SEMPRA UTILITIES' REGULATORY MATTERS	3 Months Ended
Sep. 30, 2011
Notes to Consolidated Financial Statements [Abstract]
Sempra Utilities' Regulatory Matters	NOTE 9. SEMPRA UTILITIES' REGULATORY MATTERS POWER PROCUREMENT AND RESOURCE PLANNING Renewable Energy In 2010, certain California electric retail sellers, including SDG&E, were required to deliver 20 percent of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by both the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC), are known as the Renewables Portfolio Standard (RPS) Program. In April 2011, the Governor of California signed Senate Bill X1 2 (33% RPS Program), which goes into effect December 9, 2011 and supersedes the current RPS Program. It will require 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. The 33% RPS Program contains new flexible compliance mechanisms, more restrictive than the prior mechanisms, that can be used to comply with or meet the 33% RPS Program mandates in 2011 and beyond. The new mechanisms provide for a CPUC waiver under certain conditions, including: 1) a finding of inadequate transmission, 2) delays in the start-up of commercial operations of renewable energy projects due to permitting or interconnection or 3) unexpected curtailment by an electric system balancing authority, such as the California Independent System Operator (ISO). SDG&E continues to procure renewable energy supplies to achieve the 33% RPS Program requirements. A substantial number of these supply contracts, however, are contingent upon many factors, including: access to electric transmission infrastructure; timely regulatory approval of contracted renewable energy projects; the renewable energy project developers' ability to obtain project financing and permitting; and successful development and implementation of the renewable energy technologies. For 2010, SDG&E satisfied its RPS procurement requirements through a combination of contracted deliveries and application of the flexible compliance mechanism, including the application of certain mechanisms that are no longer available under the 33% RPS Program. For 2011 and beyond, SDG&E believes it will be able to comply with the 33% RPS Program requirements based on its contracting activity and, if necessary, application of the new flexible compliance mechanisms. SDG&E's failure to comply with the RPS Program requirements could subject it to a CPUC-imposed penalty of 5 cents per kilowatt hour of renewable energy under-delivery. SDG&E Purchase of El Dorado SDG&E purchased Sempra Generation's El Dorado natural gas generation plant on October 1, 2011, pursuant to an option to acquire the plant that was exercised in 2007. In accordance with the CPUC's approval, SDG&E acquired El Dorado (now named Desert Star Energy Center) at a price equal to the closing book value of the plant upon transfer. SDG&E made a compliance filing with the CPUC in September 2011 stating the book value purchase price as $215 million. The final purchase price is subject to change pending completion of an independent audit of Sempra Generation's net book value of the plant as of the close of business on September 30, 2011. SDG&E expects this audit to be completed by year-end 2011. East County Substation In response to a CPUC application filed by SDG&E for authorization to proceed with the East County Substation project, the CPUC and Bureau of Land Management jointly issued a favorable final environmental impact report and environmental impact statement in October 2011. We expect a CPUC decision on this project in the first quarter of 2012. We provide additional detail on the East County Substation project and CPUC application in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. GENERAL RATE CASE (GRC) The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the Sempra Utilities to recover their reasonable cost of operations and to provide the opportunity to realize their authorized rates of return on their investment. In December 2010, the Sempra 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. The CPUC issued a ruling in March 2011 setting the proceeding scope and schedule that projected a final CPUC decision around the month of March 2012 and granted the utilities' requests to establish regulatory accounts to allow recovery of their authorized 2012 revenue requirements retroactive to January 1, 2012. In July 2011, the Sempra Utilities filed amendments to revise their original applications, primarily to reflect the impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. With these amendments, SDG&E is requesting a revenue requirement in 2012 of $1.845 billion, an increase of $231 million (or 14.3%) over 2011. SoCalGas is requesting a revenue requirement in 2012 of $2.107 billion, an increase of $263 million (14.3%) over 2011. The Division of Ratepayer Advocates and other intervening parties are recommending that the CPUC reduce the utilities' revenue requirements in 2012 by approximately 5 percent compared to 2011. UTILITY INCENTIVE MECHANISMS The CPUC applies performance-based measures and incentive mechanisms to all California utilities, under which the Sempra 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 15 of the Notes to Consolidated Financial Statements in the Annual Report, and updates below. Natural Gas Procurement In the third quarter of 2011, the CPUC approved and SoCalGas recorded SoCalGas' application for its Gas Cost Incentive