We discuss matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and details of any new matters below.

The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment. In December 2010, the California Utilities filed their 2012 General Rate Case (GRC) applications to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. Both SDG&E and SoCalGas filed revised applications with the CPUC in July 2011. Evidentiary hearings were completed in January 2012, and final briefs reflecting the results from these hearings were filed with the CPUC in May 2012.

In February 2012, the California Utilities filed amendments to update their July 2011 revised applications. With these amendments, SDG&E is requesting a revenue requirement in 2012 of $1.849 billion, an increase of $235 million (or 14.6 percent) over 2011, of which $67 million is being requested for cost recovery of the incremental wildfire insurance premiums which are not included in the 2011 revenue requirement as set forth in the 2008 GRC. SoCalGas is requesting a revenue requirement in 2012 of $2.112 billion, an increase of $268 million (14.5 percent) over 2011.

In March 2013, the CPUC issued a proposed draft decision (2012 GRC PD) that would establish a 2012 revenue requirement of $1.749 billion for SDG&E and $1.952 billion for SoCalGas. This represents an increase of $135 million (8.4 percent) and $108 million (5.9 percent) over the authorized 2011 revenue requirements of SDG&E and SoCalGas, respectively. The 2012 GRC PD would also establish a four-year GRC period (through 2015); subsequent escalation of the adopted revenue requirements for years 2013, 2014 and 2015 based on the Consumer Price Index – Urban (CPI-U); and the continuation of the Z-Factor mechanism for qualifying cost recovery. The Z-Factor mechanism allows the California Utilities to seek cost recovery of significant cost increases, under certain circumstances, incurred between GRC filings from unforeseen events subject to a $5 million deductible per event.

On April 18, 2013, the California Utilities filed comments in response to the 2012 GRC PD with the CPUC recommending changes to the proposed 2012 revenue requirements, citing significant errors that should be addressed. The issues identified by the California Utilities in their filed comments equate to the 2012 GRC PD's proposed revenue requirement being understated by $3 million and $52 million for SDG&E and SoCalGas, respectively. Among the major issues in the 2012 GRC PD identified by the California Utilities in the filed comments are: 1) discrepancies between the detail in the model used by the CPUC in determining the proposed 2012 revenue requirements when compared to the language in the 2012 GRC PD; 2) recovery of amounts for the funding of pension plans that are in excess of what the current funding levels of these plans are expected to be based on current pension funding guidelines; 3) reductions for the funding of critical SoCalGas gas operations and customer service departments; and 4) the level of funding for the employees' short-term incentive compensation plans when compared to the CPUC's assessment of the level of total employee compensation for the California Utilities and to what has been approved in other recent California investor-owned utilities' GRC decisions.

In addition to the issues comprising the understatement of the 2012 GRC PD's revenue requirement for 2012, the filed comments also identify an inconsistency in the 2012 GRC PD's design of the proposed attrition mechanism when compared to the attrition mechanism adopted in other recent California investor-owned utilities' GRC decisions. The 2012 GRC PD proposes the use of the CPI-U, rather than a utility-industry index, as the basis for Post Test Year escalation. The filed comments provide a comparison of what the attrition would be based on the CPI-U as compared to the attrition mechanism adopted in recent GRCs for other regulated utilities. This comparison shows that, on average over the past five years (2007 – 2012), the utility-industry index for SDG&E and SoCalGas was 170 basis points (1.7 percent) and 140 basis points (1.4 percent) higher, respectively, than the CPI-U. In their filed comments, the California Utilities urge the CPUC to reject the use of the CPI-U as the index and adopt a utility-industry index or indices, similar to what was adopted for other California investor-owned utilities in their most recent GRC proceedings.

We expect a final CPUC decision, which will be made effective retroactive to January 1, 2012, in the second quarter of 2013. The financial impact of the final CPUC decision, retroactive to January 1, 2012, will be reflected in the California Utilities' financial statements in the period in which the final CPUC decision is issued. Because a final decision for the 2012 GRC was not issued by March 31, 2013, the California Utilities have recorded revenues in 2012 and in the first quarter of 2013 based on levels authorized in 2011 plus, for SDG&E and consistent with the recent CPUC decisions for cost recovery for SDG&E's incremental wildfire insurance premiums, an amount for the recovery of 2012 wildfire insurance premiums.

