UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Edison International        Yes ¨o No þ    Southern California Edison Company        Yes ¨o No þ

DOCUMENTS INCORPORATED BY REFERENCE

PortionsDesignated portions of the following documents listed belowProxy Statement relating to registrants' joint 2015 Annual Meeting of Shareholders have been incorporated by reference into the parts of this report sowhere indicated.

This is a combined Form 10-K separately filed by Edison International and Southern California Edison Company. Information contained herein relating to an individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.

GLOSSARY

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 Edison International's and SCE's current expectations and projections about future events based on Edison International's and 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 Edison International and 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 Edison International and SCE, include, but are not limited to:to the:

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 Edison International, SCE or their 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 Edison International's and SCE's businesses. Forward-looking statements speak only as of the date they are made and neither Edison International nor SCE are obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International and SCE with the SEC.

Except when otherwise stated, references to each of Edison International, SCE, Edison Energy, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to "Edison International Parent and Other" mean Edison International Parent and its consolidated non-utility subsidiaries.

Edison Capital holds energy and infrastructure investmentsInternational's earnings are prepared in the form of leveraged leases and partnership interests in affordable housing projectsaccordance with GAAP used in the United States.

SCE's 2014 core earnings increased $260 million for the year primarily due to hold equity interestshigher authorized revenues from rate base growth, higher income tax benefits and engagelower severance costs. In the fourth quarter of 2014, the CPUC authorized an increase in businessesSCE's revenue of $30 million ($18 million after-tax) due to a revised determination of rate base for deferred income taxes. Included in emerging sectors2014 results is $19 million ($11 million after-tax) from a change in estimate of the electricity industry. To date, the holdingsrevenue under its FERC formula rate and $15 million ($9 million after-tax) of these subsidiaries are not material for financial reporting purposes. In August 2013, Edison International acquired SoCore Energy, LLC, a distributed solar developer focused on commercial rooftop installations.

Multiple factors are converging to putThe electricity industry is undergoing extensive change, including technological advancements such as customer-owned generation, energy storage and customer-owned generation that may change the nature of energy generation and delivery. Recent trends in the electric power industry on the cusp of significant change. These factors include:

The electric distribution grid is an important component of California's public policy goals to support a cleaner environment. These policy goals continue to advance as California moves forward in implementing AB 32, the California Global Warming Solutions Act of 2006. AB 32 established a comprehensive program to reduce GHG emissions and required regulations that would reduce California's GHG emissions to 1990 levels by 2020. California law currently requires retail sellers of electricity to procure 33% of their customers' electricity requirements from renewable resources. The Governor of California has been addressingproposed the next set of objectives for 2030 and beyond, which include increasing from 33% to 50% the electricity derived from renewable resources. Also included is a targeted 50% reduction of petroleum use in mobile vehicles, which may result in growth in electric vehicles and investment in charging infrastructure. California’s policy goals in these changesareas may create opportunities for the electric grid to enable GHG emission reductions by focusingproviding the supporting infrastructure to increase adoption of customer-owned generation, electric storage, and electric vehicles but they may increase customer rates and add technical complexity and risk to the safe and reliable operation of the electric grid.

Having considered these trends, SCE onis investing in and strengthening its electric grid and driving operational and service excellence to improve system safety, reliability and service while controlling costs and rates. Simultaneously, Edison International is investing, at much more modest levels, in Competitive Businesses to meetlargely evaluate the attractiveness of new business models and potential competitive threats to the traditional utility business model.

The distribution grid needs investment to support two-way flows of electricity needs of commercialcreated by customer-owned generation as well as new technologies such as electric vehicles and industrial customers both insideenergy storage and beyond SCE's service area. Edison International continuesis critical to see meritimplementing California's public policy goals, including those to reduce GHG emissions. SCE is engaged in initiatives that are not currently addressed in the ownershipGRC, including preparing a Distribution Resources Plan and operationparticipating in the Charge Ready Program.

AB 327 requires SCE and other California investor-owned utilities to submit a proposed Distribution Resources Plan by July 1, 2015. The goal of Competitive Businessesthe Distribution Resources Plan is to facilitate the integration of distributed energy resources at optimal locations in a manner that minimizes overall system costs and maximizes customer benefits from these investments, while at the same time maintaining system safety and reliability. To accomplish this, the plan must evaluate locational benefits and costs of distributed resources located on the distribution system based upon reductions or increases in local generation capacity needs, avoided or increased investments in distribution infrastructure, safety benefits, reliability benefits, and any other savings distributed resources provide to the electric grid or costs to customers.

