CALIFORNIA UTILITIES' REGULATORY MATTERS	3 Months Ended
Jun. 30, 2012
Notes to Consolidated Financial Statements [Abstract]
Sempra Utilities' Regulatory Matters	NOTE 9. CALIFORNIA UTILITIES' REGULATORY MATTERS JOINT MATTERS General Rate Case (GRC) 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%) 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%) over 2011. The Division of Ratepayer Advocates (DRA) is recommending that the CPUC reduce the utilities' revenue requirements in 2012 by approximately 5 percent compared to 2011. Until such time as a final decision for the 2012 GRC is issued, the California Utilities are recording revenues in 2012 based on levels authorized in 2011 plus, for SDG&E, 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. We currently expect a final decision for the 2012 GRC, which will be made effective retroactive to January 1, 2012, in the fourth quarter of 2012. Cost of Capital 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). The authorized ROR is the rate that the California Utilities are authorized to earn on their investment in electric and natural gas distribution, natural gas transmission and electric generation assets. In addition, a cost of capital proceeding also addresses market-based benchmarks to be monitored to determine whether an adjustment to the established authorized rate of return is required during the interim years between proceedings through the approved adjustment mechanism. SDG&E and SoCalGas filed separate applications with the CPUC in April 2012 to update their cost of capital effective January 1, 2013. Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E) also filed separate cost of capital applications with the CPUC. SDG&E is proposing to adjust its authorized capital structure by increasing the amount of its common equity from 49.0 percent to 52.0 percent. SDG&E is also proposing to lower its authorized ROE from 11.1 percent to 11.0 percent and to lower its authorized ROR from 8.40 percent to 8.20 percent. SoCalGas is proposing to adjust its authorized capital structure by increasing the amount of its common equity from 48.0 percent to 52.0 percent. SoCalGas is also proposing to increase its authorized ROE from 10.82 percent to 10.9 percent and to lower its authorized ROR from 8.68 percent to 8.42 percent. SDG&E is proposing to continue its cost of capital adjustment mechanism which uses a utility bond benchmark. SoCalGas is proposing to switch from its current cost of capital adjustment mechanism, which is based on U.S. Treasury Bonds, to the utility bond benchmark used by SDG&E, Edison and PG&E. Both SDG&E and SoCalGas are proposing to add an “off ramp” provision to the adjustment mechanism as a safeguard to protect against extreme changes in interest rates and to allow the CPUC latitude to suspend the annual mechanism if prudent. The CPUC issued a ruling in June 2012 bifurcating the proceeding. Phase 1 will address each utility's cost of capital for 2013. Phase 2 will address the continuation of the cost of capital adjustment mechanisms for SDG&E, Edison and PG&E. SoCalGas' request to suspend and replace its Market Indexed Capital Adjustment Mechanism (MICAM) will be addressed by a separate ruling. A Phase 1 draft decision is targeted for November 2012. A Phase 2 schedule will be established at a later date. SDG&E's cost of capital adjustment mechanism benchmark is based on the 12-month average monthly A-rated utility bond yield as published by Moody's for the 12-month period October through September of each fiscal year. If this 12-month average falls outside of a specified range, then SDG&E's authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the mid-point of the specified range. In addition, SDG&E's authorized recovery rate for the cost of debt and preferred stock would also be adjusted to their respective actual weighted average cost. Therefore, SDG&E's authorized ROR would adjust, upward or downward, as a result of all three adjustments with the new rate going into effect on January 1 following the year in which the benchmark range was exceeded. However, SDG&E expects that the CPUC decision from the 2013 cost of capital application will be effective as of January 1, 2013, and that it will supersede the rates that would result if, at the end of September 2012, this mechanism were to indicate that an adjustment is required. SoCalGas' MICAM identifies two conditions for determining whether a change in the authorized rate of return is required. Both conditions are based on the 30-year Treasury bond yields – one being the most recent trailing 12-month rolling average yield and the second being the corresponding 12-month forward forecast yield as published by Global Insight. If both conditions fall outside a specified range in a given month, SoCalGas' authorized ROE would be adjusted, upward or downward, by one-half of the difference between the trailing 12-month rolling average yield and the midpoint of the range, effective January 1 following the year in which both conditions were exceeded. Also, SoCalGas' authorized recovery rate for the cost of debt and preferred stock would be adjusted to their respective actual weighted average cost. Therefore, SoCalGas' authorized ROR would adjust, upward or downward, as a result of all three cost adjustments. In the event of such an event occurring, the benchmark interest rate would be reset to the interest rate in effect at the time it was determined that the benchmark range had been exceeded. As of January 31, 2012, the historical rolling average yield for the 30-year Treasury bonds of 3.79 percent fell below the MICAM floor of 3.88 percent. In addition, the Global Insight 12-month forward forecasted yield of 3.48 percent published in February 2012 was also below the MICAM floor. Therefore, the MICAM calls for an adjustment of SoCalGas' ROE and authorized recovery for the cost of debt and preferred stock to their actual weighted average cost to be effective on January 1, 2013. If the MICAM adjustment is implemented, SoCalGas' ROE would be reduced to 10.02 percent effective January 1, 2013, a reduction of 80 basis points from its current authorized ROE, and its authorized ROR would be reduced to 7.99 percent, a reduction of 69 basis points from its current authorized ROR. However, SoCalGas expects that the CPUC decision from its 2013 cost of capital application will supersede the rates that would result from the MICAM adjustment. Natural Gas Pipeline Operations Safety Assessments As a result of recent natural gas pipeline explosions in the U.S., including the September 2010 rupture in San Bruno, California of a natural gas pipeline owned and operated by PG&E (the San Bruno incident), 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 in August 2012. SDG&E and SoCalGas expect a final decision in the first quarter of 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 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 must accept, modify or reject the plans by the end of 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. 