10-K 1 sce201110k.htm FORM 10-K SCE 2011 10K
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________
FORM 10-K
________________________
(Mark One)
R
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2011
o
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)
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
 
Name of each exchange
on which registered
 
 
Cumulative Preferred Stock
 
NYSE Amex
 
 
 
 
 
 
 
4.08%Series    4.32%Series
4.24%Series    4.78%Series
 
 
 
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ
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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ
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 "accelerated filer," "large accelerated filer," and "smaller reporting company" in Rule 12b-12 of the Exchange Act. (Check One):
Large Accelerated Filer o
Accelerated Filer o
Non-accelerated Filer þ
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 þ
As of February 27, 2012, there were 434,888,104 shares of Common Stock outstanding, all of which are held by the registrant's parent holding company. The aggregate market value of registrant's voting and non-voting common equity held by non-affiliates was zero.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents listed below have been incorporated by reference into the parts of this report so indicated.
(1) Designated portions of the Proxy Statement relating to registrant's 2012 Annual Meeting of Shareholders                  Part III
 
 
 
 
 
 



TABLE OF CONTENTS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


i


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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iii


GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
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
Big 4
 
Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
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
NOx
 
nitrogen oxide
NRC
 
Nuclear Regulatory Commission


iv


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
SCAQMD
 
South Coast Air Quality Management District
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
SRP
 
Salt River Project Agricultural Improvement and Power District
US EPA
 
U.S. Environmental Protection Agency
VIE(s)
 
variable interest entity(ies)



v


FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K 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;
the cost and availability of electricity including the ability to procure sufficient resources to meet expected customer needs in the event of significant counterparty defaults under power-purchase agreements;
changes in the fair value of investments and other assets;
changes in interest rates and rates of inflation, including those rates which may be adjusted by public utility regulators;
governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by Independent System Operators and Regional Transmission Organizations;
availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;
cost and availability of labor, equipment and materials;
ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance;
ability to recover uninsured losses in connection with wildfire-related liability;
effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;
cost and availability of coal, natural gas, fuel oil, and nuclear fuel, and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;
cost and availability of emission credits or allowances for emission credits;
transmission congestion in and to each market area and the resulting differences in prices between delivery points;
ability to provide sufficient collateral in support of hedging activities and power and fuel purchased;


1


weather conditions and natural disasters;
risks inherent in the development of generation projects and transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable the acceptance of power delivery), and governmental approvals; and
risks that competing transmission systems will be built by merchant transmission providers in SCE's service area.
See "Risk Factors" in Part I, Item 1A of this report for additional information on risks and uncertainties that could cause results to differ from those currently expected or that otherwise could impact SCE or its subsidiaries.
Additional information about risks and uncertainties, including more detail about the factors described in this report, is contained throughout this report. Readers are urged to read this entire report, including the information incorporated by reference, 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.



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PART I
ITEM 1.    BUSINESS
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. The SCE service territory contains a population of nearly 14 million people. In 2011, SCE's total operating revenue was derived as follows: 41.6% commercial customers, 40.2% residential customers, 5.7% industrial customers, 0.7% resale sales, 5.5% public authorities, and 6.3% agricultural and other customers. SCE had 18,069 full-time employees at December 31, 2011. SCE's operating revenue was approximately $10.6 billion in 2011.
Sources of energy to serve SCE's customers during 2011 were approximately: 36% purchased power; 21% CDWR; and 43% SCE-owned generation.
SCE separately files reports pursuant to Section 13(a) or 15(d) of the Securities Exchange Act. SCE also files a joint Proxy Statement with its parent, Edison International. Such reports and Proxy Statement are available at www.edisoninvestor.com or on the SEC's website at www.sec.gov. The information contained on, or connected to, the Edison investor website is not incorporated by reference into this report.
Regulation
CPUC
SCE's retail operations are subject to regulation by the CPUC. The CPUC has the authority to regulate, among other things, retail rates, energy purchases on behalf of retail customers, rate of return, rates of depreciation, issuance of securities, disposition of utility assets and facilities, oversight of nuclear decommissioning funding and costs, and aspects of the transmission system planning, site identification and construction.
FERC
SCE's wholesale operations (including sales of electricity into the wholesale markets) are subject to regulation by the FERC. The FERC has the authority to regulate wholesale rates as well as other matters, including unbundled transmission service pricing, accounting practices, and licensing of hydroelectric projects. The FERC also has jurisdiction over a portion of the retail rates and associated rate design.
NERC
The North American Electric Reliability Corporation ("NERC") establishes and enforces reliability standards and critical infrastructure protection standards to protect the bulk power system against potential disruptions from cyber and physical security breaches. The critical infrastructure protection standards focus on controlling access to critical physical and cyber security assets. Compliance with these standards is mandatory. The maximum penalty that may be levied for violating a NERC reliability or critical infrastructure protection standard is $1 million per violation, per day.
SCE has a formal cyber security program that is staffed and has a dedicated budget. The program covers SCE's information technology systems as well as the electric grid where SCE has control of it. Program staff is engaged with industry groups as well as public-private initiatives to reduce risk and to strengthen the security and reliability of SCE's systems and infrastructure. The program is also engaged in the protection of SCE's customer information.
Transmission and Substation Facilities Regulation
The construction, planning and project site identification of SCE's transmission lines and substation facilities require the approval of many governmental agencies and compliance with various laws. These agencies include utility regulatory commissions such as the CPUC and other state regulatory agencies depending on the project location; the CAISO, and other environmental, land management and resource agencies such as the Bureau of Land Management, the U.S. Forest Service, and the California Department of Fish and Game; and regional water quality control boards. In addition, to the extent that SCE transmission line projects pass through lands owned or controlled by Native American tribes, consent and approval from the affected tribes and the Bureau of Indian Affairs are also necessary for the project to proceed.
CEC
The construction, planning, and project site identification of SCE's power plants of 50 MW or greater within California are subject to the jurisdiction of the CEC. The CEC is also responsible for forecasting future energy needs. These forecasts are used by the CPUC in determining the adequacy of SCE's electricity procurement plans.


3


Nuclear Power Plant Regulation
SCE is subject to the jurisdiction of the NRC with respect to the safety of its San Onofre and Palo Verde Nuclear Generating Stations. The NRC regulates commercial nuclear power plants through licensing, oversight and inspection, performance assessment, and enforcement of its requirements.
In light of the 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 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. In October 2011, the NRC identified seven of the near-term actions recommended by the NRC staff as having the greatest potential for safety improvement. The NRC staff was directed to strive to implement these actions by 2016. Implementation of these actions will require further interactions between the NRC staff and the nuclear industry. These actions may impact future operations and capital requirements at U.S. nuclear facilities at the time of their implementation, including the operations and capital requirements of SCE's nuclear facilities.
Operating License Renewal
In April 2011, the NRC extended the operating license for Palo Verde Operating Units 1, 2 and 3 for an additional 20 years, to 2045, 2046 and 2047, respectively. San Onofre's current operating licenses for Units 2 and 3 will expire in 2022. The NRC's review of a license renewal application typically takes three to five years. Prior to filing a license renewal application at the NRC, SCE would make an application to the CPUC to demonstrate the cost effectiveness of continuing operations at San Onofre and to seek authority to recover the cost of seeking a license renewal at the NRC and pursuing approvals from other state and federal agencies, such as the Department of the Navy and the California Coastal Commission. SCE will consider a decision to file an application for cost recovery at the CPUC in 2012. If SCE were to choose not to pursue license renewal or if SCE' efforts to obtain license renewal were not successful, SCE will need to determine what generation and transmission alternatives would need to be made available to replace the capacity, energy, and grid reliability benefits that SCE's customers now receive from San Onofre by the time San Onofre ceases generating electricity. Should SCE decide to pursue a license extension for San Onofre, SCE will likely need to simultaneously consider generation and transmission alternatives given the long lead times for the NRC to approve a license extension and to site, permit and construct new generation and transmission facilities. The costs of these alternatives could be substantial.
Overview of Ratemaking Process
CPUC
Revenue authorized by the CPUC through triennial GRC proceedings is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation and distribution assets (also referred to as “rate base”). The CPUC sets an annual revenue requirement for the base year which is made up of the operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure (discussed below). The return is established by multiplying an authorized rate of return, determined in separate cost of capital proceedings, by SCE's generation and distribution rate base. In the GRC proceedings, the CPUC also generally approves the level of capital spending on a forecast basis. Following the base year, the revenue requirements for the remaining two years are set by a methodology established in the GRC proceeding, which generally, among other items, includes annual allowances for escalation in operation and maintenance costs, additional changes in capital-related investments and the recovery for expected nuclear refueling outages.
SCE's authorized revenue requirements were $4.83 billion, $5.04 billion and $5.25 billion for the years ended December 31, 2009, 2010 and 2011, respectively. SCE filed its 2012 GRC application with the CPUC on November 23, 2010, to be effective on January 1, 2012. For further discussion of the 2012 GRC, see “Management Overview—2012 CPUC General Rate Case” in the MD&A.
CPUC rates decouple authorized revenue from the volume of electricity sales, so that SCE earns revenue equal to amounts authorized. Differences between amounts collected and authorized levels are either collected from or refunded to customers, and, therefore, such differences do not impact operating revenue. Accordingly, SCE is neither benefited nor burdened by the volumetric risk related to retail electricity sales.
The CPUC regulates SCE's capital structure and authorized rate of return. SCE's current authorized capital structure is 48%


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common equity, 43% long-term debt and 9% preferred equity. SCE's current authorized cost of capital consists of: cost of long-term debt of 6.22%, cost of preferred equity of 6.01% and return on common equity of 11.5%. SCE is scheduled to file a new cost of capital application with the CPUC in April 2012 that will be effective beginning in 2013.
In addition, to the ratemaking process described above, the CPUC has also authorized ratemaking mechanisms outside of the GRC process for significant capital projects, as needed.
Balancing accounts (also referred to as cost-recovery mechanisms) are typically used to track and recover SCE's costs of fuel, purchased-power, and certain operation and maintenance expenses, including certain demand-side management program costs. SCE earns no return on these activities and although differences between forecasted and actual costs do not impact earnings, such differences do impact cash flows and can change rapidly.
SCE's balancing account for fuel and power procurement-related costs is established under the Energy Resource Recovery Account ("ERRA") Mechanism. SCE sets rates based on an annual forecast of the costs that it expects to incur during the following year. In addition, the CPUC has established a "trigger" mechanism for the ERRA balancing account that allows for a rate adjustment if the balancing account over-collection or under-collection exceeds 5% of SCE's prior year's revenue that is classified as generation for retail rates. For 2012, the trigger amount is approximately $237 million.
The majority of costs eligible for recovery through cost-recovery rates are approved upfront by the CPUC though a procurement plan with predefined standards, or through CPUC preapproval, and thus could negatively impact earnings and cash flows if SCE's costs were found to be unreasonable or out of compliance and disallowed.
FERC
Revenue authorized by the FERC is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in transmission assets. In August 2011, the FERC accepted 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. For further discussion of SCE's FERC formula rates, see “Management Overview—FERC Formula Rates” in the MD&A.
Retail Rates
To develop retail rates, the authorized revenue requirements are allocated among all customer classes (residential, commercial, industrial and agricultural) on a functional basis (i.e., generation, distribution, transmission, etc.). Specific rate components are designed to recover the authorized revenue allocated to each customer class.
Currently, SCE has a five tier residential rate structure. Each tier represents a certain electricity usage level and within each increasing usage level, the electricity is priced at higher rates per kilowatt hour. The first tier is a baseline tier and has the lowest rate per kilowatt hour. "Baseline" refers to a specific amount of energy allocated for residential customers that is charged at a lower price than energy used in excess of that amount. Baseline quantities are determined by SCE for approval by the CPUC using average residential electricity consumption for nine geographical regions in southern and central California. Seasonal variations in usage are also accounted for in determining baseline allowances.
The intent of the baseline and the tiered structure is to provide a portion of reasonable energy needs (baseline usage) of residential customers at the lowest rate, and to encourage conservation of energy by increasing the rate charges as energy usage increases. Statutory restrictions on tier one and two rates have shifted the burden of residential rate increases to the higher tier/usage customers. As part of the second phase of SCE's 2012 GRC, SCE requested certain rate design modifications that are intended to provide a more equitable, cost-based rate design.
CDWR-Related Rates
As a result of the California energy crisis, in 2001 the CDWR entered into contracts to purchase power for sale at cost directly to SCE's retail customers and issued bonds to finance those power purchases. The CDWR's total statewide power charge and bond charge revenue requirements were allocated by the CPUC among the customers of the investor-owned utilities (SCE, PG&E and SDG&E). SCE billed and collected from its customers the costs of power purchased and sold by the CDWR. SCE will continue to bill and collect CDWR bond-related charges and direct access exit fees until 2022. The CDWR-related charges and a portion of direct access exit fees that are remitted directly to the CDWR are not recognized as operating revenue; but did affect customer rates. All CDWR power contracts that were allocated to SCE expired by the end of 2011. See "Results of Operations—Supplemental Operating Revenue Information" in the MD&A for further discussion of the impact of CDWR charges on customer rates.