The program proposes to begin with a $22 million pilot for installation of up to 1,500 chargers as well as a mattersupporting market education effort. The results of corporate strategythis first phase will help shape Phase 2 of the program, which is expected to cost an additional $333 million over the next five years. SCE requested CPUC approval for its pilot by June 2015, and is exploring business venturesfor Phase 2 by June 2016.

The CPUC issued a decision in December 2014 that reversed a number of areas related to the provisionprior prohibition on utility ownership of electric powervehicle infrastructure and infrastructure, including distributed generation, electrification of transportation, water purification, and power management services to the commercial and industrial sector.implemented a case-by-case evaluation requirement for proposed utility investments in electric vehicle infrastructure.

Edison InternationalTotal capital expenditures (including accruals) were $4.0 billion in 2014 and its subsidiaries are subject to extensive regulation. As a public utility holding company, Edison International is subject to the Public Utility Holding Company Act. The Public Utility Holding Company Act primarily obligates Edison International and its utility subsidiaries to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.

Edison International maintains a propertySCE forecasts capital expenditures in the range of $11.8 billion to $13.4 billion for 2015 – 2017. Actual capital spending will be affected by: changes in regulatory, environmental and casualty insurance program for itselfengineering design requirements; permitting and its subsidiariesproject delays; cost and excess liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations.availability of labor, equipment and materials; and other factors. These policiesfactors as well as major projects are subject to specific retentions, sub-limitsdiscussed further under "—Liquidity and deductibles, which are comparable to those carried by other utility companies of similar size. SCE also has separate insurance programs for nuclear property and liability, workers compensation and solar rooftop construction. For further information on nuclear and wildfire insurance, see "Item 8. Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies.Capital Resources—SCE—Capital Investment Plan."

A final 2015 GRC decision is not expected until later in 2015. SCE expects to recognize revenue based on the 2014 authorized revenue requirement until a GRC decision is issued. The CPUC has approved the authority to regulate, among other things, retail rates, energy purchasesestablishment of a GRC memorandum account, which will make the 2015 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2015. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or provide assurance on behalfthe timing of retail customers, SCE capital structure, ratea final decision.

In December 2014, the CPUC granted a one-year extension of the transmission system planning, site identification and construction.

The NRC has jurisdiction with respectcost of capital trigger mechanism provides for an automatic annual adjustment to SCE's authorized cost of capital in September if the utility bond index changes beyond certain thresholds. The adjustment would apply to the safetyfollowing calendar year. The return on common equity will remain at 10.45% for 2015 and 2016, subject to any index changes that exceed the thresholds for 2016.

In December 2014, Edison International declared a 17.6% increase to the annual dividend rate from $1.42 per share to $1.67 per share. Edison International plans to increase its dividends to common shareholders to its target payout ratio of theapproximately 45% to 55% of SCE earnings in steps over time.

Replacement steam generators were installed at San Onofre in 2010 and 2011. On January 31, 2012, a leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. The NRC regulates commercial nuclear power plants through licensing, oversightUnit was safely taken off-line and inspection, performance assessment, and enforcementsubsequent inspections revealed excessive tube wear. Unit 2 was off-line for a planned outage when areas of its requirements. Inunexpected tube wear were also discovered. On June 6, 2013, SCE decided to permanently retire and decommission Units 2 and 3.

On November 20, 2014, the CPUC approved the Amended and Restated Settlement Agreement (the "San Onofre OII Settlement Agreement") that SCE had entered into with TURN, the ORA, SDG&E, the Coalition of California Utility Employees, and Friends of the Earth (together, the "Settling Parties"). The San Onofre OII Settlement Agreement resolved the CPUC's OII and related proceedings regarding the Steam Generator Replacement Project at San Onofre and the related outage and subsequent shutdown of San Onofre. The San Onofre OII Settlement Agreement does not affect proceedings related to recoveries from third parties described below, but does describe how shareholders and customers will share any