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 Updated Annual Report. Utility Incentive Mechanisms 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 Updated Annual Report, and in the updates below. Energy Efficiency We expect a draft decision on an incentive mechanism for the 2013-2014 program period in the third quarter of 2012, with a final decision by year-end. We expect a draft decision on how and if an incentive mechanism should apply to the 2010-2012 program cycle in the third quarter of 2012, and a final decision on any incentive awards for the 2010-2012 period by year-end. The CPUC issued its latest Order Instituting Rulemaking (OIR) in January 2012 to continue its review of the incentive mechanism. Natural Gas Procurement 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. In June 2012, SoCalGas applied to the CPUC for approval of a GCIM award of $5.4 million for natural gas procured for its core customers during the 12-month period ending March 31, 2012. SoCalGas expects a CPUC decision in the first half of 2013. SDG&E MATTERS San Onofre Nuclear Generating Station (SONGS) 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 tube-to-tube contact. During a planned maintenance and refueling outage on the Unit 2 steam generators in February 2012, inspections found high levels of unexpected wear in some heat transfer tubes of the Unit 2 steam generators. As of today, both Units 2 and 3 remain offline. Any remedial action that will permit restart of one or both of the Units will need to be approved by the NRC. The schedule to restart these Units has not been determined. Edison currently believes that Unit 2 could be restarted months in advance of Unit 3; however, in order to do so, it is expected that Unit 2, pending further repairs and analysis, would operate at reduced power levels and with mid-cycle scheduled outages to provide assurance of safe operation. It is not clear at this time whether Unit 3 will be able to restart without extensive additional repairs, and Edison has not indicated when it believes Unit 3 may be ready to restart operations. Edison is engaged in the analysis of what repairs, if any, could be undertaken to restore the steam generators to their originally specified capabilities safely, but has not yet determined what those repairs might be or whether the generators will need to be replaced for the Units to operate at their prior output levels. The timing of the restart of either of the Units is dependent upon approval by the NRC. In March 2012, the NRC issued a Confirmatory Action Letter 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 choose to impose additional inspections and assessment processes that could result in significant costs or additional delay. Should Edison seek NRC approval to restart a Unit, the NRC may employ other procedures before making any determination about whether to grant permission pursuant to the terms of the Confirmatory Action Letter. It is also possible that one or more amendments to the NRC operating license for SONGS might be required (whether or not as a prerequisite to return a Unit to safe operation). There is no set or predetermined time period for such processes, and, accordingly, there can be no assurance about the length of time the NRC may take to review any request to restart submitted by Edison under the Confirmatory Action Letter or whether any such request would be granted in whole or in part. Through June 30, 2012, SDG&E's proportional investment in the steam generators was approximately $178 million. These investment amounts remain subject to CPUC review upon submission of Edison's final costs for the overall project. During the unscheduled outage at SONGS, SDG&E has procured replacement power, the cost of which is fully recovered in revenues subject to a reasonableness review by the CPUC. Replacement power costs for outages associated with the unscheduled SONGS outage (commencing in 2012 on February 1 for Unit 3 and March 5 for Unit 2) through June 30, 2012 were approximately $25 million. Total replacement power costs will not be known until the Units are returned to service, but costs for power are likely to be higher during the summer months should replacement power still be required. Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. At June 30, 2012, SDG&E's rate base investment in SONGS was $228 million and its net book investment, including construction work in progress and nuclear fuel was $463 million. Under California Public Utilities Code Section 455.5, SDG&E will be required to notify the CPUC if either of the Units has been out of service for nine consecutive months, not including preplanned outages (November 2012 for Unit 3 and December 2012 for Unit 2). In that event, the CPUC is required within 45 days of receipt of the notice to initiate an investigation to determine whether SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such amounts recovered in rates are collected subject to refund. Under Section 455.5, any determination to adjust rates is made after hearings are conducted in connection with the next general rate case. 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, and there is currently pending before the CPUC a proposal to initiate an Order Instituting Investigation regarding such impacts. The steam generators are warranted for an initial period of 20 years from acceptance by its supplier Mitsubishi Heavy Industries (MHI). MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. On July 18, 2012, the NRC issued a report providing the result of the inspection performed by the Augmented Inspection Team (AIT). 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 $137 million and excludes consequential damages, defined to include the cost of replacement power. Such limitations in the contract are subject to applicable exceptions. 