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Purchased Power and Fuel Supply
SCE obtains the power needed to serve its customers from its generating facilities and from sales by qualifying facilities, independent power producers, renewable power producers, the CAISO, and other utilities.
Natural Gas Supply
SCE requires natural gas to meet contractual obligations for power tolling agreements (power contracts in which SCE has agreed to provide or pay for the natural gas burned to generate electricity). SCE also requires natural gas to fuel its Mountainview and peaker plants, which are generation units that are designed to operate in response to changes in demand for power. The physical natural gas purchased by SCE is subject to competitive bidding.
Nuclear Fuel Supply
For San Onofre Units 2 and 3, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below:
Uranium concentrates
2020
Conversion
2020
Enrichment
2020
Fabrication
2015
For Palo Verde, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below:
Uranium concentrates
2017
Conversion
2018
Enrichment
2020
Fabrication
2016
Coal Supply
On January 1, 2010, SCE and the other Four Corners participants entered into a Four Corners Coal Supply Agreement with the BHP Navajo Coal Company, under which coal will be supplied to Four Corners Units 4 and 5 until July 6, 2016. The co-owners of Four Corners (excluding SCE) are currently negotiating a potential new Coal Supply Agreement with BHP Navajo Coal Company for the period after July 6, 2016. In November 2010, SCE entered into an agreement to sell its interest in Four Corners subject to certain conditions and regulatory approvals. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment," for more information on the sale of SCE's interest in Four Corners.
CAISO Wholesale Energy Market
In California and other states, wholesale energy markets exist through which competing electricity generators offer their electricity output to electricity retailers. Each state's wholesale electricity market is generally operated by its state ISO or a regional RTO. California's wholesale electricity market is operated by the CAISO. The CAISO schedules power in hourly increments with hourly prices through a real-time and day-ahead market that combines energy, ancillary services, unit commitment and congestion management. SCE participates in the day-ahead and real-time markets for the sale of its generation and purchases of its load requirements.
The CAISO uses a nodal locational pricing model, which sets wholesale electricity prices at system points ("nodes") that reflect local generation and delivery costs. Generally, SCE schedules its electricity generation to serve its load but when it has excess generation or the market price of power is more economic than its own generation, SCE may sell power from utility-owned generation assets and existing power procurement contracts into, or buy generation and/or ancillary services to meet its load requirements from, the day-ahead market. SCE will offer to buy its generation at nodes near the source of the generation, but will take delivery at nodes throughout SCE's service territory. Congestion may occur when available energy cannot be delivered due to transmission constraints, which results in transmission congestion charges and differences in prices at various nodes. The CAISO also offers congestion revenue rights or CRRs, a commodity that entitles the holder to receive (or pay) the value of transmission congestion between specific nodes, acting as an economic hedge against transmission congestion charges.


6


Competition
Because SCE is an electric utility company operating within a defined service territory pursuant to authority from the CPUC, SCE faces retail competition only to the extent that federal and California laws permit other entities to provide electricity and related services to customers within SCE's service territory. While California law provides only limited opportunities for customers to choose to purchase power directly from an energy service provider other than SCE, a California statute was adopted in 2009 that permits a limited, phased-in expansion of customer choice (direct access) for nonresidential customers. SCE also faces some competition from cities and municipal districts that create municipal utilities or community choice aggregators. Competition between SCE and other electricity providers is conducted mainly on the basis of price; customers seek the lowest cost power available. The effect of this competition on SCE generally is to reduce the number of customers purchasing power from SCE, but those departing customers typically continue to utilize and pay for SCE's transmission and distribution services.
Technological developments, such as on-site power generation (self generation), pose additional competitive challenges for traditional utilities. See "Item 1A. Risk Factors—Regulatory Risks."
In the area of transmission infrastructure, SCE may experience increased competition from merchant transmission providers. The FERC has made changes to its transmission planning requirements with the goal of opening transmission development to competition from independent developers. 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 2012 – 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.
Properties
SCE supplies electricity to its customers through extensive transmission and distribution networks. Its transmission facilities, which are located primarily in California but also in Nevada and Arizona, deliver power from generating sources to the distribution network and consist of lines ranging from 33 kV to 500 kV and substations. SCE's distribution system, which takes power from substations to customers, includes over 59,000 circuit miles of overhead lines, 44,000 circuit miles of underground lines and over 700 distribution substations, all of which are located in California.
SCE owns the generating facilities listed in the following table.
Generating Facility
 
Location
(in CA, unless
otherwise noted)
 
Fuel Type
 
Operator
 
SCE's
Ownership
Interest (%)
 
Net Physical
Capacity
(in MW)
 
SCE's Capacity
pro rata share
(in MW)
San Onofre Nuclear
Generating Station
 
South of San Clemente
 
Nuclear
 
SCE
 
78.21
%
 
2,150

 
1,760

Hydroelectric Plants (36)
 
Various
 
Hydroelectric
 
SCE
 
100
%
 
1,176

 
1,176

Pebbly Beach Generating Station
 
Catalina Island
 
Diesel
 
SCE
 
100
%
 
9

 
9

Mountainview
 
Redlands
 
Natural Gas
 
SCE
 
100
%
 
1,050

 
1,050

Peaker Plants (4)
 
Various
 
Gas fueled Combustion Turbine
 
SCE
 
100
%
 
196

 
196

Palo Verde Nuclear
Generating Station
 
Phoenix, AZ
 
Nuclear
 
APS
 
15.8
%
 
3,739

 
591

Four Corners Units 4 and 5
 
Farmington, NM
 
Coal-fired
 
APS
 
48
%
1 

1,540

 
739

Solar PV Plants (23)
 
Various
 
Photovoltaic
 
SCE
 
100
%
 
53

 
53

Total
 
 
 
 
 
 
 
 

 
9,913

 
5,574

1 
In November 2010, SCE entered into an agreement to sell its interest in Four Corners to APS for approximately $294 million. The sale is contingent upon the satisfaction of several conditions and the obtaining of multiple regulatory approvals. Currently SCE estimates that the sale will close in the second half of 2012. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for more information.


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San Onofre, Four Corners, certain of SCE's substations, and portions of its transmission, distribution and communication systems are located on lands owned by the United States or others under licenses, permits, easements or leases, or on public streets or highways pursuant to franchises. Certain of the documents evidencing such rights obligate SCE, under specified circumstances and at its expense, to relocate such transmission, distribution, and communication facilities located on lands owned or controlled by federal, state, or local governments.
Twenty-eight of SCE's 36 hydroelectric plants and related reservoirs are located in whole or in part on U.S.-owned lands pursuant to 30- to 50-year FERC licenses that expire at various times between 2012 and 2046. Such licenses impose numerous restrictions and obligations on SCE, including the right of the United States to acquire projects upon payment of specified compensation. When existing licenses expire, the FERC has the authority to issue new licenses to third parties that have filed competing license applications, but only if their license application is superior to SCE's and then only upon payment of specified compensation to SCE. New licenses issued to SCE are expected to contain more restrictions and obligations than the expired licenses because laws enacted since the existing licenses were issued require the FERC to give environmental objectives greater consideration in the licensing process.
Substantially all of SCE's properties are subject to the lien of a trust indenture securing first and refunding mortgage bonds. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."
Insurance
SCE participates in the property and casualty insurance program of its parent, Edison International. This program includes excess liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations. For further information on wildfire insurance issues, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies." SCE also has separate insurance programs for nuclear property and liability, workers compensations and solar rooftop construction liability.
Seasonality
Due to warm weather during the summer months and SCE's rate design, operating revenue during the third quarter of each year is generally higher than the other quarters.
Environmental Matters
Legislative and regulatory activities by federal, state, and local authorities in the United States relating to energy and the environment impose numerous restrictions on the operation of SCE's existing facilities and affect the timing, cost, location, design, construction and operation of new facilities, as well as the cost of mitigating the environmental impacts of past operations. The environmental regulations and other developments discussed below have the largest impact on fossil-fuel fired power plants, and therefore the discussion in this section focuses mainly on regulations applicable to the states of California and New Mexico, where such facilities are located.
SCE continues to monitor legislative and regulatory developments and to evaluate possible strategies for compliance with environmental regulations. Additional information about environmental matters affecting SCE, including projected environmental capital expenditures, is included in the MD&A under the heading "Liquidity and Capital Resources—Capital Investment Plan" and in "Item 8. SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Environmental Remediation" and "—Note 10. Environmental Developments."
Air Quality
The CAA, which regulates air pollutants from mobile and stationary sources, has a significant impact on the operation of fossil fuel plants, especially coal-fired plants. The CAA requires the US EPA to establish concentration levels in the ambient air for six criteria pollutants to protect public health and welfare. These concentration levels are known as National Ambient Air Quality Standards ("NAAQS"). The six criteria pollutants are carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO2.
Federal environmental regulations of these criteria pollutants require states to adopt state implementation plans, known as SIPs, for certain pollutants, which detail how the state will attain the standards that are mandated by the relevant law or regulation. The SIPs must be equal to or more stringent than the federal requirements and must be submitted to the US EPA for approval. Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (non-attainment areas), and must develop a SIP both to bring non-attainment areas into compliance with the NAAQS and to maintain good air quality in attainment areas. If the attainment status of areas changes, states may be required to develop new SIPs that address the changes. Much of southern California is in a non-attainment area for several criteria pollutants.


8


Ozone
National Ambient Air Quality Standards
In January 2010, the US EPA proposed a revision to the primary and secondary NAAQS for 8-hour ozone that it had finalized in 2008. The 8-hour ozone standard established in 2008 was 0.075 parts per million. In January 2010, the US EPA proposed establishing a primary 8-hour ozone NAAQS between 0.060 and 0.070 parts per million and a distinct secondary standard to protect sensitive vegetation and ecosystems. In September 2011, President Obama announced that the proposed revision was being withdrawn. The ozone NAAQS established in 2008 remains in place, but the implementation process must be completed before the 0.075 parts-per-million standard can be enforced. The US EPA has indicated that it intends to issue initial area designations of attainment, nonattainment, and unclassifiable areas across the nation in 2012. States will then be required to develop and submit state implementation plans outlining how compliance with the 2008 NAAQS will be achieved. New primary and secondary ozone standards are expected in 2014.
Regional Haze
The regional haze rules under the CAA are designed to prevent impairment of visibility in certain federally designated areas. The goal of the rules is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions by 2064. Sources such as power plants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required to install best available retrofit technology ("BART") or implement other control strategies to meet regional haze control requirements.
In relation to Four Corners, the US EPA issued its proposed FIP in October 2010. The proposed FIP would require the installation of SCR pollution control equipment within designated time periods. In November 2010, SCE and APS entered into an agreement for the sale of SCE's interest in Four Corners Units 4 and 5 to APS, subject to regulatory approvals and other conditions. Due to the investment constraints of SB 1368, the California law on GHG emission performance standards discussed below in "—Greenhouse Gas Regulation—Regional Initiatives and State Legislation," SCE does not expect to be a Four Corners participant after the 2016 expiration of the current participant agreements and does not expect to participate in any investment in Four Corners SCRs. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment," for more information on the sale of SCE's interest in Four Corners.
New Source Review Requirements
The NSR regulations impose certain requirements on facilities, such as electric generating stations, if modifications are made to air emissions sources at the facility. Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address NSR compliance issues at the nation's coal-fired power plants.
In April 2009, APS, as operating agent of Four Corners, received a US EPA request pursuant to Section 114 of the CAA for information about Four Corners, including information about Four Corners' capital projects from 1990 to the present. SCE understands that in other cases the US EPA has utilized responses to similar Section 114 letters to examine whether power plants have triggered NSR requirements under the CAA. In October 2011, four environmental organizations filed a lawsuit against the Four Corners owners alleging NSR violations. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment," for information on the sale of SCE's interest in Four Corners.
Water Quality
Clean Water Act
Regulations under the federal Clean Water Act govern critical parameters at generating facilities, such as the temperature of effluent discharges and the location, design, and construction of cooling water intake structures at generating facilities. In March 2011, the US EPA proposed standards under the federal Clean Water Act that 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.
California—Prohibition on the Use of Ocean-Based Once-Through Cooling
California has a US EPA-approved program to issue individual or group permits for the regulation of Clean Water Act