The decommissioning of a nuclear plant requires the management of three related activities: radiological decommissioning, non-radiological decommissioning and the management of spent nuclear fuel. The decommissioning process is expected to take many years. In June 2013, SCE began the initial activity phase of radiological decommissioning by filing with the NRC a certification of permanent cessation of power operations at San Onofre. Notifications of permanent removal of fuel from the reactor vessels were provided in June and July 2013 for Units 3 and 2, respectively. On September 23, 2014, SCE submitted its Post-Shutdown Decommissioning Activities Report ("PSDAR"), Irradiated Fuel Management Plan and Decommissioning Cost Estimate for San Onofre, Units 2 and 3 to the NRC. These submittals were subject to a ninety-day period for NRC review and acceptance, which expired on December 27, 2014. SCE is now permitted to start major radiological decommissioning activities pursuant to NRC regulations, provided SCE obtains all necessary environmental permits for decommissioning. During the second quarter of 2014, SCE updated its decommissioning cost estimate based on a site specific assessment. The decommissioning cost estimate in 2014 dollars is $4.4 billion (SCE share – $3.3 billion) and includes costs from June 7, 2013 through to the respective completion dates to decommission San Onofre Units 2 and 3 estimated to be in 2052. The decommissioning cost estimate is subject to a number of estimates including the cost of burial of nuclear waste, cost of removal of property, site remediation costs as well as a number of other assumptions and estimates, including when the federal government may remove spent fuel canisters from the San Onofre site, as to which there can be no assurance. The cost estimate is subject to change and such changes may be material. SCE's share of the present value of decommissioning costs using current discount rates was $3.0 billion at December 31, 2014. For further information, see "Management Overview—Permanent"Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Asset Retirement ofObligation."

SCE has nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $3.4 billion as of December 31, 2014. If the decommissioning cost estimate and assumptions regarding trust performance do not change, SCE believes that future contributions to the trust funds will not be necessary. The CPUC must issue an order granting prior approval for withdrawal of decommissioning trust funds. SCE has filed a request with the CPUC to authorize release of trust funds for costs up to a specified cost cap of $214 million to cover SCE's share of 2013 decommissioning costs. The request also seeks CPUC approval for a process by which SCE will be able to seek the release of trust funds to cover decommissioning costs incurred in 2014 and future periods until the CPUC approves a permanent San Onofre decommissioning plan and cost recovery mechanism.

Depending on the ultimate interpretation of IRS regulations, which address the taxation of a qualified nuclear decommissioning trust, SCE may be restricted from withdrawing amounts from the qualified decommissioning trusts to pay for independent spent fuel storage installation ("ISFSI") where SCE is seeking, or plans to seek, recovery of the ISFSI costs in litigation against the DOE. For further information, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—Spent Nuclear Fuel." SCE intends to participate as part of an industry coalition in working with the MD&A.IRS and the Department of Treasury to pursue an interpretation of the IRS regulations that is consistent with Congress’ intent when this tax provision was enacted by Congress in 1984. If SCE is unable to obtain timely reimbursement of such costs, it may delay decommissioning activities. Furthermore, expenditures incurred are expected to be funded by SCE until such time as a favorable determination is made or the DOE litigation for such period is resolved. For further information, see "Risk Factors—Risk Factors Relating to SCE—Operating Risks."

SCE's results of Ratemaking Processoperations are derived mainly through two sources:

Utility cost-recovery activities were primarily affected by SCE's authorized CPUC rate base. In the GRC proceedings, the CPUC also generally approves the levelfollowing:

SCE's 2012retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $12.2 billion for 2014, $11.6 billion for 2013 and $11.2 billion for 2012.

The CPUC regulates SCE's cost2013 revenue reflects:

As a result of the CPUC-authorized decoupling mechanism, SCE setsearnings are not affected by changes in retail electricity sales (see "Business—SCE—Overview of Ratemaking Process").

SCE’s income tax provision increased by $195 million in 2014 compared to 2013. The effective tax rates were 23.2% and 21.8% for 2014 and 2013, respectively. The effective tax rate increase in 2014 was primarily due to higher state income taxes.

SCE's ability to operate its business, fund capital expenditures, and implement its business strategy is 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 obligations, dividend payments to Edison International, and the outcome of tax and regulatory matters.

The Tax Increase Prevention Act of 2014 extended 50% bonus depreciation for qualifying property retroactive to January 1, 2014 and through 2015 for certain long production period property. This extension is expected to benefit cash flow in 2015 as SCE utilizes net operating losses to reduce tax liabilities. The impact on cash flow represents an annual forecastacceleration of tax benefits that would have otherwise been deductible over the life of the qualifying assets.