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. 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. 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 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. Edison is also addressing a number of other regulatory and performance issues at SONGS, and the NRC has required Edison to take actions to provide greater assurance of compliance by SONGS personnel. 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. We provide more information about SONGS in Note 10 and in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report. Power Procurement and Resource Planning Renewable Energy SDG&E is subject to the Renewables Portfolio Standard (RPS) Program administered by both the CPUC and the California Energy Commission (CEC), which requires each California utility to procure 33 percent of its annual electric energy requirements from renewable energy sources by 2020, with an average of 20 percent required from January 1, 2011 to December 31, 2013; 25 percent by December 31, 2016; and 33 percent by December 31, 2020. The CPUC began a rulemaking in May 2011 to address the implementation of the 33% RPS Program. We discuss the RPS Program further in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report. South Orange County Reliability Enhancement SDG&E filed an application with the CPUC in May 2012 for a Certificate of Public Convenience and Necessity (CPCN) 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 will be requesting a CPUC decision approving the estimated $473 million project by the third quarter of 2013. 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. Incremental Insurance Premium Cost Recovery In December 2010, the CPUC approved SDG&E's request for a $29 million revenue requirement for the recovery of the incremental increase in its general liability and wildfire liability insurance premium costs for the July 2009/June 2010 policy period. In its decision approving this cost recovery, the CPUC also authorized SDG&E to request recovery of any incremental insurance premiums for future policy periods through December 31, 2011, with a $5 million deductible applied to each policy renewal period. This approval was in response to a request filed by SDG&E with the CPUC in August 2009 seeking authorization to recover higher liability insurance premiums (amounts in excess of those authorized to be recovered in the 2008 GRC), which SDG&E began incurring commencing July 1, 2009, and any losses realized due to higher deductibles associated with the new policies. SDG&E made the filing under the CPUC's rules allowing utilities to seek recovery of significant cost increases incurred between GRC filings that meet certain criteria, subject to a $5 million deductible per event. In December 2011, the CPUC approved SDG&E's request for an incremental revenue requirement of $63 million for the July 2010/June 2011 policy period. In May 2012, the CPUC approved SDG&E's request for a $28 million revenue requirement for the first six months of the July 2011/June 2012 policy period. In the CPUC's December 2010 decision, discussed above, 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, with a decision currently expected in the fourth quarter of 2012, 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 2012 revenue through June 30, 2012 reflects the expected recovery of the cost of the incremental wildfire insurance premiums incurred in the current year. Excess Wildfire Claims Cost Recovery SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC in August 2009 proposing a new 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 rates. This application was made jointly with Edison and PG&E. In July 2010, the CPUC approved SDG&E's and SoCalGas' requests for separate regulatory memorandum accounts to record the subject expenses while the application is pending before the CPUC. Several parties protested the original application and, in response, the four utilities jointly submitted an amended application in August 2010. In November 2011, Edison and PG&E requested to withdraw from the joint utility application due, in part, to the delays in the proceeding. In January 2012, the CPUC granted their requests to withdraw and held evidentiary hearings for SDG&E and SoCalGas, both of which are still moving forward with the application. Legal briefs were completed in March 2012. We expect a final CPUC decision in the second half of 2012. SDG&E intends to request recovery for costs incurred associated with the 2007 wildfires that are in excess of amounts recovered from its insurance coverage and other responsible third parties in a future application. If a cost recovery mechanism covering the 2007 wildfire costs is approved by the CPUC as a result of these proceedings, SDG&E intends to utilize the methodology authorized. Otherwise, SDG&E will file an application for cost recovery utilizing other cost recovery application processes available through the CPUC. We provide additional information about 2007 wildfire litigation costs and their recovery in Note 10. East County Substation In June 2012, the CPUC approved SDG&E's application for authorization to proceed with the East County Substation project, estimated to cost $435 million. The Bureau of Land Management (BLM) is expected to issue its record of decision in the third quarter of 2012. SDG&E expects to begin construction by the end of 2012 and the substation to be placed in service in 2014. We provide additional information on the project in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report. SOCALGAS MATTER Aliso Canyon Natural Gas Storage Compressor Replacement In September 2009, SoCalGas filed an application with the CPUC requesting approval to replace certain obsolete natural gas turbine compressors used in the operations of SoCalGas' Aliso Canyon natural gas storage reservoir, with a new electric compressor station. In April 2012, the CPUC issued a draft environmental impact report (EIR) for the project concluding that no significant or unavoidable adverse environmental impacts have been identified from the construction or operation of the proposed project. Public comments on the draft EIR were filed in May 2012. We expect a final EIR and CPUC decision on the estimated $200 million project in the first half of 2013. We discuss additional matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