9


discharges. California also regulates certain discharges not regulated by the US EPA. Effective October 1, 2010, the California State Water Resources Control Board issued a final policy, which establishes closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like SCE's San Onofre and many of the existing fossil-fueled power plants along the California coast. The final policy required an independent engineering study to be completed prior to the fourth quarter of 2013 regarding the feasibility of compliance by California's two coastal nuclear power plants. The policy may result in significant capital expenditures at San Onofre and may affect its operations.
Coal Combustion Wastes
US EPA regulations currently classify coal ash and other coal combustion residuals as solid wastes that are exempt from hazardous waste requirements. This classification enables beneficial uses of coal combustion residuals, such as for cement production and fill materials. In June 2010, the US EPA published proposed regulations relating to coal combustion residuals that could result in their reclassification. For further discussion see "Item 8. SCE Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
Greenhouse Gas Regulation
There have been a number of federal and state legislative and regulatory initiatives to reduce GHG emissions. Any climate change regulation or other legal obligation that would require substantial reductions in GHG emissions or that would impose additional costs or charges for the emission of GHGs could significantly increase the cost of generating electricity from fossil fuels, and especially from coal-fired plants, as well as the cost of purchased power, which could adversely affect SCE.
Federal Legislative/Regulatory Developments
In June 2010, the US EPA issued the Prevention of Significant Deterioration ("PSD") and Title V Greenhouse Gas Tailoring Rule, known as the "GHG tailoring rule." This regulation generally subjects newly constructed sources of GHG emissions and newly modified existing major sources to the PSD air permitting program beginning in January 2011 (and later, to the Title V permitting program under the CAA); however the GHG tailoring rule significantly increases the emissions thresholds that apply before facilities are subjected to these programs. The emissions thresholds for CO2 equivalents in the final rule vary from 75,000 tons per year to 100,000 tons per year depending on the date and whether the sources are new or modified.
Regulation of GHG emissions pursuant to the PSD program could affect efforts to modify SCE's facilities in the future, and could subject new capital projects to additional permitting or emissions control requirements that could delay such projects.
In December 2010, the US EPA announced that it had entered into a settlement with various states and environmental groups to resolve a long-standing dispute over regulation of GHGs from electrical generating units pursuant to the New Source Performance Standards in the CAA and would propose performance standards for emissions from new and modified power plants and emissions guidelines for existing power plants. The specific requirements will not be known until the regulations are finalized. Since January 2010, the US EPA's Final Mandatory GHG Reporting Rule has required all sources within specified categories, including electric generation facilities, to monitor emissions, and to submit annual reports to the US EPA by March 31 of each year. SCE's 2011 GHG emissions were approximately 5.8 million metric tons.
Regional Initiatives and State Legislation
Regional initiatives and state legislation may also require reductions of GHG emissions and it is not yet clear whether or to what extent any federal legislation would preempt them. If state and/or regional initiatives remain in effect after federal legislation is enacted, utilities and generators could be required to satisfy them in addition to the federal standards.
SCE's operations in California are subject to two laws governing GHG emissions. The first law, the California Global Warming Solutions Act of 2006 (also referred to as AB 32), establishes a comprehensive program to reduce GHG emissions. AB 32 requires the California Air Resources Board ("CARB") to develop regulations, effective in 2012, that would reduce California's GHG emissions to 1990 levels in yearly increments by 2020. In December 2011, the CARB regulation was officially published establishing a California cap-and-trade program. The first compliance period under the regulations is for 2013 GHG emissions. CARB regulations implementing a cap-and-trade program and the cap-and-trade program itself, continue to be the subject of litigation. In December 2011, a federal district court enjoined the Low Carbon Fuel Standard, another AB 32 program regulating the carbon content of transportation fuels, on constitutional commerce clause grounds. Additional litigation challenging the cap-and-trade program on similar grounds is expected, though no suit has been filed to date.
The second law, SB 1368, required the CPUC and the CEC to adopt GHG emission performance standards restricting the ability of California investor-owned and publicly owned utilities, respectively, to enter into long-term arrangements for the purchase of electricity. The standards that have been adopted prohibit these entities, including SCE, from entering into long-


10


term financial commitments with generators that emit more than 1,100 pounds of CO2 per MWh, the performance of a combined-cycle gas turbine generator. SB 1368 may prohibit SCE from making emission control expenditures at Four Corners. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for information on the sale of SCE's interest in Four Corners.
California law has also required SCE to increase its electricity generated from renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are provided from such resources (the "RPS Program") by no later than December 31, 2010 or such later date as flexible compliance requirements permit. In accordance with the procurement rules and regulations, SCE demonstrated full compliance with the RPS Program in its March 2011 and August 2011 filings.
In April 2011, California enacted a law requiring California retail sellers of electricity to procure 33% of their customers' electricity requirements from renewable resources, as defined in the statute. The impact of the new 33% law will depend on how the CPUC and CEC implement the law, which remains uncertain. On December 1, 2011, the CPUC approved a decision setting procurement quantity requirements for CPUC-regulated retail sellers that incrementally increase to 33% over several periods between January 2011 and December 31, 2020. The quantity would remain at 33% of retail sales for each year thereafter. Currently SCE estimates its delivery of eligible renewable resources to customers to be 21% of its total energy portfolio for 2011.
Litigation Developments
Litigation alleging that GHG is a public and private nuisance may affect SCE, whether or not it is named as a defendant. The law is unsettled on whether or not this litigation presents questions capable of judicial resolution or political questions that should be resolved by the legislative or executive branches. For further discussion see "Item 8. SCE Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
ITEM 1A.    RISK FACTORS
Regulatory Risks
SCE's financial results depend upon its ability to recover its costs in a timely manner from its customers through regulated rates.
SCE's ongoing financial results depend on its ability to recover from its customers in a timely manner its costs, including the costs of electricity purchased for its customers, through the rates it charges its customers as approved by the CPUC and FERC. SCE's financial results also depend on its ability to earn a reasonable return on capital, including long-term debt and equity. SCE's capital investment plan, increasing procurement of renewable power, increasing environmental regulations, moderating demand, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customer rates. Increases in self generation also reduce the pool of customers from whom fixed costs are recovered, while costs potentially increase due to system modifications that may be necessary to cope with the systemic effects of self-generation. Customers that self-generate their own power do not currently pay most transmission and distribution charges and are only subject to certain non-bypassable charges. The net result is to increase utility rates further for those customers who do not self-generate, which encourages more self generation and further rate increases. If SCE is unable to obtain a sufficient rate increase or to recover material amounts of its costs in rates in a timely manner or recover an adequate return on capital, its financial condition and results of operations could be materially adversely affected. For further information on SCE's rate requests, see "Management Overview—2012 General Rate Case" and "—FERC Formula Rates" in the MD&A.
SCE's energy procurement activities are subject to regulatory and market risks that could adversely affect its financial condition and liquidity.
SCE obtains energy, capacity, environmental credits and ancillary services needed to serve its customers from its own generating plants, as well as through contracts with energy producers and sellers. California law and CPUC decisions allow SCE to recover through the rates it is allowed to charge its customers reasonable procurement costs incurred in compliance with an approved procurement plan. Nonetheless, SCE's cash flows remain subject to volatility primarily resulting from changes to commodity prices. In addition, SCE is subject to the risks of unfavorable or untimely CPUC decisions about the compliance with SCE's procurement plan and the reasonableness of certain procurement-related costs.
SCE may not be able to hedge its risk for commodities on economic terms or fully recover the costs of hedges through the rates it is allowed to charge its customers, which could adversely affect SCE's liquidity and results of operations, see "Liquidity and Capital Resources—Market Risk Exposures" in the MD&A.


11


SCE is subject to extensive regulation and the risk of adverse regulatory decisions and changes in applicable regulations or legislation.
SCE operates in a highly regulated environment. SCE's business is subject to extensive federal, state and local energy, environmental and other laws and regulations. The CPUC regulates SCE's retail operations, and the FERC regulates SCE's wholesale operations. The NRC regulates SCE's nuclear power plants. The construction, planning, and project site identification of SCE's power plants and transmission lines in California are also subject to the jurisdiction of the California Energy Commission (for plants 50 MW or greater) and the CPUC.
SCE must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective orders. Should SCE be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose penalties or disallowances on SCE, SCE's business could be adversely affected. The process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by concerted community opposition and such delay or defeat would have an adverse effect on SCE's business.
This extensive governmental regulation creates significant risks and uncertainties for SCE's business. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to SCE, or its facilities or operations in a manner that may have a detrimental effect on SCE's business or result in significant additional costs. In addition, regulation adopted via the public initiative process may apply to SCE, or its facilities or operations in a manner that may have a detrimental effect on SCE's business or result in significant additional costs.
The generation, transmission and distribution of electricity are dangerous and involve inherent risks of injury to employees and the general public.
Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical equipment. Injuries caused by such contact can subject SCE to liability that, despite the existence of insurance coverage, can be significant.. In the wake of recent natural disasters such as windstorms, which can cause wildfires, pole failures and associated property damage and outages, the CPUC has increased its focus on public safety issues with an emphasis on heightened compliance with construction and operating standards and the potential for penalties being imposed on utilities. Such penalties and liabilities could be significant but are very difficult to predict. The range of possible penalties and liabilities includes amounts that could adversely affect SCE's liquidity and results of operations.
Operating Risks
SCE's financial condition and results of operations could be materially adversely affected if it is unable to successfully manage the risks inherent in operating and improving its facilities.
SCE's infrastructure is aging and could pose a risk to system reliability. In order to mitigate this risk, SCE is engaged in one of the largest infrastructure investment programs in its history, which involves multiple large-scale projects in multiple locations. This substantial increase in activity from SCE's historical levels elevates the operational risks and the need for superior execution in its activities. SCE's financial condition and results of operations could be materially affected if it is unable to successfully manage these risks as well as the risks inherent in operating and improving its facilities, the operation of which can be hazardous. SCE's inherent operating risks include such matters as the risks of human performance, workforce capabilities, public opposition to infrastructure projects, delays, environmental mitigation costs, difficulty in estimating costs, system limitations and degradation, and interruptions in necessary supplies. For example, SCE has recently experienced significant additional costs and disruptions in the progress of its Tehachapi Renewable Transmission Project. See "Liquidity and Capital Resources—Capital Investment Plan" in the MD&A.
SCE's systems and network infrastructure may be vulnerable to cyber attacks, intrusions or other catastrophic events that could result in their failure or reduced functionality.
Regulators, such as the NERC, and U.S. Government Departments, including the Departments of Defense, Homeland Security and Energy, have noted that the U.S. national electric grid and other energy infrastructures have potential vulnerabilities to cyber attacks and disruptions and that such cyber threats are becoming increasingly sophisticated and dynamic. SCE's operations require the continuous operation of critical information technology systems and network infrastructure. Although SCE actively monitors developments in this area and is involved in various industry groups and government initiatives, no security measures can completely shield such systems and infrastructure from vulnerabilities to cyber attacks, intrusions or other catastrophic events that could result in their failure or reduced functionality. If SCE's information technology systems security measures were to be breached or a critical system failure were to occur without timely recovery, SCE could be unable to fulfill critical business functions and/or sensitive confidential personal and other


12


data could be compromised, which could adversely affect SCE's financial condition and results of operations. See "Item 1. Business—Regulation—NERC" for further discussion.
There are inherent risks associated with operating nuclear power generating facilities.
Continued NRC scrutiny of San Onofre may result in additional corrective actions that will increase operations and maintenance costs or require additional capital expenditures.
San Onofre is subject to extensive oversight and scrutiny of the NRC. This scrutiny may result in SCE being required to take additional corrective actions and incur increased operations and maintenance expenses or new capital expenditures. If SCE is unable to take effective corrective actions required by the NRC, the NRC has the authority to impose fines or shut down a unit, or both, depending upon the NRC's assessment of the severity of the situation, until compliance is achieved. See "Item 1. Business—Regulation—Nuclear Power Plant Regulation" for further discussion.
Existing insurance and ratemaking arrangements may not protect SCE fully against losses from a nuclear incident.
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 the San Onofre and Palo Verde Nuclear Generating Stations have purchased the maximum private primary insurance available of $375 million per site. If nuclear incident liability claims were to exceed $375 million, the remaining amount would be made up from contributions of approximately $12.2 billion made by all of the nuclear facility owners in the U.S., up to an aggregate total of $12.6 billion. There is no assurance that the CPUC would allow SCE to recover the required contribution made in the case of one or more nuclear incident claims that exceeded $375 million. If this public liability limit of $12.6 billion is insufficient, federal law contemplates that additional funds may be appropriated by Congress. There can be no assurance of SCE's ability to recover uninsured costs in the event the additional federal appropriations are insufficient. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Nuclear Insurance."
Spent fuel storage capacity could be insufficient to permit long-term operation of SCE's nuclear plants.
The U.S. Department of Energy has defaulted on its obligation to begin accepting spent nuclear fuel from commercial nuclear industry participants by January 31, 1998. If SCE or the operator of Palo Verde were unable to arrange and maintain sufficient capacity for interim spent-fuel storage now or in the future, it could hinder the operation of the plants and impair the value of SCE's ownership interests until storage could be obtained, each of which may have a material adverse effect on SCE.
SCE's insurance coverage for wildfires arising from its ordinary operations may not be sufficient and Edison International may not be able to obtain sufficient insurance on SCE's behalf for such occurrences.
Edison International has been experiencing increased costs and difficulties in obtaining insurance coverage for wildfires that could arise from SCE's ordinary operations. In addition, the insurance Edison International has obtained on SCE's behalf for wildfire liabilities may not be sufficient. Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates. A loss which is not fully insured or cannot be recovered in customer rates could materially and adversely affect Edison International's and SCE's financial condition and results of operations. Furthermore, insurance for wildfire liabilities may not continue to be available at all or at rates or on terms similar to those presently available to Edison International. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
Environmental Risks
SCE is subject to extensive environmental regulations that may involve significant and increasing costs and adversely affect SCE.
SCE is subject to extensive and frequently changing environmental regulations and permitting requirements that involve significant and increasing costs and substantial uncertainty. SCE devotes significant resources to environmental monitoring, pollution control equipment, mitigation projects, and emission allowances to comply with existing and anticipated environmental regulatory requirements. However, the current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. The adoption of laws and regulations to implement greenhouse gas controls could adversely affect operations, particularly of SCE's coal-fired plants. SCE may also be exposed to risks arising from past, current or future contamination at its former or existing facilities or with respect to offsite waste disposal sites that have been used in its operations. Other environmental laws, particularly with respect to air emissions, disposal of ash, wastewater discharge and cooling water systems, are also generally becoming more stringent. The continued operation of SCE facilities may require substantial capital expenditures for environmental controls or cessation of operations. Current and future state laws and regulations in California also could increase the required amount of energy that must be procured from