A cost of capital proceeding determines a utility's authorized capital structure and authorized rate of return on rate base (ROR), which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE), weighted on a basis consistent with the authorized capital structure. The authorized ROR is the rate that the California Utilities are authorized to use in establishing rates to recover the cost of debt and equity used to finance their investment in electric and natural gas distribution, natural gas transmission and electric generation assets. In addition, a cost of capital proceeding also addresses the automatic ROR adjustment mechanism which applies market-based benchmarks to determine whether an adjustment to the authorized ROR is required during the interim years between cost of capital proceedings.

SDG&E and SoCalGas filed separate applications with the CPUC in April 2012 to update their cost of capital effective January 1, 2013. The CPUC issued a ruling in June 2012 bifurcating the proceeding. Phase 1 addressed each utility's cost of capital for 2013, with a final decision issued in December 2012, which granted SDG&E and SoCalGas an authorized ROR of 7.79 percent and 8.02 percent, respectively. The CPUC-authorized ROR in effect prior to the effective date of this decision was 8.40 percent for SDG&E and 8.68 percent for SoCalGas. We provide additional details regarding the cost of capital proceeding in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. Phase 2 addressed the cost of capital adjustment mechanisms for SDG&E, SoCalGas, Southern California Edison (Edison) and Pacific Gas & Electric Company (PG&E).

SDG&E, SoCalGas, PG&E, Edison and the Division of Ratepayer Advocates (DRA) sponsored a joint stipulation in Phase 2 of the proceeding. In March 2013, the CPUC's final decision adopted the joint stipulation, as proposed. SDG&E retains its current cost of capital adjustment mechanism, and SoCalGas will implement this same adjustment mechanism, which we describe in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. Both utilities are forgoing their proposed off-ramp provision.

Various regulatory agencies, including the CPUC, are evaluating natural gas pipeline safety regulations, practices and procedures. In February 2011, the CPUC opened a forward-looking rulemaking proceeding to examine what changes should be made to existing pipeline safety regulations for California natural gas pipelines. The California Utilities are parties to this proceeding.

In June 2011, the CPUC directed SoCalGas, SDG&E, PG&E and Southwest Gas to file comprehensive implementation plans to test or replace all natural gas transmission pipelines that have not been pressure tested. The California Utilities filed their Pipeline Safety Enhancement Plan (PSEP) with the CPUC in August 2011. The proposed safety measures, investments and estimated costs are not included in the California Utilities' 2012 GRC requests discussed above.

In December 2011, the assigned Commissioner to the rulemaking proceeding for the pipeline safety regulations ruled that SDG&E's and SoCalGas' Triennial Cost Allocation Proceeding (TCAP) would be the most logical proceeding to conduct the reasonableness and ratemaking review of the companies' PSEP.

In January 2012, the CPUC Consumer Protection and Safety Division (CPSD) issued a Technical Report of the California Utilities' PSEP. The report, along with testimony and evidentiary hearings, will be used to evaluate the PSEP in the regulatory process. Generally, the report found that the PSEP approach to pipeline replacement and pressure testing and other proposed enhancements is reasonable.

In February 2012, the assigned Commissioner in the TCAP issued a ruling setting a schedule for the review of the SDG&E and SoCalGas PSEP with evidentiary hearings held in August 2012. SDG&E and SoCalGas expect a final decision in 2013. In April 2012, the CPUC issued an interim decision in the rulemaking proceeding formally transferring the PSEP to the TCAP and authorizing SDG&E and SoCalGas to establish regulatory accounts to record the incremental costs of initiating the PSEP prior to a final decision on the PSEP. The TCAP proceeding will address the recovery of the costs recorded in the regulatory account.