At December 31, 2014, SCE had $2.27 billion available under its $2.75 billion credit facility, for further details see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." SCE may finance unrecovered power procurement-related costs that it expectsas well as other balancing account undercollections and working capital requirements to incursupport operations and capital expenditures with commercial paper or other borrowings, subject to availability in the capital markets.

A summary of SCE's large transmission and substation projects during the subsequent year.next three years is presented below:

The maximum cost estimate used by the CPUC to determine public need for segments 4-11 was established in 2009 at $1.5 billion in 2009 dollars, which was lower than SCE’s requested cost estimate of $1.7 billion (cost estimates made in Tehachapi regulatory filings are in constant dollars in the year of the filing and include direct expenditures and corporate overhead costs). Subsequently, the estimated costs of the project increased due to a number of factors, including engineering scope/design changes, licensing delays, added environmental mitigation and compliance costs, and added construction costs. In addition, the CPUC has establishedordered SCE to underground a "trigger" mechanism3.5-mile portion of the line that traverses Chino Hills; setting a

maximum cost estimate in 2013 of $224 million for the ERRA balancing accountunderground portion. The cost estimate that allowsSCE had proposed in 2013 for the underground portion of the Tehachapi Project was $372 million. Separately, during 2013, the CPUC ordered SCE to implement FAA-related scope changes, such as aviation marking and lighting. Including the underground portion of the line, the CPUC has acknowledged a total maximum cost estimate to determine public need in 2013 of as much as $2.2 billion to $2.3 billion. Because SCE has not completed final engineering on all aspects of segments 4-11, SCE has not yet filed a petition for modification with the CPUC for the current 2014 cost estimate of $2.7 billion. Opposition in other communities affected by the project could potentially cause further delays and additional costs. Cost recovery for the project is subject to FERC review and approval.

The Coolwater-Lugo Project will provide additional 220 kV transmission capacity needed in the Kramer Junction and Lucerne Valley areas of San Bernardino County to alleviate an existing bottleneck in order to facilitate interconnection of current and future renewable generation projects. The Coolwater-Lugo scope primarily consists of installing new transmission lines and new substation facilities. The operator of the Coolwater Generating Station has informed the CPUC of its intent to permanently retire the station. Under the CAISO's tariff, the operator will retain deliverability priority to the existing line for a rate adjustment ifperiod of at least three years, absent the balancing account over-commitment by the operator not to repower or under-collection exceeds 5% of SCE's prior year's revenue that is classified as generation for retail rates. For 2014,restart the trigger amount is approximately $289 million. At December 31, 2013, SCE's undercollection instation. SCE believes it would be premature to delay licensing. However should the ERRA balancing account was approximately $1 billion, dueoperator commit to delays in regulatory decisions andnot repower or restart the deferral of San Onofre costs tostation, the OII proceeding. For further informationcapacity on the status of the ERRA undercollection, see "Management Overview—ERRA Balancing Account" in the MD&A.

SCE no longer has a federally-based right to construct certain of the new transmission facilities in its service territory and SCE's power procurement contract administration activities throughmust competitively bid on such projects. In January 2015, the annual ERRA review proceeding. IfCAISO reported that SCE was one of six bidders that it will consider to build and own the Delaney Colorado River transmission project. The CAISO estimated that the project will cost approximately $300 million, which is foundnot included in the table above. SCE expects a CAISO decision on the project award in the second half of 2015. For more information on transmission infrastructure competition, see "Business—SCE—Competition."

Distribution expenditures include projects and programs to be unreasonable or imprudent with respectmeet reliability, infrastructure replacement (including replacement of poles to its utility-owned generation outagesmeet current compliance and contract administration activities, then this could negatively impact SCE's earningssafety standards), customer load growth requirements, information and cash flows.

Generation expenditures include maintenance-related capital expenditures associated with Palo Verde and SCE's hydroelectric and gas-fired generation infrastructure and renewal of FERC approved SCE's settlement 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. Under operation of the formula rate, transmission revenue will be updated to actual cost of service annually. The transmission revenue requirementoperating licenses. Infrastructure expenditures include dam improvements, flowline and rates are updated each December, to reflect a forecast of costs for the upcoming rate period, as well as a true up of the transmission revenue to actual costs incurred by SCE in the prior calendar year on its formula rate. The FERC weighted average ROE, including projectsubstation refurbishments, and other incentives, is 10.45%powerline replacements. Equipment replacement expenditures include transformers, automation, switchgear, hydro turbine repowers, generator rewinds, and will remain in effect until at least June 30, 2015, when the moratorium, provided for in the settlement, on modifications to the formula rate tariff ends. For further information on the current FERC formula rates, related transmission revenue requirements and rate changes, see “Liquidity and Capital Resources—SCE—small generator replacements.