13


renewable resources. See "Item 1. Business—Environmental Matters" and "Item 8. SCE Notes to Consolidated Financial Statements—Note 10. Environmental Developments" for further discussion of environmental regulations under which SCE operates.
Financing Risks
As a capital intensive company, SCE relies on access to the capital markets. If SCE were unable to access the capital markets or the cost of financing were to substantially increase, its liquidity and operations would be adversely affected.
SCE regularly accesses the capital markets to finance its activities and is expected to do so by its regulators as part of its obligation to serve as a regulated utility. SCE's needs for capital for its ongoing infrastructure investment program are substantial. SCE's ability to arrange financing, as well as its ability to refinance debt and make scheduled payments of principal and interest, are dependent on numerous factors, including SCE's levels of indebtedness, maintenance of acceptable credit ratings, its financial performance, liquidity and cash flow, and other market conditions. SCE's failure to obtain additional capital from time to time would have a material adverse effect on SCE's liquidity and operations. See "Liquidity and Capital Resources—Capital Investment Plan" and "—Historical Consolidated Cash Flows" in the MD&A.
ITEM 1B.    UNRESOLVED STAFF COMMENTS
None.
ITEM 2.    PROPERTIES
The principal properties of SCE are described above under the heading "Item 1. Business—Properties."
ITEM 3.    LEGAL PROCEEDINGS
None.
Pursuant to Form 10-K's General Instruction G(3), the following information in included as an additional item in Part I:
EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officer
 
Age at
December 31, 2011
 
Company Position
Ronald L. Litzinger
 
52
 
President
Stephen E. Pickett
 
61
 
Executive Vice President, External Relations
Lynda L. Ziegler
 
59
 
Executive Vice President, Power Delivery Services
Peter T. Dietrich
 
47
 
Senior Vice President and Chief Nuclear Officer
Linda G. Sullivan
 
48
 
Senior Vice President and Chief Financial Officer
Russell C. Swartz
 
60
 
Senior Vice President and General Counsel
Chris C. Dominski
 
45
 
Vice President and Controller
As set forth in Article IV of SCE's Bylaws, the elected officers of SCE are chosen annually by, and serve at the pleasure of, SCE's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. All of the above officers have been actively engaged in the business of SCE, its parent company Edison International, and/or one of SCE's subsidiaries or other affiliates for more than five years, except


14


for Mr. Dietrich, and have served in their present positions for the periods stated below. Additionally, those officers who have had other or additional principal positions in the past five years had the following business experience during that period:
Executive Officer
 
Company Position
 
Effective Dates
Ronald L. Litzinger
 
President, SCE
 
January 2011 to present
 
 
Chairman of the Board, President and Chief Executive Officer, EMG1
 
April 2008 to December 2010
 
 
Senior Vice President, Transmission and Distribution, SCE
 
May 2005 to March 2008
Stephen E. Pickett
 
Executive Vice President, External Relations, SCE
 
February 2011 to present
 
 
Executive Vice President, External Relations and General Counsel, SCE
 
January 2011 to February 2011
 
 
Senior Vice President and General Counsel, SCE
 
January 2002 to December 2010
Lynda L. Ziegler
 
Executive Vice President, Power Delivery Services, SCE
 
January 2011 to present
 
 
Senior Vice President, Customer Service, SCE
 
March 2006 to December 2010
Peter T. Dietrich
 
Senior Vice President and Chief Nuclear Officer, SCE
 
December 2010 to present
 
 
Senior Vice President, SCE
 
November 2010 to present
 
 
Site Vice President, Entergy Nuclear Operations, Inc.,
James A. Fitzpatrick Nuclear Plant2
 
April 2006 to November 2010
Stuart R. Hemphill
 
Senior Vice President, Power Supply
 
January 2011 to present
 
 
Senior Vice President, Power Procurement, SCE
 
July 2009 to December 2010
 
 
Vice President, Renewable and Alternative Power, SCE
 
March 2008 to June 2009
 
 
Director of Renewable and Alternative Power, SCE
 
April 2006 to March 2008
Linda G. Sullivan
 
Senior Vice President and Chief Financial Officer, SCE
 
March 2010 to present
 
 
Senior Vice President, Chief Financial Officer and Acting Controller, SCE
 
July 2009 to March 2010
 
 
Vice President and Controller, Edison International
 
June 2005 to August 2009
 
 
Vice President and Controller, SCE
 
June 2005 to June 2009
Russell C. Swartz
 
Senior Vice President and General Counsel, SCE
 
February 2011 to present
 
 
Vice President and Associate General Counsel, SCE
 
February 2010 to February 2011
 
 
Associate General Counsel, SCE
 
March 2007 to February 2010
 
 
Assistant General Counsel, SCE
 
February 2002 to February 2007
Chris C. Dominski
 
Vice President, and Controller, SCE
 
March 2010 to present
 
 
Assistant Controller, Edison International
 
March 2007 to April 2010
 
 
Assistant Controller, SCE
 
March 2007 to March 2010
 
 
Manager, Financial Planning and Analysis, SCE
 
July 2006 to March 2007
1 
EMG is the holding company of Edison Mission Energy, an independent power producer. EMG is a wholly-owned subsidiary of Edison International and is an affiliate of SCE.
2 
Entergy Nuclear Operations, Inc. is a subsidiary of Entergy Corporation, an integrated energy company and is not a parent, affiliate or subsidiary of SCE.



15


PART II
ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Certain information responding to Item 5 with respect to frequency and amount of cash dividends is included in "Item 8. SCE Notes to the Consolidated Financial Statements—Note 17. Quarterly Financial Data." As a result of the formation of a holding company described in Item 1 above, all of the issued and outstanding common stock of SCE is owned by Edison International and there is no market for such stock.
Item 201(d) of Regulation S-K, "Securities Authorized for Issuance under Equity Compensation Plans," is not applicable because SCE has no compensation plans under which equity securities of SCE are authorized for issuance.
ITEM 6.    SELECTED FINANCIAL DATA
Selected Financial Data: 2007 – 2011
(Dollars in millions)
2011
 
2010
 
2009
 
2008
 
2007
Income statement data:
 
 
 
 
 
 
 
 
 
Operating revenue
$
10,577

 
$
9,983

 
$
9,965

 
$
11,248

 
$
10,233

Operating expenses
8,454

 
8,119

 
8,047

 
9,595

 
8,492

Net income
1,144

 
1,092

 
1,371

 
904

 
1,063

Net income available for common stock
1,085

 
1,040

 
1,226

 
683

 
707

Balance sheet data:

 
 
 
 
 
 
 
 
Total assets
$
40,315

 
$
35,906

 
$
32,474

 
$
32,568

 
$
27,477

Long-term debt including current portion
8,431

 
7,627

 
6,740

 
6,362

 
5,081

Common shareholder's equity
8,913

 
8,287

 
7,446

 
6,513

 
6,228

Preferred and preference stock
1,045

 
920

 
920

 
920

 
929

Capital structure:

 
 
 
 
 
 
 
 
Common shareholder's equity
48.5
%
 
49.2
%
 
49.3
%
 
47.2
%
 
50.9
%
Preferred and preference stock
5.7
%
 
5.5
%
 
6.1
%
 
6.7
%
 
7.6
%
Long-term debt
45.8
%
 
45.3
%
 
44.6
%
 
46.1
%
 
41.5
%
The selected financial data was derived from SCE's audited financial statements and is qualified in its entirety by the more detailed information and financial statements, including notes to these financial statements, included in this annual report.



16


ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MANAGEMENT OVERVIEW
SCE's core mission is to deliver safe, reliable and affordable electric service to its customers. Accomplishing this mission requires balancing competing priorities, including public policies regarding air and water quality, energy efficiency and renewable energy and the need to replace aging infrastructure. The accumulation of several major policy mandates is expected to add significantly to the cost of electric service, which could cause a growing number of customers to seek to self-generate their power. Choices by customers to self-generate results in fewer kilowatt hour sales to absorb the increasing costs of the electrical system, further increasing rates for SCE's other customers. Working with policy makers to balance competing priorities, a key focus of SCE is to manage the costs that drive increases in electricity rates while delivering safe and reliable electric service to its customers.
Highlights of Operating Results
(in millions)
2011
 
2010
 
Change
 
2009
Net income available for common stock
$
1,085

 
$
1,040

 
$
45

 
$
1,226

Less: Non-core items
 
 
 
 
 
 
 
Global Settlement

 
95

 
(95
)
 
306

Tax impact of health care legislation

 
(39
)
 
39

 

Regulatory items

 

 

 
46

Total non-core items

 
56

 
(56
)
 
352

Core Earnings
$
1,085

 
$
984

 
$
101

 
$
874

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 primarily due to rate base growth.
Non-core items included:
An earnings benefit of $95 million recorded in 2010 relating to the California impact of the federal Global Settlement resulting from acceptance by the California Franchise Tax Board of tax positions finalized with the IRS in 2009 and receipt of the final interest determination from the Franchise Tax Board. For further discussion of the Global Settlement, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 7. Income Taxes."
An after-tax earnings charge of $39 million recorded in 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.
See "Results of Operations" for discussion of SCE results of operations, including a comparison of 2010 results to 2009.
2012 CPUC General Rate Case
SCE filed its 2012 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 at San Onofre, 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 and including the impacts of reducing SCE's solar program as approved by the CPUC, would result in incremental customer base rate increases of $809 million, $117 million and $513 million in 2012, 2013 and 2014, respectively.
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


17


reductions and approximately $220 million in capital-related revenue requirement reductions. The Utility Reform Network ("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 investments for specific projects. Intervenors have also recommended changes to SCE's proposed post-test year ratemaking methodology to be used for 2013 and 2014 as well as limiting the recovery amount of SCE's pension costs. A final decision on the GRC is expected in the first half of 2012. The CPUC has authorized the establishment of a GRC memorandum account, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012. Recognition of the revenue for the period January 1, 2012 through the date of a final decision, as well as any delays in certain expenditures, may impact the timing of earnings in 2012.
FERC Formula Rates
The FERC has accepted, subject to refund and settlement procedures, SCE's request to implement formula rates as a means to determine SCE's FERC transmission revenue requirement effective January 1, 2012. The formula rates include revenue requirements related to construction work in progress ("CWIP") that was previously recovered through a separate mechanism. 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 and rate base 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 forecasted annual 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.
Capital Program
During 2011, SCE continued execution of its capital investment program. Total capital expenditures (including accruals) were $3.9 billion in 2011 compared to $3.8 billion in 2010. The level of future spending is significantly dependent on a final outcome of SCE's 2012 GRC decision and the timing, scope and approvals of major transmission projects. SCE's capital program for 2012 – 2014 is focused primarily in the following areas:
Maintaining reliability and expanding the capability of SCE's transmission and distribution system.
Upgrading and constructing new transmission lines and substations for system reliability and increased access to renewable energy, including the Tehachapi, Devers-Colorado River, Eldorado-Ivanpah, and Red Bluff projects.
Completing installation of digital meters in households and small businesses, referred to as EdisonSmartConnectTM. Through 2011, SCE installed 3.8 million meters and plans to install the remaining 1.2 million meters during 2012.
Generation capital projects for nuclear and hydro-electric plants.
SCE forecasts capital expenditures in the range of $11.8 billion to $13.2 billion for 2012 – 2014. 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 as discussed further under "Liquidity and Capital Resources—Capital Investment Plan." SCE has experienced significant cost pressures on its Tehachapi and Devers-Colorado River Transmission Projects, primarily related to environmental monitoring and mitigation costs, scope changes and schedule delays. Currently, SCE is completing the final engineering design for these projects and expects to file revised cost estimates with the CPUC later this year. Subject to further permitting and schedule delays, SCE has revised its direct capital expenditure estimates for the Tehachapi Project to $2.5 billion from $2.1 billion and revised its estimates for the Devers-Colorado River Project to $860 million from $649 million. The Tehachapi Project may be further impacted by issues related to aviation marking and lighting and community opposition to portions of the line, as further discussed in "Liquidity and Capital Resources—Capital Investment Plan." Capital program cost increases have been partially offset by expenditures for other transmission reliability projects, which were deferred due to delays from once-through cooling requirements for coastal generating plants. SCE plans to utilize cash generated from its operations, tax benefits and issuance of additional debt and preferred equity to fund its capital needs.
Environmental Developments
For a discussion of environmental developments, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 10. Environmental Developments."