In April 2012, the CPUC issued a decision expanding the scope of the rulemaking proceeding to incorporate the provisions of California Senate Bill (SB) 705, which requires gas utilities to develop and implement a plan for the safe and reliable operation of their gas pipeline facilities. SDG&E and SoCalGas submitted their pipeline safety plans in June 2012. The CPUC decision also orders the utilities to undergo independent management and financial audits to assure that the utilities are fully meeting their safety responsibilities. CPSD will select the independent auditors and will oversee the audits. A schedule for the audits has not been established. In December 2012, the CPUC issued a final decision accepting the utility safety plans filed pursuant to SB 705.

We provide additional information regarding these rulemaking proceedings and the California Utilities' PSEP in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

The CPUC applies performance-based measures and incentive mechanisms to all California investor-owned utilities, under which the California Utilities have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals.

We provide additional information regarding these incentive mechanisms in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and below.

In the first quarter of 2012, the CPUC approved and SoCalGas recorded SoCalGas' application for its Gas Cost Incentive Mechanism (GCIM) award of $6.2 million for natural gas procured for its core customers during the 12-month period ending March 31, 2011. SoCalGas expects a final decision on its pending application requesting a GCIM award of $5.4 million for the 12-month period ending March 31, 2012 in the second half of 2013.

SDG&E has a 20-percent ownership interest in San Onofre Nuclear Generating Station (SONGS), a 2,150-MW nuclear generating facility near San Clemente, California. SONGS is operated by Edison and is subject to the jurisdiction of the Nuclear Regulatory Commission (NRC) and the CPUC.

In 2005, the CPUC authorized a project to install four new steam generators in Units 2 and 3 at SONGS and remove and dispose of their predecessor generators. Edison completed the installation of these steam generators in 2010 and 2011 for Units 2 and 3, respectively. In January 2012, a water leak occurred in the Unit 3 steam generator which caused it to be shut down. Edison conducted inspection testing and determined that the water leak was the result of excessive wear from tubes rubbing against each other as well as against retainer bars in the heat transfer tube bundles. Unit 2 was shut down at the time of this event for a planned maintenance and refueling outage. Inspection of Unit 2 steam generators performed in February 2012 found unexpectedly high levels of wear in some heat transfer tubes of the Unit 2 steam generators. As a result of these findings, Edison has plugged and removed from service all tubes showing excessive wear in each of the steam generators. In addition, Edison has preventively plugged all tubes in contact with the retainer bars or in the area of the tube bundles where tube-to-tube contact occurred. As of the filing date of this report, both Units 2 and 3 remain offline.

Restart of one or both of the Units will need to be approved by the NRC. In March 2012, the NRC issued a Confirmatory Action Letter (CAL) that required NRC permission to restart Unit 2 and Unit 3 and outlined actions that Edison must complete before permission to restart either Unit may be sought. The NRC could also impose additional inspections and assessment processes that could result in significant costs or additional delay. In October 2012, Edison submitted to the NRC a response to the CAL along with a restart plan for Unit 2, proposing to operate the Unit at a reduced power level for five months and then shut it down for further inspection. The plan submitted to the NRC does not address Unit 3. The NRC has been engaged in a series of inspections, evaluations, reviews and public meetings about the causes of the outage and to verify that Edison has performed the actions described in the CAL response. The NRC has made numerous requests for additional information to determine whether to allow SONGS to operate at less than 100 percent thermal power or have Edison submit further operational assessments demonstrating the structural integrity of the steam generator tubes at 100 percent thermal power. The CAL is also currently the subject of a hearing request before the NRC.

Although Edison has advised the NRC that it does not believe a license amendment would be required, in March 2013 Edison voluntarily submitted an additional operational assessment addressing the issue of structural integrity at 100 percent thermal power, and in April 2013, Edison submitted a license amendment request (LAR) for Unit 2. The LAR is intended to modify the license to reflect the reduced maximum power level, as a temporary change for approximately two years, after which new amendments for long-term power operations would be required. The NRC published the LAR in the Federal Register on April 16, 2013. In the Federal Register notice, the NRC explained that it has made a proposed determination that the LAR involves no significant hazards consideration (NSHC). Third parties have 30 days after the date of publication of the notice to submit comments on the proposed NSHC determination and 60 days to file requests for a hearing or petitions to intervene. If the NRC makes a NSHC determination, then a license amendment can be issued without further proceeding. If the NRC does not make such a NSHC determination, then the LAR could become subject to an extensive public hearing process prior to its issuance of a license amendment. Even if the NRC does make a final NSHC determination and issues the license amendment, any such determination could be subject to a motion for stay of issuance of the license amendment before the NRC or the applicable United States Court of Appeals.

