Measurements" and see "Market Risk Exposures—Commodity Price Risk" in the year-ended 2010 MD&A.



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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 "SCE 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.
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.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
For a discussion of SCE'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 "SCE Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."



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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to this item is included in the MD&A under the heading "Market Risk Exposures" and is incorporated herein by reference.
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
SCE's management, under the supervision and with the participation of the company's President and Chief Financial Officer, has evaluated the effectiveness of SCE'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 President and Chief Financial Officer have concluded that, as of the end of the period, SCE's disclosure controls and procedures are effective.
Internal Control Over Financial Reporting

There were no changes in SCE’s internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-1(f) under the Exchange Act) during the period to which this report relates that have materially affected, or are reasonably likely to materially affect, SCE’s internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For a discussion of SCE's legal proceedings, refer to "SCE 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 SCE 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 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."



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ITEM 5. OTHER INFORMATION

On October 27, 2011, the SCE Board of Directors amended the emergency provisions of the SCE 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 SCE 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 Southern California Edison Company, as amended October 27, 2011
 
 
 
31.1

Certification of the President 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 SCE 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

 
 
 
*
Furnished, not filed, pursuant to Rule 406T of SEC Regulation S-T.



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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.
SOUTHERN CALIFORNIA EDISON COMPANY
(Registrant)
By
/s/ Chris C. Dominski
 
Chris C. Dominski
Vice President and Controller
(Duly Authorized Officer and
Principal Accounting Officer)

Date: November 2, 2011




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