CALIFORNIA UTILITIES' REGULATORY MATTERS

3 Months Ended

Jun. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

NOTE 9. CALIFORNIA UTILITIES' REGULATORY MATTERS

JOINT MATTERS

General Rate Case (GRC)

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%) 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%) over 2011. The Division of Ratepayer Advocates (DRA) is recommending that the CPUC reduce the utilities' revenue requirements in 2012 by approximately 5 percent compared to 2011.

Until such time as a final decision for the 2012 GRC is issued, the California Utilities are recording revenues in 2012 based on levels authorized in 2011 plus, for SDG&E, 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. We currently expect a final decision for the 2012 GRC, which will be made effective retroactive to January 1, 2012, in the fourth quarter of 2012.

Cost of Capital

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). The authorized ROR is the rate that the California Utilities are authorized to earn on their investment in electric and natural gas distribution, natural gas transmission and electric generation assets. In addition, a cost of capital proceeding also addresses market-based benchmarks to be monitored to determine whether an adjustment to the established authorized rate of return is required during the interim years between proceedings through the approved adjustment mechanism.

SDG&E and SoCalGas filed separate applications with the CPUC in April 2012 to update their cost of capital effective January 1, 2013. Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E) also filed separate cost of capital applications with the CPUC. SDG&E is proposing to adjust its authorized capital structure by increasing the amount of its common equity from 49.0 percent to 52.0 percent. SDG&E is also proposing to lower its authorized ROE from 11.1 percent to 11.0 percent and to lower its authorized ROR from 8.40 percent to 8.20 percent. SoCalGas is proposing to adjust its authorized capital structure by increasing the amount of its common equity from 48.0 percent to 52.0 percent. SoCalGas is also proposing to increase its authorized ROE from 10.82 percent to 10.9 percent and to lower its authorized ROR from 8.68 percent to 8.42 percent. SDG&E is proposing to continue its cost of capital adjustment mechanism which uses a utility bond benchmark. SoCalGas is proposing to switch from its current cost of capital adjustment mechanism, which is based on U.S. Treasury Bonds, to the utility bond benchmark used by SDG&E, Edison and PG&E. Both SDG&E and SoCalGas are proposing to add an “off ramp” provision to the adjustment mechanism as a safeguard to protect against extreme changes in interest rates and to allow the CPUC latitude to suspend the annual mechanism if prudent.