In summary, two separate processes are underway at the NRC that will affect whether Edison will be in a position to restart Unit 2 in a timely manner. The NRC must approve a restart under the CAL and must issue the requested license amendment before Unit 2 restart can proceed. Both of these processes are subject to potentially extended hearings prior to the NRC taking the requested action. In addition, the NRC is not obligated to act on either request within a specified period of time and may decline to approve a restart of Unit 2 under the CAL, issue the requested license amendment, or both.

Accordingly, there can be no assurance about the length of time the NRC may take to review the request to restart Unit 2 and other submissions, including the operational assessment and the LAR, or whether the request to restart will be granted in whole or in part. However, in connection with making the LAR, Edison has requested the NRC Staff to reach conclusions about the restart of Unit 2 by June 1, if possible. Based on discussions with Edison, neither SDG&E nor Edison expect such decision by the requested date.

Also, due to the more extensive tube-to-tube wear that occurred in Unit 3, it remains unclear whether Unit 3 will be able to restart without additional repairs and corrective actions. The ability to restart Unit 3 may also be affected by the information obtained about the operating performance of Unit 2, should Unit 2 be restarted. Each Unit will only be restarted when all necessary repairs and appropriate mitigation plans for that Unit are completed in accordance with the CAL and when the NRC and Edison are satisfied that it is safe to restart and operate such Unit.

If Edison is unable to restart Unit 2, a retirement of Unit 2 could also result in the retirement of Unit 3. If Unit 2 does restart, then an assessment of the feasibility of restarting Unit 3 without extensive repairs will be conducted. Without a restart of Unit 2, a decision to retire one or both Units could be made before year-end 2013. Through March 31, 2013, SDG&E's proportional investment in the steam generators, net of accumulated depreciation, was approximately $149 million. In March 2013, Edison filed the final costs for the steam generator project with the CPUC. The total project costs, after adjusting for inflation using the Handy-Whitman Index, was within the amount authorized in the CPUC decision approving the project.

In October 2012, the CPUC issued an Order Instituting Investigation (OII) into the SONGS outage pursuant to California Public Utilities Code Section 455.5 to determine whether Edison and SDG&E should remove from customer rates some or the entire revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires that all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account, with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, will be required to be refunded to customers.

During the unscheduled outage at SONGS, SDG&E has procured replacement power, the cost of which is fully recovered in revenues subject to review and potential disallowance by the CPUC. The estimated replacement power cost requirements specified in the OII proceeding, including estimated foregone energy sales from excess SONGS production, produce a replacement power cost estimate, in excess of avoided nuclear fuel costs, that is incurred by SDG&E through March 31, 2013, as a result of the unscheduled SONGS outage (commencing in 2012 on January 31 for Unit 3 and March 5 for Unit 2) of approximately $107 million, of which $35 million was incurred in the first quarter of 2013. Total replacement power costs will not be known until the Units are returned to service and are fully operational.

Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. In 2012, SDG&E recognized approximately $199 million of revenue associated with its investment in SONGS and related operating costs. For the quarter ended March 31, 2013, SDG&E recognized an estimated $39 million of such revenue. Following is a summary of SDG&E's March 31, 2013 net book investment, excluding any decommissioning-related assets and liabilities, and its rate base investment in SONGS:

SUMMARY OF SDG&E NET BOOK INVESTMENT AND RATE BASE INVESTMENT IN SONGS(1)
(Dollars in millions)
			Unit 2		Unit 3		Common Plant		Total
Net book investment:
Net property, plant and equipment, including
	construction work in progress	$	151	$	115	$	127	$	393
Materials and supplies			―		―		10		10
Nuclear fuel			―		―		116		116
	Net book investment	$	151	$	115	$	253	$	519

Rate base investment		$	99	$	94	$	78	$	271
(1)	Excludes nuclear decommissioning-related assets and liabilities.