18


RESULTS OF OPERATIONS
SCE's results of operations are derived mainly through two sources:
Utility earning activities – representing revenue authorized by the CPUC and FERC which is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution assets. The annual revenue requirements are comprised of forecasted operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure. Also, included in utility earnings activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.
Utility cost-recovery activities – representing CPUC- and FERC-authorized balancing accounts which allow for recovery of specific project or program costs incurred or provide for mechanisms to track and recover or refund differences in forecasted and actual amounts, subject to reasonableness review or compliance with upfront standards.
The following table is a summary of SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities.
 
2011
2010
2009
(in millions)
Utility
Earning
Activities
Utility
Cost-
Recovery
Activities
Total
Consolidated
Utility
Earning
Activities
Utility
Cost-
Recovery
Activities
Total
Consolidated
Utility
Earning
Activities
Utility
Cost-
Recovery
Activities1,2
Total
Consolidated
Operating revenue
$
5,902

$
4,675

$
10,577

$
5,606

$
4,377

$
9,983

$
5,303

$
4,662

$
9,965

Fuel and purchased power

3,356

3,356


3,293

3,293


3,472

3,472

Operations and maintenance
2,208

1,179

3,387

2,271

1,020

3,291

2,111

1,043

3,154

Depreciation decommissioning and amortization
1,294

132

1,426

1,213

60

1,273

1,124

54

1,178

Property taxes and other
277

8

285

260

3

263

244


244

Gain on sale of assets




(1
)
(1
)

(1
)
(1
)
Total operating expenses
3,779

4,675

8,454

3,744

4,375

8,119

3,479

4,568

8,047

Operating income
2,123


2,123

1,862

2

1,864

1,824

94

1,918

Net interest expense and other
(378
)

(378
)
(330
)
(2
)
(332
)
(298
)

(298
)
Income before income taxes
1,745


1,745

1,532


1,532

1,526

94

1,620

Income tax expense
601


601

440


440

249


249

Net income
1,144


1,144

1,092


1,092

1,277

94

1,371

Net income attributable to noncontrolling interest







94

94

Dividends on preferred and preference stock
59


59

52


52

51


51

Net income available for common stock
$
1,085

$

$
1,085

$
1,040

$

$
1,040

$
1,226

$

$
1,226

Core Earnings3
 

 

$
1,085

 

 

$
984

 

 

$
874

Non-Core Earnings:
 
 
 
 
 
 
 
 
 
Global tax settlement
 

 


 

 

95

 

 

306

Tax impact of health care legislation
 

 


 

 

(39
)
 

 


Regulatory items
 

 


 

 


 

 

46

Total SCE GAAP Earnings
 

 

$
1,085

 

 

$
1,040

 

 

$
1,226

1 
Effective January 1, 2010, SCE deconsolidated the Big 4 projects and therefore these projects are reflected in 2009 activities only (see "Item 8. SCE Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities" for further discussion).
2 
Effective July 1, 2009, SCE transferred Mountainview Power Company, LLC to SCE. As a result of the transfer and for comparability purposes, Mountainview's 2009 activity was reclassified from cost-recovery activities to utility earning activities consistent with the revised recovery mechanism.
3 
See use of Non-GAAP financial measures in "Management Overview—Highlights of Operating Results."


19


Utility Earning Activities
2011 vs. 2010
Utility earning activities were primarily affected by the following:
Higher operating revenue of $296 million primarily due to the following:
$135 million increase primarily due to a $215 million (4.35%) increase in 2011 authorized revenue approved in the 2009 CPUC GRC decision. The 2011 increase was partially offset by reductions of $80 million mainly resulting from revenue recognized in 2010 associated with the recovery of San Onofre Unit 3 scheduled outage costs with no comparable amount in 2011.
$95 million increase in FERC-related revenue primarily resulting from the inclusion of capital expenditures related to the Tehachapi Transmission Project in rate base.
$25 million increase in capital-related revenue requirements related to the San Onofre steam generator replacement project and a $20 million increase for the EdisonSmartConnectTM project.
$20 million increase related to recovery of legal costs incurred between 2004 and 2009 in support of SCE's efforts to obtain generator refunds related to claims arising out of the energy crisis in California in 2000 – 2001.
Lower operation and maintenance expense of $63 million primarily due to costs incurred in 2010 related to the San Onofre Unit 3 scheduled outage.
Higher depreciation, decommissioning and amortization expense of $81 million primarily related to increased transmission and distribution investments.
Higher net interest expense and other of $48 million primarily due to higher outstanding balances on long-term debt. For details of other income and expenses, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 16. Other Income and Expenses."
Higher income taxes primarily due to an increase in income as well as benefits recorded in 2010 related to the Global Settlement. See "—Income Taxes" below for more information.
2010 vs. 2009
Utility earning activities were primarily affected by the following:
Higher operating revenue of $303 million primarily due to the following:
$190 million increase primarily due to a 4.25% increase in 2010 authorized revenue approved in the 2009 CPUC GRC decision.
$55 million increase in FERC-related revenue, primarily due to the implementation of SCE's 2010 and 2009 FERC rate cases effective March 1, 2010 and March 1, 2009, respectively.
$25 million increase in capital-related revenue requirements related to the San Onofre steam generator replacement project and a $20 million increase for the EdisonSmartConnect™ project.
Higher operation and maintenance expense of $160 million primarily due to the following:
$75 million of higher expenses to support company growth programs, including new information technology system requirements and facility maintenance.
$45 million of higher transmission and distribution expenses to support system reliability and infrastructure replacement, right of way costs; preventive maintenance work, technical training and line clearing.
$15 million of higher generation expenses primarily from a $25 million increase from the San Onofre Unit 2 and 3 scheduled outages, including $10 million of additional work identified during the Unit 2 scheduled outage, and a $10 million increase primarily due to overhaul and outage costs at Four Corners. These increases were partially offset by a $20 million decrease resulting from 2009 scheduled outages at the Mountainview power plant.
$15 million of higher expense related to general liability and property insurance due to higher premiums for wildfire coverage.


20


Higher depreciation expense of $89 million primarily related to increased capital expenditures, including capitalized software costs.
Higher net interest expense and other of $32 million primarily due to:
Lower other income of $19 million primarily related to a decrease in AFUDC – equity earnings due to the transfer of the Mountainview power plant to utility rate base in the third quarter of 2009 partially offset by an increase in AFUDC – equity resulting from a higher capitalization rate and level of construction in progress associated with SCE's capital expenditure plan.
Higher interest expense of $7 million primarily due to higher outstanding balances on long-term debt.
See "—Income Taxes" below for discussion of higher income taxes during 2010 compared to the same period in 2009.
Utility Cost-Recovery Activities
2011 vs. 2010
Utility cost-recovery activities were primarily affected by the following:
Higher purchased power expense of $59 million primarily driven by the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but impacted customer bills (see "—Supplemental Operating Revenue Information" below), and higher costs associated with 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 $159 million including $75 million of increased energy efficiency program costs and $40 million related to the EdisonSmartConnectTM project.
Higher depreciation, decommissioning and amortization expense of $72 million including $35 million related to the EdisonSmartConnectTM project and $25 million related to the San Onofre steam generator replacement project.
2010 vs. 2009
Utility cost-recovery activities exclude the impact of the consolidation of the Big 4 projects in 2009 for comparability purposes. The following amounts were excluded for 2009: $370 million for purchased power expense to reflect the elimination of sales between the VIEs and SCE; $368 million for fuel expense; and $94 million for operation and maintenance expense. Utility cost-recovery activities were primarily affected by:
Lower purchased power expense of $191 million primarily related to lower realized losses on economic hedging activities ($156 million in 2010 compared to $344 million in 2009) reflecting the impact of higher natural gas prices in 2010 and changes in SCE's hedge portfolio mix.
Higher operation and maintenance expense of $71 million primarily due to an increase in spending for various public purpose programs.
Supplemental Operating Revenue Information
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $10.0 billion for both 2011 and 2010 and $9.5 billion for 2009. The 2011 revenue reflects:
a rate decrease of $408 million resulting from a rate adjustment beginning on June 1, 2011, primarily reflecting the refund of over collected fuel and power procurement-related costs, offset by
a sales volume increase of $393 million primarily due to SCE providing power that was previously provided by CDWR contracts which expired in 2011.
The 2010 revenue reflects:
a rate increase of $777 million mainly due to the implementation of the CPUC 2009 GRC decision and approved FERC transmission rate changes, partially offset by
a sales volume decrease of $255 million primarily due to milder weather experienced during 2010 compared to the same period in 2009 and continuing recessionary effects.
As a result of the CPUC-authorized decoupling mechanism, SCE earnings are not affected by changes in retail electricity


21


sales (see "Item 1. Business—Overview of Ratemaking Process").
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, as well as CDWR bond-related costs and a portion of direct access exit fees. The amounts collected and remitted to CDWR were $1.1 billion, $1.2 billion and $1.8 billion for years ended December 31, 2011, 2010 and 2009, respectively. All CDWR power contracts allocated to SCE by the CPUC had expired by the end of 2011. SCE's revenue and related purchased power expense is expected to increase in 2012 as these CDWR contracts are replaced by new power purchase agreements entered into by SCE.
Effective January 1, 2010, the CDWR-related rates were decreased to reflect lower power procurement expenses and a refund of operating reserves that CDWR releases as its contracts terminate. Approximately $440 million is expected to be refunded to SCE customers through lower CDWR rates in 2012.
Income Taxes
The table below provides an analysis of the principal factors impacting SCE's effective tax rate.
 
Years ended December 31,
 (in millions)
2011
2010
2009
Income from continuing operations before income taxes
$
1,745

$
1,532

$
1,620

Net income attributable to noncontrolling interests in the Big 4 projects


(94
)
Adjusted income from continuing operations before income taxes
$
1,745

$
1,532

$
1,526

Provision for income tax at federal statutory rate of 35%
$
611

$
536

$
534

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

(95
)
(306
)
Change in tax accounting method for asset removal costs2

(40
)

State tax – net of federal benefit
80

59

67

Health care legislation3

39


Property-related
(76
)
(47
)
(64
)
Other
(14
)
(12
)
18

Total income tax expense from continuing operations
$
601

$
440

$
249

Effective tax rate
34.4
%
28.7
%
16.3
%
1 
Edison International and the IRS finalized the terms of a Global Settlement on May 5, 2009. The Global Settlement resolved all of SCE's federal income tax disputes and affirmative claims through tax year 2002. During 2009, SCE recorded after-tax earnings of approximately $306 million. During 2010, SCE recognized a $95 million earnings benefit from the acceptance by the California Franchise Tax Board of the tax positions finalized in 2009 and receipt of the final interest determination from the Franchise Tax Board.
2 
During 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 as required by the CPUC.
3 
During 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 increase in income taxes for property-related items was primarily due to a cumulative deferred income tax adjustment of $30 million in 2011 related to nuclear fuel.
For a discussion of the status of Edison International's income tax audits, see "SCE Notes to Consolidated Financial Statements—Note 7. Income Taxes."