The CPUC issued a ruling in June 2012 bifurcating the proceeding. Phase 1 will address each utility's cost of capital for 2013. Phase 2 will address the continuation of the cost of capital adjustment mechanisms for SDG&E, Edison and PG&E. SoCalGas' request to suspend and replace its Market Indexed Capital Adjustment Mechanism (MICAM) will be addressed by a separate ruling. A Phase 1 draft decision is targeted for November 2012. A Phase 2 schedule will be established at a later date.

SDG&E's cost of capital adjustment mechanism benchmark is based on the 12-month average monthly A-rated utility bond yield as published by Moody's for the 12-month period October through September of each fiscal year. If this 12-month average falls outside of a specified range, then SDG&E's authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the mid-point of the specified range. In addition, SDG&E's authorized recovery rate for the cost of debt and preferred stock would also be adjusted to their respective actual weighted average cost. Therefore, SDG&E's authorized ROR would adjust, upward or downward, as a result of all three adjustments with the new rate going into effect on January 1 following the year in which the benchmark range was exceeded. However, SDG&E expects that the CPUC decision from the 2013 cost of capital application will be effective as of January 1, 2013, and that it will supersede the rates that would result if, at the end of September 2012, this mechanism were to indicate that an adjustment is required.

SoCalGas' MICAM identifies two conditions for determining whether a change in the authorized rate of return is required. Both conditions are based on the 30-year Treasury bond yields – one being the most recent trailing 12-month rolling average yield and the second being the corresponding 12-month forward forecast yield as published by Global Insight. If both conditions fall outside a specified range in a given month, SoCalGas' authorized ROE would be adjusted, upward or downward, by one-half of the difference between the trailing 12-month rolling average yield and the midpoint of the range, effective January 1 following the year in which both conditions were exceeded. Also, SoCalGas' authorized recovery rate for the cost of debt and preferred stock would be adjusted to their respective actual weighted average cost. Therefore, SoCalGas' authorized ROR would adjust, upward or downward, as a result of all three cost adjustments. In the event of such an event occurring, the benchmark interest rate would be reset to the interest rate in effect at the time it was determined that the benchmark range had been exceeded.

As of January 31, 2012, the historical rolling average yield for the 30-year Treasury bonds of 3.79 percent fell below the MICAM floor of 3.88 percent. In addition, the Global Insight 12-month forward forecasted yield of 3.48 percent published in February 2012 was also below the MICAM floor. Therefore, the MICAM calls for an adjustment of SoCalGas' ROE and authorized recovery for the cost of debt and preferred stock to their actual weighted average cost to be effective on January 1, 2013. If the MICAM adjustment is implemented, SoCalGas' ROE would be reduced to 10.02 percent effective January 1, 2013, a reduction of 80 basis points from its current authorized ROE, and its authorized ROR would be reduced to 7.99 percent, a reduction of 69 basis points from its current authorized ROR. However, SoCalGas expects that the CPUC decision from its 2013 cost of capital application will supersede the rates that would result from the MICAM adjustment.

Natural Gas Pipeline Operations Safety Assessments

As a result of recent natural gas pipeline explosions in the U.S., including the September 2010 rupture in San Bruno, California of a natural gas pipeline owned and operated by PG&E (the San Bruno incident), 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 in August 2012. SDG&E and SoCalGas expect a final decision in the first quarter of 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 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 must accept, modify or reject the plans by the end of 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.

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 Updated Annual Report.

Utility Incentive Mechanisms

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 Updated Annual Report, and in the updates below.

Energy Efficiency

We expect a draft decision on an incentive mechanism for the 2013-2014 program period in the third quarter of 2012, with a final decision by year-end. We expect a draft decision on how and if an incentive mechanism should apply to the 2010-2012 program cycle in the third quarter of 2012, and a final decision on any incentive awards for the 2010-2012 period by year-end. The CPUC issued its latest Order Instituting Rulemaking (OIR) in January 2012 to continue its review of the incentive mechanism.