Under Section 455.5, any determination to adjust rates would be made after the CPUC conducts hearings. If, after investigation and hearings, the CPUC were to require SDG&E to reduce rates as a result of a Unit being out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation. Notwithstanding the requirements of Section 455.5, the CPUC may institute other proceedings relating to the impact of the extended outage at SONGS and its potential effects on rates.

A ruling was issued in January 2013 setting the initial scope and schedule for the OII, which will be managed in phases. The first phase will identify the costs at issue, including the excess replacement power costs, for 2012, with a decision expected by mid-2013. Phase 2 will address the issue of costs remaining in rates, with a decision expected by the end of 2013. Phase 3 will review the steam generator replacement project costs for reasonableness, with a decision expected by the end of 2014. Costs at issue for 2013 would be addressed in a fourth phase of the OII, but a schedule for this phase has not been established.

SDG&E continues to provide information to the CPUC in response to inquiries stemming from the OII, and it is SDG&E's intent to continue to pursue continued recovery in rates of its investment in SONGS (including the cost of the steam generator replacement project), it's authorized return on its investment in SONGS and recovery of all costs incurred related to its proportionate share of the SONGS operating and maintenance costs and the cost incurred for replacement power in excess of avoided nuclear fuel costs. As of March 31, 2013, it is SDG&E's opinion that there is insufficient information available to conclude that it is probable that the CPUC will require SDG&E to refund any of the SONGS revenue that is subject to review in the OII to customers. Should SDG&E conclude that it is probable that a portion or all of such revenue will be required to be refunded to customers, SDG&E will record a charge against earnings at the time such conclusion is reached.

The steam generators were designed and supplied by Mitsubishi Heavy Industries (MHI) and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. In July 2012, the NRC issued a report providing the result of the inspection performed by the Augmented Inspection Team (AIT) of Edison's performance as the SONGS Operating Agent. The inspection concluded that faulty computer modeling that inadequately predicted conditions in the steam generators at SONGS and manufacturing issues contributed to excessive wear of the components. The most probable causes of the tube-to-tube wear were a combination of higher than predicted thermal/hydraulic conditions and changes in the manufacturing of the Unit 3 steam generators. This report also identified a number of yet unresolved issues that are continuing to be examined. Edison's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include the cost of replacement power. Such limitations in the contract are subject to certain exceptions. Edison, on behalf of all owners, has formally notified MHI that it believes that one or more of such exceptions now apply and that MHI's liability is not limited to $138 million. MHI has advised Edison that it disagrees with Edison's position. This disagreement may ultimately become the subject of dispute resolution procedures as set forth in the contract with MHI, including international arbitration. Edison has submitted invoices on behalf of all owners to MHI in the aggregate amount of $139 million for certain steam generator repair costs incurred through February 28, 2013, of which MHI has paid $45 million but reserved the right to challenge any of the charges in the invoice. In January 2013, MHI advised Edison that it rejected a portion of the first invoice and required further documentation regarding the remainder of the invoice. Edison expects to continue to invoice MHI for any additional costs incurred.

SDG&E is a named insured on the Edison insurance policies covering SONGS. These policies, issued by Nuclear Electric Insurance Limited (NEIL), cover nuclear property and non-nuclear property damage at the SONGS facility, as well as accidental outage insurance. Edison has placed NEIL on notice of potential claims for loss recovery. As of the date of this report, Edison submitted to NEIL a separate Partial Proof of Loss on behalf of each of Edison, SDG&E and the City of Riverside in connection with the outages of SONGS Units 2 and 3 through December 29, 2012, that total $234 million. The NEIL policies contain a number of exclusions and limitations that may reduce or eliminate coverage. SDG&E will assist Edison in pursuing claims recoveries from NEIL, as well as warranty claims with MHI, but there is no assurance that SDG&E will recover all or any of its applicable costs pursuant to these arrangements. We provide additional information about insurance related to SONGS in Note 10.