Mechanism (GCIM) award of $6 million for natural gas procured for its core customers during the 12-month period ending March 31, 2010. In June 2011, SoCalGas applied to the CPUC for approval of a 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 CPUC decision in the first half of 2012. In the first quarter of 2010, SoCalGas recorded a GCIM award of $12 million for its procurement activities during the 12-month period ending March 31, 2009, approved by the CPUC in January 2010. Energy Efficiency The CPUC established incentive mechanisms that are based on the effectiveness of energy efficiency and demand side management programs. In June 2011, the Sempra Utilities filed requests with the CPUC seeking incentive awards of $15.1 million for SDG&E and $2.0 million for SoCalGas for their 2009 program year results. SDG&E's filing reflects changes that SDG&E believes were errors in the calculation method developed by the CPUC's Energy Division. The CPUC issued a ruling in September 2011 directing the Energy Division to issue a report confirming the amount of the utilities' incentive awards. The Energy Division issued its report on September 30, 2011 which acknowledged the calculation issues for SDG&E, but did not validate the incentive awards for either utility. SDG&E and SoCalGas continue to work with the Energy Division to validate the awards. We still expect a CPUC decision by the end of 2011. The CPUC is also considering modifications to the incentive mechanism that would apply to the 2010 – 2012 program period, but has not established a schedule for a decision. SOCALGAS COST OF CAPITAL A cost of capital proceeding determines a utility's authorized capital structure and authorized rate of return, which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE). 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 Market Indexed Capital Adjustment Mechanism (MICAM). We provide more information about cost of capital in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report. SoCalGas' cost of capital trigger mechanism 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 range of 3.88 percent (MICAM floor) to 6.88 percent (MICAM ceiling) 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 5.38 percent (SoCalGas' MICAM benchmark interest rate), 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 actual weighted average cost. Therefore, SoCalGas' authorized rate of return would adjust, upward or downward, as a result of all three cost adjustments. Based on the Global Insight 12-month forward forecasted yield published in early October 2011, this forward forecasted yield is below the MICAM floor. As of October 31, 2011, the historical rolling average yield for the 30-year Treasury Bonds was above the MICAM floor. For the historical rolling average yield of the 30-year Treasury Bonds to be below the MICAM floor at the end of November, the daily average yield for the month of November would need to be at or below 1.20 percent. For the historical rolling average yield of the 30-year Treasury Bonds to be below the floor at the end of December, the average of the average daily yields for the months of November and December would need to be at or below 2.81 percent. The yield on the 30-year Treasury Bonds as of October 31, 2011 was 3.16 percent. SDG&E REQUEST FOR AUTHORITY TO INVEST IN WIND FARM In July 2011, the CPUC approved a settlement agreement filed by SDG&E in April 2011 regarding SDG&E's request to make a tax equity investment in the holding company of a wind farm project. This approval allows SDG&E to make an investment after the wind farm project has met all of the conditions precedent set forth in the definitive documents and upon the initiation of commercial operation of the project. The approved investment, which would be included in the utility's rate base, is the lesser of $250 million or 64.99 percent of the project's costs. SDG&E would also make an incremental investment, to be excluded from the utility's rate base, of no less than 10 percent of the project's costs. SDG&E expects the project to be in commercial operation in late 2012. Federal Energy Regulatory Commission (FERC) approval of SDG&E's investment and the power purchase agreement is also required. SDG&E filed for this approval in October 2011. INSURANCE 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 2009/2010 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, 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 resulting from unforeseen circumstances. The CPUC's rules allow a utility to seek recovery of incurred costs that meet certain criteria, subject to a $5 million deductible per event. In April 2011, SDG&E filed a request for an incremental revenue requirement of $63 million for the 2010/2011 policy period. We expect a CPUC decision on this request by the end of 2011. In September 2011, SDG&E filed a request for $28 million for incremental insurance premiums incurred for the first six months of the 2011/2012 policy period. 