Natural Gas Procurement

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.

In June 2012, SoCalGas applied to the CPUC for approval of a GCIM award of $5.4 million for natural gas procured for its core customers during the 12-month period ending March 31, 2012. SoCalGas expects a CPUC decision in the first half of 2013.

SDG&E MATTERS

San Onofre Nuclear Generating Station (SONGS)

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 tube-to-tube contact. During a planned maintenance and refueling outage on the Unit 2 steam generators in February 2012, inspections found high levels of unexpected wear in some heat transfer tubes of the Unit 2 steam generators. As of today, both Units 2 and 3 remain offline.

Any remedial action that will permit restart of one or both of the Units will need to be approved by the NRC. The schedule to restart these Units has not been determined. Edison currently believes that Unit 2 could be restarted months in advance of Unit 3; however, in order to do so, it is expected that Unit 2, pending further repairs and analysis, would operate at reduced power levels and with mid-cycle scheduled outages to provide assurance of safe operation. It is not clear at this time whether Unit 3 will be able to restart without extensive additional repairs, and Edison has not indicated when it believes Unit 3 may be ready to restart operations. Edison is engaged in the analysis of what repairs, if any, could be undertaken to restore the steam generators to their originally specified capabilities safely, but has not yet determined what those repairs might be or whether the generators will need to be replaced for the Units to operate at their prior output levels. The timing of the restart of either of the Units is dependent upon approval by the NRC.

In March 2012, the NRC issued a Confirmatory Action Letter 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 choose to impose additional inspections and assessment processes that could result in significant costs or additional delay. Should Edison seek NRC approval to restart a Unit, the NRC may employ other procedures before making any determination about whether to grant permission pursuant to the terms of the Confirmatory Action Letter. It is also possible that one or more amendments to the NRC operating license for SONGS might be required (whether or not as a prerequisite to return a Unit to safe operation). There is no set or predetermined time period for such processes, and, accordingly, there can be no assurance about the length of time the NRC may take to review any request to restart submitted by Edison under the Confirmatory Action Letter or whether any such request would be granted in whole or in part.

Through June 30, 2012, SDG&E's proportional investment in the steam generators was approximately $178 million. These investment amounts remain subject to CPUC review upon submission of Edison's final costs for the overall project.

During the unscheduled outage at SONGS, SDG&E has procured replacement power, the cost of which is fully recovered in revenues subject to a reasonableness review by the CPUC. Replacement power costs for outages associated with the unscheduled SONGS outage (commencing in 2012 on February 1 for Unit 3 and March 5 for Unit 2) through June 30, 2012 were approximately $25 million. Total replacement power costs will not be known until the Units are returned to service, but costs for power are likely to be higher during the summer months should replacement power still be required.

Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. At June 30, 2012, SDG&E's rate base investment in SONGS was $228 million and its net book investment, including construction work in progress and nuclear fuel was $463 million. Under California Public Utilities Code Section 455.5, SDG&E will be required to notify the CPUC if either of the Units has been out of service for nine consecutive months, not including preplanned outages (November 2012 for Unit 3 and December 2012 for Unit 2). In that event, the CPUC is required within 45 days of receipt of the notice to initiate an investigation to determine whether SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such amounts recovered in rates are collected subject to refund. Under Section 455.5, any determination to adjust rates is made after hearings are conducted in connection with the next general rate case. 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, and there is currently pending before the CPUC a proposal to initiate an Order Instituting Investigation regarding such impacts.

The steam generators are warranted for an initial period of 20 years from acceptance by its supplier Mitsubishi Heavy Industries (MHI). MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. On July 18, 2012, the NRC issued a report providing the result of the inspection performed by the Augmented Inspection Team (AIT). 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 $137 million and excludes consequential damages, defined to include the cost of replacement power. Such limitations in the contract are subject to applicable exceptions.

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. 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.

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 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.

Edison is also addressing a number of other regulatory and performance issues at SONGS, and the NRC has required Edison to take actions to provide greater assurance of compliance by SONGS personnel. 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.