Edison is also addressing a number of other regulatory and performance issues at SONGS. Edison continues to implement plans and address the identified issues, however a number of these issues remain outstanding. To the extent that these issues persist, it is likely that additional action will be required by Edison, which may result in increased SONGS operating costs and/or materially adversely impacted operations. Currently, SDG&E is allowed to fully offset its share of SONGS operating costs in revenue. If further action is required, it may result in an increase in SDG&E's Operation and Maintenance expense, with any increase being fully offset in Operating Revenues – Electric.

In light of the aftermath and the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the earthquake and tsunami in March 2011, the NRC plans to perform additional operation and safety reviews of nuclear facilities in the United States. The NRC has also required additional actions by licensees to address severe accident risk and has requested additional analysis on external hazards such as seismic and tsunami. The lessons learned from the events in Japan and the results of the NRC reviews may materially impact future operations and capital requirements at nuclear facilities in the United States, including the operations and capital requirements at SONGS.

We provide more information about SONGS in Note 10 following and in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E filed an application with the CPUC in October 2012 for a permit to construct various transmission replacement projects in and around the Cleveland National Forest. The proposed projects will replace and fire-harden five transmission lines at an estimated cost of $420 million. The projects are subject to review by the U.S. Forest Service (USFS). A joint environmental report will be developed by the CPUC and USFS. SDG&E expects a CPUC decision approving the transmission projects in 2014. We expect the projects to be in service by 2017.

SDG&E filed an application with the CPUC in May 2012 for a Certificate of Public Convenience and Necessity to construct the South Orange County Reliability Enhancement project. The purpose of the project is to enhance the capacity and reliability of SDG&E's electric service to the south Orange County area. The proposed project primarily includes replacing and upgrading approximately eight miles of transmission lines and rebuilding and upgrading a substation at an existing site. SDG&E expects a final CPUC decision approving the estimated $473 million project in 2014. SDG&E obtained approval for the project from the ISO in May 2011. The project is planned to be in service by the second half of 2017.

Since December 2010, the CPUC has approved SDG&E's requests to recover in rates the incremental increase in its general liability and wildfire liability insurance premium costs starting with the July 2009/June 2010 policy period and for each subsequent policy period through December 31, 2011, which SDG&E began incurring commencing July 1, 2009.

In the CPUC's December 2010 decision, discussed above and in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, the CPUC directed SDG&E to include in its 2012 GRC application the amount of the incremental wildfire insurance premiums it would be seeking recovery for in rates subsequent to December 31, 2011. SDG&E's 2012 GRC application does request $67 million of revenue requirement for cost recovery of wildfire insurance premiums in 2012. As a decision on SDG&E's 2012 GRC application is pending with the CPUC, and based on the CPUC's rulings for the recovery of the cost of the incremental wildfire insurance premiums incurred since July 2009, SDG&E's first quarter 2012 and 2013 revenue reflects the recovery of the cost of the incremental wildfire insurance premiums at a level consistent with what was approved for recovery for the policy period starting July 2011.

SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC in August 2009 proposing a new framework and mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. In December 2012, the CPUC issued a final decision that ultimately did not approve the proposed framework for the utilities but allowed SDG&E to maintain its authorized memorandum account, so that SDG&E may file applications with the CPUC requesting recovery of amounts properly recorded in the memorandum account at a later time, subject to reasonableness review.

SDG&E intends to pursue recovery of such costs in a future application. SDG&E will continue to assess the potential for recovery of these costs in rates. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated as of March 31, 2013, the resulting after-tax charge against earnings would have been up to $190 million. In addition, in periods following any such conclusion, SDG&E's earnings will be adversely impacted by increases in the estimated cost to litigate or settle pending wildfire claims. We discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

We provide additional information about 2007 wildfire litigation costs and their recovery in Note 10.

SUMMARY OF SDG&E NET BOOK INVESTMENT AND RATE BASE INVESTMENT IN SONGS(1)
(Dollars in millions)
			Unit 2		Unit 3		Common Plant		Total
Net book investment:
Net property, plant and equipment, including
	construction work in progress	$	151	$	115	$	127	$	393
Materials and supplies			―		―		10		10
Nuclear fuel			―		―		116		116
	Net book investment	$	151	$	115	$	253	$	519

Rate base investment		$	99	$	94	$	78	$	271
(1)	Excludes nuclear decommissioning-related assets and liabilities.