22


LIQUIDITY AND CAPITAL RESOURCES
SCE's ability to operate its business, fund capital expenditures, and implement its business strategy are dependent upon its cash flow and access to the capital markets. 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, interest and dividend payments to investors, and the outcome of tax and regulatory matters.
SCE expects to fund its 2012 obligations, capital expenditures and dividends through 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 to meet operating and capital requirements.
In January and February 2012, SCE issued 250,000 shares and 100,000 shares, respectively, of 6.25% Series E preference stock (cumulative, $1,000 liquidation value). The Series E preference stock may not be redeemed prior to February 1, 2022. The proceeds from the sale of these shares were used to repay commercial paper borrowings issued to fund SCE's capital program.
Available Liquidity
SCE has two credit facilities: a $2.4 billion five-year credit facility that matures in February 2013 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
(419
)
Outstanding letters of credit
(81
)
Amount available
$
2,394

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 December 31, 2011, SCE's debt to total capitalization ratio was 0.48 to 1.
Capital Investment Plan
SCE's forecasted capital expenditures for 2012 – 2014 include a capital forecast in the range of $11.8 billion to $13.2 billion based on the average variability experienced in 2011, 2010 and 2009 of 11% between annual forecast capital expenditures and actual spending. This capital forecast includes certain projects under CPUC jurisdiction that are subject to the outcome of the 2012 CPUC GRC. The completion of projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, weather and other unforeseen conditions.
SCE's 2011 capital expenditures and the 2012 – 2014 capital expenditures forecast are set forth in the table below:
(in millions)
 
2011
Actual
2012
2013
2014
Total
Transmission
 
$
929

$
1,547

$
1,452

$
850

$
3,849

Distribution
 
1,847

2,304

2,355

2,416

7,075

Generation
 
729

743

642

520

1,905

EdisonSmartConnect™
 
372

373



373

Total Estimated Capital Expenditures1
 
$
3,877

$
4,967

$
4,449

$
3,786

$
13,202

Total Estimated Capital Expenditures for 2012 – 2014 (using 11% variability discussed above)
 
 
$
4,421

$
3,960

$
3,369

$
11,750

1 
Included in SCE's capital expenditures plan are projected environmental capital expenditures of $499 million, $534 million and $576 million in 2012, 2013 and 2014, respectively. The projected environmental capital expenditures are to comply with laws, regulations, and other nondiscretionary requirements.


23


Transmission Projects
SCE has experienced cost increases on its Tehachapi and Devers-Colorado River Transmission Projects, primarily related to environmental monitoring and mitigation costs, scope changes and schedule delays. A summary of SCE's major transmission and substation projects during the next three years is presented below:
Project Name
Description
Project Lifecycle Phase
In Service Date
Direct Expenditures1(in millions)
% of Spend Complete
2012 – 2014 Forecast (in millions)
Tehachapi 1-11
Transmission lines and substation
In construction
2009 – 2015
$
2,500

62
%
$
904

Devers-Colorado River
Transmission line
In construction
2013
860

18
%
709

Eldorado-Ivanpah
Substation and upgraded transmission line
Engineering/Construction
2013
444

6
%
417

Red Bluff
Substation
In construction
2013
234

6
%
220

1 
Direct expenditures include direct labor, land and contract costs incurred for the respective projects and exclude overhead costs that are included in the capital expenditures forecasted for 2012 – 2014.
Currently, SCE is completing the final engineering design for the Tehachapi Transmission and the Devers-Colorado River Projects and has increased its 2012 – 2014 forecasted expenditures for these projects as a result of cost pressures discussed above. The Tehachapi Project costs and schedule 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 accordance with FAA standards. In October 2011, the CPUC staff notified SCE that the constructed portions of the project should 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. In January 2012, in response to a CPUC request, SCE provided information on potential new options for a portion of the project, including traversing a state park, changing the nature of some of the towers, and undergrounding lines. Adoption of any of these alternatives could create additional costs and delay the completion of the project. SCE is required to file revised cost estimates with the CPUC. As with all transmission investments, cost recovery will be subject to future rate proceedings.
Distribution Projects
Distribution expenditures include projects and programs to meet customer load growth requirements, reliability and infrastructure replacement needs, information and other technology and related facility requirements.
Generation Projects
Generation expenditures include:
Nuclear-related capital expenditures necessary to maintain safe and reliable plant operation, meet NRC and other regulatory requirements, and optimize plant performance and cost-effectiveness.
Hydro-related capital expenditures associated with infrastructure and equipment replacement and renewal of FERC operating licenses. Infrastructure expenditures include dam improvements, flowline and substation refurbishments, and powerline replacements. Equipment replacement expenditures include transformers, automation, switchgear, hydro turbine repowers, generator rewinds, and small generator replacements.
SCE's Solar Photovoltaic Program to develop up to 125 MW of utility owned Solar Photovoltaic generating facilities generally ranging in size from 1 to 2 MW each, on commercial and industrial rooftops and other space in SCE's service territory. The CPUC has authorized recovery of reasonable costs and allowed for a return on investment.
EdisonSmartConnect™
SCE's EdisonSmartConnect™ project involves installing state-of-the-art "smart" meters in approximately 5 million households and small businesses through its service area. In March 2008, SCE was authorized by the CPUC to recover $1.63 billion in customer rates for the deployment phase of EdisonSmartConnect™. In 2009, SCE began full deployment of meters to all residential and small business customers under 200 kW. SCE anticipates completion of the deployment in 2012. In 2011, the CPUC began exploring the feasibility of allowing customers to voluntarily opt out of smart meter installation.


24


SCE has provided information to the CPUC on the costs and technical issues involved. Should the CPUC order SCE to implement an opt out option, SCE would file an application seeking to recover the associated costs in rates.
Regulatory Proceedings
Energy Efficiency Shareholder Risk/Reward Incentive Mechanism
The CPUC previously adopted and extended through 2009 an Energy Efficiency Risk/Reward Incentive Mechanism ("Energy Efficiency Mechanism") allowing SCE to earn incentives based on SCE's performance toward meeting CPUC energy efficiency goals. In December 2011, the CPUC issued a decision approving an $18 million final payment for 2009 performance under the Energy Efficiency Mechanism. The CPUC is reviewing and may further modify or eliminate the Energy Efficiency Mechanism for performance periods subsequent to 2009.
San Onofre Outage and Repair Issues
Four replacement steam generators were installed at San Onofre Units 2 and 3 in 2010 and 2011. Inspections of the Unit 2 steam generators during a planned maintenance and refueling outage in February 2012 found some isolated areas of wear in some of the 19,454 heat transfer tubes. In light of this condition, SCE, in consultation with the steam generators' manufacturer, determined that a number of the tubes should be removed from service as a preventive measure. The steam generators are designed to include sufficient tubes to accommodate a need to remove some from service for a variety of reasons, including wear, and the tubes that SCE is in the process of preventively removing from service in Unit 2 are well within the extra margin. Additionally, on January 31, 2012, a water leak was detected in one of the tubes of a new steam generator in Unit 3, and the Unit was safely taken offline. Extensive testing of the Unit 3 steam generators is ongoing to fully understand the cause of the leak. In a memorandum dated February 16, 2012, the NRC determined that inasmuch as the leak was in a newly installed steam generator, it will conduct an event follow-up baseline inspection to review San Onofre's response to the leak and verify the appropriateness of its remedial actions. Each Unit will be restarted when repairs on that Unit are completed, and SCE is satisfied that it is safe to do so.
The steam generators were supplied by Mitsubishi Heavy Industries (“MHI”) and are warranted for an initial period of 20 years from acceptance. Subject to certain exceptions, the purchase agreement sets forth specified damages for certain repairs, generally limits MHI's aggregate contractual liability to the approximately $137 million purchase price of the generators and excludes consequential damages from recovery, such as the cost of replacement power. In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million when adjusted for inflation) for SCE's 78.21% share of San Onofre to purchase and install new generators and remove their predecessors. Those expenditures remain subject to CPUC review upon submission of SCE's final costs for the overall project. SCE expects to file an application with the CPUC setting forth final project costs in the third or fourth quarter of 2012. Replacement power costs are recovered through the ERRA balancing account, subject to reasonableness review.
Dividend Restrictions
The CPUC regulates SCE's capital structure which 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 December 31, 2011, SCE's 13-month weighted-average common equity component of total capitalization was 50.4% resulting in the capacity to pay $436 million in additional dividends.
During 2011, SCE made $461 million in dividend payments to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the level of capital expenditures, operating cash flows and earnings.
Margin and Collateral Deposits
Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. Future collateral requirements may differ from the requirements at December 31, 2011, due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, and the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations.
Some of the power procurement contracts contain provisions that require SCE to maintain an investment grade credit rating from the major credit rating agencies. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the liability or post additional collateral.


25


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 December 31, 2011.
(in millions)
 
 
Collateral posted as of December 31, 20111
 
$
149

Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade
 
89

Posted and potential collateral requirements2
 
$
238

1 
Collateral provided to counterparties and other brokers consisted of $51 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $17 million of cash reflected in "Other current assets" on the consolidated balance sheets and $81 million in letters of credit.
2 
There would be no increase to SCE's total posted and potential collateral requirements based on SCE's forward positions as of December 31, 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 December 31, 2011, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $208 million for its workers compensation self-insurance plan.
Regulatory Balancing Accounts
SCE's cash flows are affected by regulatory balancing account over- or under-collections. Over- and under-collections represent differences between cash collected in current rates for specified forecasted costs and the costs actually incurred. With some exceptions, SCE seeks to adjust rates on an annual basis or at other designated times to recover or refund the balances recorded in its balancing account. Under- or over-collections in these balancing accounts impact cash flows and can change rapidly. Over- and under-collections accrue interest based on a three-month commercial paper rate published by the Federal Reserve.
As of December 31, 2011, balancing account net over-collections were $1.2 billion primarily related to public purpose-related program costs as well as fuel and power procurement-related costs. Over-collections for public purpose-related programs are expected to decrease as costs are incurred to fund programs established by the CPUC. The fuel and power procurement-related over-collections of $392 million are expected to be refunded through a rate adjustment in 2012.
Historical Consolidated Cash Flows
The table below sets forth condensed historical cash flow information for SCE.
(in millions)
2011
2010
2009
Net cash provided by operating activities
$
3,261

$
3,386

$
4,069

Net cash provided (used) by financing activities
799

503

(1,999
)
Net cash used by investing activities
(4,260
)
(4,094
)
(3,219
)
Net decrease in cash and cash equivalents
$
(200
)
$
(205
)
$
(1,149
)
Net Cash Provided by Operating Activities
Net cash provided by operating activities decreased $125 million in 2011 compared to 2010. The decrease in cash flows provided by operating activities was primarily due to the following:
$310 million decrease from refunding to customers overcollections of revenue which resulted from actual electricity sales exceeding forecasted electricity sales. SCE began refunding this balance through a rate adjustment effective June 1, 2011;
$250 million decrease resulting from higher balancing account overcollections for fuel and power procurement-related


26


costs in 2010 when compared to 2011 (overcollections of approximately $300 million in 2010 compared to approximately $50 million in 2011). The 2010 overcollection was primarily due to lower realized gas and power prices compared to the amounts forecasted for setting customer rates. SCE began refunding the overcollection through a rate adjustment beginning on June 1, 2011. The balancing account was over-collected by $392 million at December 31, 2011, $345 million at December 31, 2010, $46 million at December 31, 2009 and under-collected by $406 million at December 31, 2008; and
$365 million increase resulting from higher income before depreciation and income taxes primarily driven by higher customer revenue.
Net cash provided by operating activities decreased $683 million in 2010, compared to 2009. The cash flows provided by operating activities were primarily due to the following:
$531 million decrease in cash reflecting lower net tax receipts in 2010 compared to 2009 primarily related to the impacts of the Global Settlement. In 2009, SCE received tax-allocation payments of $875 million from the Global Settlement, compared to tax-allocation payments received of $26 million in 2010. This decrease was partially offset by higher estimated tax payments in 2009 compared to 2010.
$155 million net cash inflow from balancing accounts composed of:
$310 million net cash inflow from the funding of public purpose and solar initiative programs and lower pension and PBOP contributions in 2010 compared to 2009; and
$155 million net cash outflow due to the decrease in balancing account cash flows for fuel and power procurement-related costs (collections of approximately $300 million in 2010, compared to collections of approximately $450 million in 2009).
Timing of cash receipts and disbursements related to working capital items, including a net cash outflow of $95 million related to the timing of fuel and power procurement-related activities primarily related to ISO charges and a $60 million decrease in margin and collateral deposits – net of collateral received.
Net Cash Provided (Used) by Financing Activities
Cash provided (used) by financing activities mainly consisted of net repayments of short-term debt and long-term debt issuances (payments).
Net cash provided by financing activities for 2011 was $799 million consisting of the following significant events:
Issued $500 million of 3.875% first and refunding mortgage bonds due in 2021. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.
Issued a net $419 million of commercial paper supported by SCE's line of credit to fund interim working capital requirements.
Issued $250 million of 3.9% first and refunding mortgage bonds due in 2041. The proceeds from these bonds were used to fund SCE's capital program.
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.
Issued $125 million of 6.5% Series D preference stock. The proceeds from the issuance were used to fund SCE's capital program.
Paid $461 million of dividends to Edison International.
Purchased $86 million of SCE variable rate tax-exempt bonds.
Net cash provided by financing activities for 2010 was $503 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.