In December 2012,2014, the CPUC adoptedawarded SCE an energy efficiency incentive mechanismof $22 million for the 2010 – 2012 and 2013 energy efficiency program performance period.years. The mechanism uses an incentive calculation that is based on actualCPUC has not completed its assessment of energy efficiency expenditures. The December 2012 CPUC decision provided shareholderfixed price contract cost accounting practices which could result in additional earnings of $6.2 million for the 2010 program performance period and allows SCE the opportunity to claim future shareholder earnings in both 2013 and 2014 associated with SCE's 2011 and 2012 program performance periods using this incentive calculation. In September 2013,years. There is no assurance that the CPUC adopted a new energy efficiency incentive mechanism called the Energy Savings and Performance Incentive Mechanism ("ESPI"). The ESPI will apply starting with the 2013 – 2014 energy efficiency program cycle and continuemake an award for subsequent cycles, until further notice. The ESPI is comprised of performance/savings rewards and management fees based on actual energy efficiency expenditures and does not contain any provisions for penalties. The proposed ESPI schedule for earning claims anticipates payments of the incentive rewards occurring between one and two years after the relevant programgiven year. For further discussion of SCE's energy efficiency incentive awards, see "Liquidity and Capital Resources—SCE—Regulatory Proceedings—Energy Efficiency Incentive Mechanism" in the MD&A.

In CaliforniaNovember 2014, SCE filed its 2015 annual update with the FERC with the rates effective from January 1, 2015 to December 31, 2015. The update provided support for an increase in SCE's transmission revenue requirement of $89 million or 10.8% over amounts currently authorized in rates. The primary reason for the increase is the inclusion of costs associated with several large transmission projects that were completed in 2013, including Devers-Colorado River, Eldorado-Ivanpah, and other states, therethe Red Bluff substation.

Rates related to fuel and purchased power are wholesale energy markets through which competing electricity generators offer their electricity outputset annually based on a forecast of the costs SCE expects to market participants, including 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 participatesincur in the day-aheadfollowing year. Actual fuel and real-time markets forpower costs that are either greater or less than the sale of its generation and purchases for its load requirements.

In October 2013, the CPUC issued a decision adopting policies and targets for customers in SCE's service area 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 competition from citiesstorage procurement. Under the Energy Storage Procurement Framework 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.

Some of the fixed costs ofpower procurement contracts contain provisions that require SCE to maintain an investment grade credit rating from the poles, wires, meters, advanced technologies, and other infrastructure that makesmajor credit rating agencies. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the grid safe, reliable, and able to accommodate solar panelsliability or other distributed generation systems. In addition, NEM customers are exempted from standby and departing load charges and interconnection-related costs.post additional collateral.

AB 327 directsThe table below provides the CPUC to address this subsidization through: rate reform, which includes the impositionamount of fixed charges on both NEM and non-NEM customers; the development of a new standard billing contract for customers who install distributed generation systems after July 2017 or the attainment of the NEM Cap; and a transition period over which customers who received NEM billing prior to new standard billing contract period will transition to the new contract. The new standard billing contract will be based on the actual costs and benefits of distributed power generation.

In June 2013,SCE's cash flows are affected by regulatory balancing accounts 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 decidedseeks to permanently retireadjust rates on an annual basis or at other designated times to recover or refund the remaining Units at San Onofre. For more information, seebalances 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.

During the third quarter of 2014, indirect subsidiaries of Edison Energy entered into three non-recourse debt and certaintax equity financings designed to fund a portion of SCE's substations, and portionstheir capital requirements for approximately 35 megawatts of its transmission, distribution and communication systemssolar rooftop projects. The projects are located on lands owned by the federal, state or local governments under licenses, permits, easements or leases, or on public streets or highways pursuantexpected 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. In particular, the easement granted by the U.S. Navy for San Onofre gives the Navy the right to set site-restoration requirements, which could exceed the NRC requirements and require SCE to restore the site to its original condition.

The following table summarizes major categories of net cash provided by operating activities as provided in more detail in SCE's consolidated statements of cash flows for 2014, 2013 and 2012.