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

Power Procurement and Resource Planning

Renewable Energy

SDG&E is subject to the Renewables Portfolio Standard (RPS) Program administered by both the CPUC and the California Energy Commission (CEC), which requires each California utility to procure 33 percent of its annual electric energy requirements from renewable energy sources by 2020, with an average of 20 percent required from January 1, 2011 to December 31, 2013; 25 percent by December 31, 2016; and 33 percent by December 31, 2020. The CPUC began a rulemaking in May 2011 to address the implementation of the 33% RPS Program. We discuss the RPS Program further in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

South Orange County Reliability Enhancement

SDG&E filed an application with the CPUC in May 2012 for a Certificate of Public Convenience and Necessity (CPCN) 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 will be requesting a CPUC decision approving the estimated $473 million project by the third quarter of 2013. 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.

Incremental Insurance Premium Cost Recovery

In December 2010, the CPUC approved SDG&E's request for a $29 million revenue requirement for the recovery of the incremental increase in its general liability and wildfire liability insurance premium costs for the July 2009/June 2010 policy period. In its decision approving this cost recovery, the CPUC also authorized SDG&E to request recovery of any incremental insurance premiums for future policy periods through December 31, 2011, with a $5 million deductible applied to each policy renewal period. This approval was in response to a request filed by SDG&E with the CPUC in August 2009 seeking authorization to recover higher liability insurance premiums (amounts in excess of those authorized to be recovered in the 2008 GRC), which SDG&E began incurring commencing July 1, 2009, and any losses realized due to higher deductibles associated with the new policies. SDG&E made the filing under the CPUC's rules allowing utilities to seek recovery of significant cost increases incurred between GRC filings that meet certain criteria, subject to a $5 million deductible per event.

In December 2011, the CPUC approved SDG&E's request for an incremental revenue requirement of $63 million for the July 2010/June 2011 policy period. In May 2012, the CPUC approved SDG&E's request for a $28 million revenue requirement for the first six months of the July 2011/June 2012 policy period.

In the CPUC's December 2010 decision, discussed above, 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, with a decision currently expected in the fourth quarter of 2012, 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 2012 revenue through June 30, 2012 reflects the expected recovery of the cost of the incremental wildfire insurance premiums incurred in the current year.

Excess Wildfire Claims Cost Recovery

SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC in August 2009 proposing a new 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 rates. This application was made jointly with Edison and PG&E. In July 2010, the CPUC approved SDG&E's and SoCalGas' requests for separate regulatory memorandum accounts to record the subject expenses while the application is pending before the CPUC. Several parties protested the original application and, in response, the four utilities jointly submitted an amended application in August 2010. In November 2011, Edison and PG&E requested to withdraw from the joint utility application due, in part, to the delays in the proceeding. In January 2012, the CPUC granted their requests to withdraw and held evidentiary hearings for SDG&E and SoCalGas, both of which are still moving forward with the application. Legal briefs were completed in March 2012. We expect a final CPUC decision in the second half of 2012.

SDG&E intends to request recovery for costs incurred associated with the 2007 wildfires that are in excess of amounts recovered from its insurance coverage and other responsible third parties in a future application. If a cost recovery mechanism covering the 2007 wildfire costs is approved by the CPUC as a result of these proceedings, SDG&E intends to utilize the methodology authorized. Otherwise, SDG&E will file an application for cost recovery utilizing other cost recovery application processes available through the CPUC.

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

East County Substation

In June 2012, the CPUC approved SDG&E's application for authorization to proceed with the East County Substation project, estimated to cost $435 million. The Bureau of Land Management (BLM) is expected to issue its record of decision in the third quarter of 2012. SDG&E expects to begin construction by the end of 2012 and the substation to be placed in service in 2014. We provide additional information on the project in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

SOCALGAS MATTER

Aliso Canyon Natural Gas Storage Compressor Replacement

In September 2009, SoCalGas filed an application with the CPUC requesting approval to replace certain obsolete natural gas turbine compressors used in the operations of SoCalGas' Aliso Canyon natural gas storage reservoir, with a new electric compressor station. In April 2012, the CPUC issued a draft environmental impact report (EIR) for the project concluding that no significant or unavoidable adverse environmental impacts have been identified from the construction or operation of the proposed project. Public comments on the draft EIR were filed in May 2012. We expect a final EIR and CPUC decision on the estimated $200 million project in the first half of 2013.

We discuss additional matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.