27


Paid $300 million in dividends to Edison International.
Net cash used by financing activities for 2009 was $2.0 billion consisting of the following significant events:
Issued $500 million of first refunding mortgage bonds due in 2039 and $250 million of first and refunding mortgage bonds due in 2014. The bond proceeds were used for general corporate purposes and to finance fuel inventories, respectively.
Repaid a net $1.9 billion of short-term debt.
Repaid $150 million of first and refunding mortgage bonds.
Purchased $219 million of two issues of tax-exempt pollution control bonds and converted the issues to a variable rate structure. As discussed above, SCE reissued $144 million of these bonds in 2010. SCE continues to hold the remaining $75 million of these bonds which are outstanding and have not been retired or cancelled.
Paid $300 million in dividends to Edison International.
Net Cash Used by Investing Activities
Cash flows from investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $4.1 billion, $3.8 billion and $3.0 billion for 2011, 2010 and 2009, respectively, primarily related to transmission, distribution and generation investments. Net purchases of nuclear decommissioning trust investments and other were $167 million, $219 million and $199 million for 2011, 2010 and 2009, respectively.
Contractual Obligations and Contingencies
Contractual Obligations
SCE's contractual obligations as of December 31, 2011, for the years 2012 through 2016 and thereafter are estimated below.
(in millions)
 
Total
 
Less than
1 year
 
1 to 3 years
 
3 to 5 years
 
More than
5 years
Long-term debt maturities and interest1
 
$
16,422

 
$
434

 
$
2,028

 
$
1,411

 
$
12,549

Power purchase agreements2:
 
 
 
 
 
 
 
 
 
 
Renewable energy contracts
 
16,578

 
561

 
1,328

 
1,503

 
13,186

Qualifying facility contracts
 
3,677

 
439

 
875

 
794

 
1,569

Other power purchase agreements
 
6,298

 
624

 
1,640

 
1,181

 
2,853

Other operating lease obligations3
 
641

 
73

 
135

 
109

 
324

Purchase obligations4:
 
 
 
 
 
 
 
 
 
 
Nuclear fuel supply contract payments
 
1,068

 
190

 
213

 
206

 
459

Other fuel supply contract payments
 
268

 
42

 
97

 
129

 

Other contractual obligations5
 
323

 
21

 
51

 
39

 
212

Employee benefit plans contributions6
 
1,528

 
325

 
635

 
568

 

Total7,8
 
$
46,803

 
$
2,709

 
$
7,002

 
$
5,940

 
$
31,152

1 
For additional details, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." Amount includes interest payments totaling $8.0 billion over applicable period of the debt.
2 
Certain power purchase agreements entered into with independent power producers are treated as operating or capital leases. At December 31, 2011, minimum operating lease payments for power purchase agreements were $839 million in 2012, $966 million in 2013, $930 million in 2014, $916 million in 2015, $815 million in 2016, and $11.5 billion for the thereafter period. At December 31, 2011, minimum capital lease payments for power purchase agreements were $33 million in 2012, $33 million 2013, $72 million for 2014, $109 million for 2015, $109 million for 2016, and $1.8 billion for the thereafter period (amounts include executory costs and interest of $445 million and $773 million, respectively). For further discussion, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."


28


3 
At December 31, 2011, minimum other operating lease payments were primarily related to vehicles, office space and other equipment. For further discussion, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
4 
For additional details, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
5 
At December 31, 2011, other commitments were primarily related to maintaining reliability and expanding SCE's transmission and distribution system.
6 
Amount includes estimated contributions to the pension and PBOP plans. The estimated contributions for SCE are not available beyond 2016. These amounts represent estimates that are based on assumptions that are subject to change. In addition, funding of future contributions could be impacted by the final 2012 GRC decision. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 8. Compensation and Benefit Plans" for further information.
7 
At December 31, 2011, SCE had a total net liability recorded for uncertain tax positions of $258 million, which is excluded from the table. SCE cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing of resolving these open tax issues with the IRS.
8 
The contractual obligations table does not include derivative obligations and asset retirement obligations, which are discussed in "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities," and "Item 8. SCE Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment," respectively.
Contingencies
SCE has contingencies related to the CPSD Investigations, Four Corners New Source Review litigation, nuclear insurance, wildfire insurance and spent nuclear fuel, which are discussed in "Item 8. SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
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 probable amount, SCE records the lower end of this reasonably likely range of costs (classified as "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.
As of December 31, 2011, SCE had identified 24 material sites for remediation and recorded an estimated minimum liability of $49 million. SCE expects to recover 90% of its remediation costs at certain sites. See "Item 8. 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. Derivative instruments are used, as appropriate, to manage market risks for customers and SCE. For a further discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities" and "Note 4. Fair Value Measurements."
Interest Rate Risk
SCE is exposed to changes in interest rates primarily as a result of its financing and short-term investing activities used for liquidity purposes, to fund business operations and to fund capital investments. The nature and amount of SCE's long-term and short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors. Changes in interest rates may impact SCE's authorized rate of return for the period beyond 2012, see "Item 1. Business—Overview of Ratemaking Process—CPUC" for further discussion.
At December 31, 2011, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $10.1 billion, compared to a carrying value of $8.4 billion. A 10% increase in market interest rates would have resulted in a


29


$399 million decrease in the fair market value of SCE's long-term debt. A 10% decrease in market interest rates would have resulted in a $430 million increase in the fair market value of SCE's long-term debt.
Commodity Price Risk
SCE and its customers are exposed to the risk of a change in the market price of natural gas and electric power. SCE's hedging program reduces exposure to variability in market prices related to SCE's purchases and sales of electric power and natural gas. SCE expects recovery of its related hedging costs through the ERRA balancing account or CPUC-approved procurement plans, and as a result, exposure to commodity price is not expected to impact earnings, but may impact the timing of cash flows. SCE's hedging program reduces customer exposure to variability in market prices. As part of this program, SCE enters into energy options, swaps, forward arrangements, tolling arrangements, and congestion revenue rights ("CRRs"). The transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans. For further discussion on derivative instruments entered into to mitigate commodity price exposures, see "Item 8. SCE Notes to Consolidated Financial StatementsNote 6. Derivative Instruments and Hedging Activities."
Fair Value of Derivative Instruments
With some exceptions, SCE records derivative instruments on its consolidated balance sheets at fair value. Changes in the fair value of derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms and, therefore, SCE's fair value changes have no impact on earnings. SCE does not use hedge accounting for these transactions due to this regulatory accounting treatment. For further discussion on fair value measurements and the fair value hierarchy, see "Item 8. SCE Notes to Consolidated Financial StatementsNote 4. Fair Value Measurements."
The fair value of outstanding derivative instruments used at SCE to mitigate its exposure to commodity price risk was a net liability of $936 million and $207 million at December 31, 2011 and 2010, respectively. The increase in the net liability was related to changes in unrealized losses on economic hedging activities primarily due to declining power and natural gas prices. The following table summarizes the increase or decrease to the fair values of outstanding derivative instruments as of December 31, 2011, if the electricity prices or gas prices were changed while leaving all other assumptions constant:
(in millions)
December 31, 2011
Increase in electricity prices by 10%
$
266

Decrease in electricity prices by 10%
(581
)
Increase in gas prices by 10%
(340
)
Decrease in gas prices by 10%
(7
)
Credit Risk
For information related to credit risks and how SCE manages credit risk, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."
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 arrangements. 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 arrangements, including master netting agreements.


30


As of December 31, 2011, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:
 
December 31, 2011
(in millions)
Exposure2
 
Collateral
 
Net Exposure
S&P Credit Rating1
 
 
 
 
 
A or higher
$
122

 
$

 
$
122

Not rated3
11

 
(3
)
 
8

Total
$
133

 
$
(3
)
 
$
130

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.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
The accounting policies described below are considered critical to obtaining an understanding of SCE's consolidated financial statements because their application requires the use of significant estimates and judgments by management in preparing the consolidated financial statements. Management estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the estimate requires significant assumptions and changes in the estimate or the use of alternative estimates that could have a material impact on SCE's results of operations or financial position. For more information on SCE's accounting policies, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."
Rate Regulated Enterprises
Nature of Estimate Required.    SCE follows the accounting principles for rate-regulated enterprises which are required for entities whose rates are set by regulators at levels intended to recover the estimated costs of providing service, plus a return on net investment, or rate base. Regulators may also impose certain penalties or grant certain incentives. Due to timing and other differences in the collection of revenue, these principles allow a cost that would otherwise be charged as an expense by a unregulated entity to be capitalized as a regulatory asset if it is probable that such cost is recoverable through future rates; conversely the principles allow creation of a regulatory liability for amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred.
Key Assumptions and Approach Used.    SCE's management assesses at the end of each reporting period whether regulatory assets are probable of future recovery by considering factors such as the current regulatory environment, the issuance of rate orders on recovery of the specific or a similar incurred cost to SCE or other rate-regulated entities in California, and other factors that would indicate that the regulator will treat an incurred cost as allowable for ratemaking purposes. Using these factors, management has determined that existing regulatory assets and liabilities are probable of future recovery or settlement. This determination reflects the current regulatory climate in California and is subject to change in the future.
Effect if Different Assumption Used.    Significant management judgment is required to evaluate the anticipated recovery of regulatory assets, the recognition of incentives and revenue subject to refund, as well as the anticipated cost of regulatory liabilities or penalties. If future recovery of costs ceases to be probable, all or part of the regulatory assets and liabilities would have to be written off against current period earnings. At December 31, 2011, the consolidated balance sheets included regulatory assets of $6.3 billion and regulatory liabilities of $5.3 billion. If different judgments were reached on recovery of costs and timing of income recognition, SCE's earnings may vary from the amounts reported.
Nuclear Decommissioning – ARO
Nature of Estimate Required.    Regulations by the NRC require SCE to decommission its nuclear power plants which is expected to begin after the plants' operating licenses expire. In accordance with authoritative guidance, SCE is required to record an obligation to decommission its nuclear facilities. Nuclear decommissioning costs are recovered in utility rates


31


through contributions that are reviewed every three years by the CPUC. Due to regulatory accounting treatment, nuclear decommissioning activities are not expected to affect SCE earnings.
Key Assumptions and Approach Used.    The liability to decommission SCE's nuclear power facilities is based on site-specific studies performed in 2008 and 2007 for San Onofre and Palo Verde, respectively, which estimate that SCE will spend approximately $8.6 billion through 2053 to decommission its active nuclear facilities. Decommissioning cost estimates are updated in each Nuclear Decommissioning Triennial Proceeding. The current estimate is based on the following assumptions from the 2008 and 2007 site-specific studies:
Decommissioning Costs. The estimated costs for labor, dismantling and disposal costs, energy and miscellaneous costs.
Escalation Rates. Annual escalation rates are used to convert the decommissioning cost estimates in base year dollars to decommissioning cost estimates in future-year dollars. Escalation rates are primarily used for labor, material, equipment, and low level radioactive waste burial costs. SCE's current estimate is based on SCE's decommissioning cost methodology used for ratemaking purposes, escalated at rates ranging from 1.8% to 6.9% (depending on the cost element) annually.
Timing. Cost estimates are based on an assumption that decommissioning will commence promptly after the NRC operating licenses expire. The operating licenses currently expire in 2022 for San Onofre Units 2 and 3. When the site-specific study was completed, the licenses for the Palo Verde units were set to expire in 2025, 2026 and 2027. Effective April 2011, the licenses were extended to 2045, 2046 and 2047 for the Palo Verde units.
Spent Fuel Dry Storage Costs. Cost estimates are based on an assumption that the DOE will begin to take spent fuel in 2015, and will remove the last spent fuel from the San Onofre and Palo Verde sites by 2051 and 2053, respectively. Costs for spent fuel monitoring are included until 2051 and 2053, respectively.
Changes in decommissioning technology, regulation, and economics. The current cost studies assume the use of current technologies under current regulations and at current cost levels.
Effect if Different Assumptions Used.    The ARO for decommissioning SCE's active nuclear facilities was $2.5 billion and $2.4 billion at December 31, 2011 and 2010, respectively. Changes in the estimated costs or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission these facilities which could have a material effect on the recorded liability and related regulatory asset. The following table illustrates the increase to the ARO and regulatory asset if the escalation rate was adjusted while leaving all other assumptions constant:
(in millions)
Increase to
ARO and regulatory
asset at
December 31, 2011
Uniform increase in escalation rate of 25 basis points
$
146

Pensions and Postretirement Benefits Other than Pensions
Nature of Estimate Required.    Authoritative accounting guidance requires companies to recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets and liabilities in the balance sheet; the assets and/or liabilities are normally offset through other comprehensive income (loss). In accordance with authoritative guidance for rate-regulated enterprises, regulatory assets and liabilities are recorded instead of charges and credits to other comprehensive income (loss) for its postretirement benefit plans that are recoverable in utility rates. SCE has a fiscal year-end measurement date for all of its postretirement plans.
Key Assumptions of Approach Used.    Pension and other postretirement obligations and the related effects on results of operations are calculated using actuarial models. Two critical assumptions, discount rate and expected return on assets, are important elements of plan expense and liability measurement. Additionally, health care cost trend rates are critical assumptions for postretirement health care plans. These critical assumptions are evaluated at least annually. Other assumptions, which require management judgment, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.
As of December 31, 2011, SCE's pension plans had a $4.1 billion benefit obligation and total expense for these plans was $113 million for 2011. As of December 31, 2011, SCE's PBOP plans had a $2.4 billion benefit obligation and total expense for these plans was $34 million for 2011. Annual contributions made to most of SCE's pension plans are currently recovered