Net cash provided by operating activities was also impacted by changes in regulatory assets and accordingly, the discussionliabilities, including changes in this section focuses mainly on regulations applicable to California. For more information on environmental risks, see "Item 1A. Risk Factors—Risks Relating to Southern California Edison Company—Environmental Risks."

various degreesWhile some balancing accounts are discrete, (for example, the Four Corners memorandum account related to the sale of nonattainment, includingSCE's interest or the greater Los Angeles area (known asgenerator settlements), other balancing accounts are ongoing with changes generally collected in the South Coast Air Basin),following year. During 2014 and 2013, cash flows were lower, whereas in 2012 cash flows were higher due to the impact of regulatory assets and liabilities. The impact on cash flow from the two principal balancing accounts are:

Cash flows provided (used) by other noncurrent assets and the San Joaquin Valley (extreme nonattainment). California isliabilities were $33 million, $(49) million and $221 million in the process2014, 2013 and 2012, respectively. Major factors affecting cash flow related to non-current assets and liabilities were activities related to SCE's nuclear decommissioning trusts and settlements relating to injuries and damages.

The following table summarizes cash provided by financing activities for 2014, 2013 and 2012. Issuances of developing air quality management plansdebt and updating its state implementation planpreference stock are discussed in "Notes to outline how compliance with the 2008 NAAQS will be achieved. The implementation plans may call for more stringent restrictions on air emissions, which could further increase the difficultyConsolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt" and "—Note 12. Preferred and Preference Stock of siting new natural gas fired generation in Southern California.

Cash flows from investing activities are primarily due to protect aquatic organisms by reducing capture in the screens attached to cooling water intake structures (impingement) at generating facilities and the water volume brought into the facilities (entrainment) are expected to be finalized in the first quarter of 2014. Due to the decision to permanently retire San Onofre Units 2 and 3, SCE will seek relief from the federal standards in order to avoid material capital expenditures at San Onofre.

SCE's statement of cash flows includes activities of the Nuclear Decommissioning Trusts which are reflected in the following line items:

Net cash from continuing operating activities decreased $331 million in California2014 compared to 2013 due to:

SCE has contingencies related to two laws governing GHG emissions. The first law,San Onofre, Four Corners Environmental Matters, Nuclear Insurance, Wildfire Insurance and Spent Nuclear Fuel which are discussed in "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies."

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 California Global Warming Solutions Actliability quarterly, by assessing a range of 2006 (also referred to as AB 32), establishes a comprehensive program to reduce GHG emissions. AB 32 required the California Air Resources Board ("CARB") to develop regulations, which became effective in 2012, that would reduce California's GHG emissions to 1990 levels by 2020. In December 2011, the CARB regulation was officially published establishing a California cap-and-trade program. In the California cap-and-trade program, all covered GHG emitters, including SCE, are subject to a “cap” on their emissions designed to encourage entities to reduce emissions from their operations. Covered entities must remit a compliance instrumentreasonably likely costs for each ton of carbon dioxide equivalent gas emittedidentified site using currently available information, including existing technology, presently enacted laws and can do so buying state-issued emission allowancesregulations, experience gained at auction or purchasing them in the secondary allowance market. GHG emitters can also meet up to 8% of their AB 32 cap-and-trade obligations by participating in verified offset programs, such as reforestation, that have recognized effects on reducing atmospheric GHGs. The first compliance period for the cap-and-trade program covers 2013-2014 GHG emissions. The most recent auction, held on November 19, 2013, cleared at $11.48/metric ton, $0.77 above the floor price of $10.71.

EME has one leveraged lease investment and Edison Capital has investments in affordable housing projects that apply the subjectequity method of litigation. In 2012, environmental groups filed a case against CARB challenging the cap-and-trade program's offset provisions.accounting. These off-balance sheet transactions are not material to Edison International's consolidated financial statements. SCE intervened as part of a broad business coalition to support the provisions on offset programs. The Superior Court upheld the offset provisions but the case is on appeal. The California Chamber of Commercehas variable interests in power purchase contracts with variable interest entities and a private company filed suits allegingvariable interest in unconsolidated Trust I, Trust II and Trust III that the auction itself violated AB 32issued $475 million (aggregate liquidation preference) of 5.625%, $400 million (aggregate liquidation preference) of 5.10% and the California Constitution. The Superior Court consolidated the two suits and ruled in CARB's favor in November 2013. Plaintiffs have announced their intent$275 million (aggregate liquidation preference) of 5.75%, trust securities, respectively, to appeal.