32


through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the related annual expense.
The following are critical assumptions used to determine expense for pension and other postretirement benefit for 2011:
(in millions)
Pension
Plans
Postretirement
Benefits Other
than Pensions
Discount rate1
5.25%
5.50%
Expected long-term return on plan assets2
7.5%
7.0%
Assumed health care cost trend rates3
9.75%
1 
The discount rate enables SCE to state expected future cash flows at a present value on the measurement date. SCE selects its discount rate by performing a yield curve analysis. This analysis determines the equivalent discount rate on projected cash flows, matching the timing and amount of expected benefit payments. Two corporate yield curves were considered, Citigroup and AON-Hewitt.
2 
To determine the expected long-term rate of return on pension plan assets, current and expected asset allocations are considered, as well as historical and expected returns on plan assets. A portion of PBOP trusts asset returns are subject to taxation, so the 7.5% rate of return on plan assets above is determined on an after-tax basis. Actual time-weighted, annualized returns on the pension plan assets were 2.2%, 2.0% and 5.9% for the one-year, five-year and ten-year periods ended December 31, 2011, respectively. Actual time-weighted, annualized returns on the PBOP plan assets were 1.2%, 0.8%, and 4.2% over these same periods. Accounting principles provide that differences between expected and actual returns are recognized over the average future service of employees.
3 
The health care cost trend rate gradually declines to 5.5% for 2019 and beyond.
Pension expense is recorded for SCE based on the amount funded to the trusts, as calculated using an actuarial method required for ratemaking purposes, in which the impact of market volatility on plan assets is recognized in earnings on a more gradual basis. Any difference between pension expense calculated in accordance with ratemaking methods and pension expense calculated in accordance with authoritative accounting guidance for pension is accumulated as a regulatory asset or liability, and will, over time, be recovered from or returned to customers. As of December 31, 2011, this cumulative difference amounted to a regulatory asset of $105 million, meaning that the accounting method has recognized more in expense than the ratemaking method since implementation of authoritative guidance for employers' accounting for pensions in 1987.
As of December 31, 2011, SCE had unrecognized pension costs of $1.03 billion and unrecognized PBOP costs of $714 million which primarily consisted of the cumulative impact of the reduced discount rates on the respective benefit obligations and the cumulative difference between the expected and actual rate of return on plan assets. Of these deferred costs, $989 million of pension costs and $714 million of PBOP costs are recorded as regulatory assets, an offset to the underfunded liabilities of these plans, and will be amortized to expense over the average expected future service of employees.
SCE's pension and PBOP plans are subject to limits established for federal tax deductibility. SCE funds its pension and PBOP plans in accordance with amounts allowed by the CPUC. Executive pension plans and PBOP plans have no plan assets.
Effect if Different Assumptions Used.    Changes in the estimated costs or timing of pension and other postretirement benefit obligations, or the assumptions and judgments used by management underlying these estimates, could have a material effect on the recorded expenses and liabilities. Earnings could be impacted if the CPUC eliminates or modifies the current approved regulatory recovery mechanism.
The following table summarizes the increase or (decrease) to the projected benefit obligation for pension and the accumulated benefit obligation for PBOP if the discount rate were changed while leaving all other assumptions constant:
(in millions)
Increase in discount rate by 1%
 
Decrease in discount rate by 1%
Change to projected benefit obligation for pension
$
(360
)
 
$
388

Change to accumulated benefit obligation for PBOP
(319
)
 
370



33


A one percentage point increase in the expected rate of return on pension plan assets would decrease current year expense by $30 million and a one percentage point increase in the expected rate of return on PBOP plan assets would decrease current year expense by $16 million.
The following table summarizes the increase or (decrease) to the accumulated benefit obligation and annual aggregate service and interest costs for PBOP if the health care cost trend rate was changed while leaving all other assumptions constant:
(in millions)
Increase in health care cost trend rate by 1%
 
Decrease in health care cost trend rate by 1%
Change to accumulated benefit obligation for PBOP
$
273

 
$
(227
)
Change to annual aggregate service and interest costs
14

 
(12
)
Income Taxes
Nature of Estimates Required.    As part of the process of preparing its consolidated financial statements, SCE is required to estimate its income taxes for each jurisdiction in which it operates. This process involves estimating actual current period tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within SCE's consolidated balance sheets.
SCE takes certain tax positions it believes are applied in accordance with the applicable tax laws. However, these tax positions are subject to interpretation by the IRS, state tax authorities and the courts. SCE determines its uncertain tax positions in accordance with the authoritative guidance.
Key Assumptions and Approach Used.    Accounting for tax obligations requires management judgment. Management uses judgment in determining whether the evidence indicates it is more likely than not, based solely on the technical merits, that a tax position will be sustained, and to determine the amount of tax benefits to be recognized. Judgment is also used in determining the likelihood a tax position will be settled and possible settlement outcomes. In assessing its uncertain tax positions SCE considers, among others, the following factors: the facts and circumstances of the position, regulations, rulings, and case law, opinions or views of legal counsel and other advisers, and the experience gained from similar tax positions. Management evaluates uncertain tax positions at the end of each reporting period and makes adjustments when warranted based on changes in fact or law.
Effect if Different Assumptions Used.    Actual income taxes may differ from the estimated amounts which could have a significant impact on the liabilities, revenue and expenses recorded in the financial statements. SCE continues to be under audit or subject to audit for multiple years in various jurisdictions. Significant judgment is required to determine the tax treatment of particular tax positions that involve interpretations of complex tax laws. A tax liability has been recorded with respect to tax positions in which the outcome is uncertain and the effect is estimable. Such liabilities are based on judgment and a final determination could take many years from the time the liability is recorded. Furthermore, settlement of tax positions included in open tax years may be resolved by compromises of tax positions based on current factors and business considerations that may result in material adjustments to income taxes previously estimated. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 7. Income Taxes" for a further discussion on income taxes.
Accounting for Contingencies, Guarantees and Indemnities
Nature of Estimates Required.    SCE records loss contingencies when it determines that the outcome of future events is probable of occurring and when the amount of the loss can be reasonably estimated. When a guarantee or indemnification subject to authoritative guidance is entered into, SCE records a liability for the estimated fair value of the underlying guarantee or indemnification. Gain contingencies are recognized in the financial statements when they are realized.
Key Assumptions and Approach Used.    The determination of a reserve for a loss contingency is based on management judgment and estimates with respect to the likely outcome of the matter, including the analysis of different scenarios. Liabilities are recorded or adjusted when events or circumstances cause these judgments or estimates to change. In assessing whether a loss is a reasonable possibility, SCE may consider the following factors, among others: the nature of the litigation, claim or assessment, available information, opinions or views of legal counsel and other advisors, and the experience gained from similar cases. SCE provides disclosures for material contingencies when there is a reasonable possibility that a loss or an additional loss may be incurred. Some guarantees and indemnifications could have a significant financial impact under certain circumstances, and management also considers the probability of such circumstances occurring when estimating the fair value.


34


Effect if Different Assumptions Used.    Actual amounts realized upon settlement of contingencies may be different than amounts recorded and disclosed and could have a significant impact on the liabilities, revenue and expenses recorded on the consolidated financial statements. In addition, for guarantees and indemnities actual results may differ from the amounts recorded and disclosed and could have a significant impact on SCE's consolidated financial statements. For a discussion of contingencies, guarantees and indemnities, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
NEW ACCOUNTING GUIDANCE
New accounting guidance is discussed in "Item 8. SCE Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."
ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Information responding to Item 7A is included in the MD&A under the heading "Market Risk Exposures."
ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONSOLIDATED FINANCIAL STATEMENTS


35


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Shareholder of Southern California Edison Company
In our opinion, the consolidated balance sheets and the related consolidated statements of income, comprehensive income, cash flows and changes in equity present fairly, in all material respects, the financial position of Southern California Edison Company (the "Company") and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for variable interest entities as of January 1, 2010.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 29, 2012


36


Consolidated Statements of Income
Southern California Edison Company
 
 
Years ended December 31,
(in millions)
 
2011
 
2010
 
2009
Operating revenue
 
$
10,577

 
$
9,983

 
$
9,965

Fuel
 
367

 
363

 
721

Purchased power
 
2,989

 
2,930

 
2,751

Operation and maintenance
 
3,387

 
3,291

 
3,154

Depreciation, decommissioning and amortization
 
1,426

 
1,273

 
1,178

Property and other taxes
 
285

 
263

 
244

Gain on sale of assets
 

 
(1
)
 
(1
)
Total operating expenses
 
8,454

 
8,119

 
8,047

Operating income
 
2,123

 
1,864

 
1,918

Interest income
 
5

 
7

 
11

Other income
 
135

 
141

 
160

Interest expense
 
(463
)
 
(429
)
 
(420
)
Other expenses
 
(55
)
 
(51
)
 
(49
)
Income before income taxes
 
1,745

 
1,532

 
1,620

Income tax expense
 
601

 
440

 
249

Net income
 
1,144

 
1,092

 
1,371

Less:  Net income attributable to noncontrolling interests
 

 

 
94

Dividends on preferred and preference stock
 
59

 
52

 
51

Net income available for common stock
 
$
1,085

 
$
1,040

 
$
1,226

Consolidated Statements of Comprehensive Income
 
 
 
 
 
Years ended December 31,
(in millions)
 
2011
 
2010
 
2009
Net income
 
$
1,144

 
$
1,092

 
$
1,371

Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
Pension and postretirement benefits other than pensions:
 
 
 
 
 
 
Net loss arising during period, net of income tax benefit of $2, $6 and $5 for 2011, 2010 and 2009 respectively
 
(3
)
 
(9
)
 
(7
)
Amortization of net loss included in net income, net of income tax expense of $2, $2 and $1 for 2011, 2010 and 2009 respectively
 
4

 
3

 
2

Comprehensive income
 
1,145

 
1,086

 
1,366

Less: Comprehensive income attributable to noncontrolling interests
 

 

 
94

Comprehensive income attributable to SCE
 
$
1,145

 
$
1,086

 
$
1,272


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

37


Consolidated Balance Sheets
Southern California Edison Company
 
 
December 31,
(in millions)
 
2011
 
2010
ASSETS
 
 
 
 
Cash and cash equivalents
 
$
57

 
$
257

Receivables, less allowances of $75 and $85 for uncollectible accounts at respective dates
 
760

 
715

Accrued unbilled revenue
 
519

 
442

Inventory
 
350

 
332

Prepaid taxes
 
278

 
168

Derivative assets
 
65

 
87

Regulatory assets
 
494

 
378

Other current assets
 
89

 
81

Total current assets
 
2,612

 
2,460

Nuclear decommissioning trusts
 
3,592

 
3,480

Other investments
 
93

 
68

Total investments
 
3,685

 
3,548

Utility property, plant and equipment, less accumulated depreciation of $6,894 and $6,319 at respective dates
 
27,569

 
24,778

Nonutility property, plant and equipment, less accumulated depreciation of $107 and $100 at respective dates
 
73

 
71

Total property, plant and equipment
 
27,642

 
24,849

Derivative assets
 
70

 
367

Regulatory assets
 
5,815

 
4,347

Other long-term assets
 
491

 
335

Total long-term assets
 
6,376

 
5,049

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
40,315

 
$
35,906


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

38


Consolidated Balance Sheets
Southern California Edison Company
 
 
December 31,
(in millions, except share amounts)
 
2011
 
2010
LIABILITIES AND EQUITY
 
 
 
 
Short-term debt
 
$
419

 
$

Accounts payable
 
1,319

 
1,271

Accrued taxes
 
49

 
45

Accrued interest
 
167

 
169

Customer deposits
 
199

 
217

Derivative liabilities
 
266

 
212

Regulatory liabilities
 
670

 
738

Other current liabilities
 
759

 
663

Total current liabilities
 
3,848

 
3,315

Long-term debt
 
8,431

 
7,627

Deferred income taxes
 
5,781

 
4,829

Deferred investment tax credits
 
84

 
118

Customer advances
 
138

 
112

Derivative liabilities
 
805

 
449

Pensions and benefits
 
2,461

 
1,838

Asset retirement obligations
 
2,610

 
2,507

Regulatory liabilities
 
4,670

 
4,524

Other deferred credits and other long-term liabilities
 
1,529

 
1,380

Total deferred credits and other liabilities
 
18,078

 
15,757

Total liabilities
 
30,357

 
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
 
596

 
572

Accumulated other comprehensive loss
 
(24
)
 
(25
)
Retained earnings
 
6,173

 
5,572

Total common shareholder's equity
 
8,913

 
8,287