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 Southern California Edison (SCE) and Pacific Gas & Electric (PG&E). In July 2010, the CPUC approved SDG&E's and SoCalGas' requests for separate regulatory accounts to record the subject expenses while the joint utility 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. A February 2011 ruling directing the utilities to show cause why the application should not be dismissed was stayed to permit continued settlement discussions between the four utilities and the CPUC and with the other parties to the proceeding. In June 2011, the CPUC issued a ruling scheduling evidentiary hearings in October with a decision in 2012. In September 2011, the CPUC delayed hearings to January 2012. We expect the settlement discussions to continue. SDG&E will also seek the recovery of costs incurred by SDG&E for the 2007 wildfire losses that are in excess of amounts recovered from its insurance coverage and other potentially responsible third parties. SDG&E believes that the approval of a new mechanism for cost recovery for wildfires could provide a framework for recovery of these costs. We provide additional information about 2007 wildfire litigation costs and their recovery in Note 10. 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 proceeding to examine what changes should be made to existing pipeline safety regulations for California natural gas pipelines. The Sempra Utilities are parties to this proceeding. The CPUC also appointed an independent review panel to make recommendations for possible actions by the CPUC in light of the San Bruno incident. The panel issued its report in June 2011 providing a number of conclusions regarding the San Bruno incident specifically, as well as general recommendations for pipeline operations and their oversight by regulatory agencies going forward. 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. This proceeding is being addressed separately from the 2012 GRC discussed above. The Sempra Utilities filed their Pipeline Safety Enhancement Plan in August 2011. The comprehensive plan covers all of the utilities' approximately 4,000 miles of transmission lines (3,750 miles for SoCalGas and 250 miles for SDG&E) and would be implemented in two phases: Phase 1 focuses on populated areas of SoCalGas' and SDG&E's service territories and would be implemented over a 10-year period, from 2012 to 2022. Phase 2 covers unpopulated areas of SoCalGas' and SDG&E's service territories and will be filed with the CPUC at a later date. The total cost estimate for Phase 1, over the 10-year period of 2012 to 2022, is $3.1 billion ($2.5 billion for SoCalGas and $600 million for SDG&E). In their August 2011 filing, the utilities requested the CPUC to authorize funding through 2015 of approximately $1.5 billion for SoCalGas, of which $1.2 billion would be capital investment, and $240 million for SDG&E, of which $230 million would be capital investment. After 2015, the utilities plan to include the costs of the Pipeline Safety Enhancement Plan in their General Rate Case. The utilities also proposed that the cost of the program be recovered through a surcharge, rather than by incorporating it into rates. The surcharge would increase over time, as more project work is completed. In January 2011, the National Transportation Safety Board (NTSB) issued seven safety recommendations in connection with its investigation into the cause of the San Bruno incident. According to the NTSB, these safety recommendations “were issued to address record-keeping problems that could create conditions in which a pipeline is operated at a higher pressure than the pipe was built to withstand.” In response to a request from the CPUC, each of the Sempra Utilities reviewed its pipeline facilities located or operating in populated or high consequence areas, as defined by the NTSB, to identify those segments that have not had the maximum allowable operating pressure (MAOP) established through prior hydrostatic testing. Federal and state regulations allow natural gas pipelines installed prior to July 1, 1970 to establish MAOPs through prior operating history rather than through a strength test, but strength tests are required on natural gas pipelines installed subsequent to June 30, 1970 as an element in establishing MAOPs. In response to the CPUC's request, the Sempra Utilities conducted a detailed review of 1,622 miles of pipelines (1,416 miles for SoCalGas and 206 miles for SDG&E) installed in the subject class locations, and on April 15, 2011, the Sempra Utilities submitted a report to the CPUC on the results of their review and the actions they are taking in response to the NTSB recommendations. The Sempra Utilities' records review process did not reveal any significant concerns with the currently established MAOP for their pipelines, and the Sempra Utilities intend to continue to operate their pipelines in a safe and prudent manner. AIR QUALITY AND GREENHOUSE GAS REGULATION The California Legislature enacted Assembly Bill 32 (AB 32) and California Senate Bill 1368 in 2006. These laws mandate, among other things, reductions in greenhouse gas (GHG) emissions and the payment of GHG administration fees annually. The California Air Resources Board (CARB), the agency responsible for establishing the compliance rules and regulations for the regulation of GHG under AB 32, has adopted a number of regulations pursuant to AB 32, including CARB's GHG administration fees regulation and its greenhouse gas emissions trading regulation. On October 20, 2011, the CARB finalized details of the cap and trade regulation authorized by AB 32.

SEMPRA UTILITIES' REGULATORY MATTERS

3 Months Ended

Sep. 30, 2011

Notes to Consolidated Financial Statements [Abstract]

NOTE 9. SEMPRA UTILITIES' REGULATORY MATTERS

POWER PROCUREMENT AND RESOURCE PLANNING

Renewable Energy

In 2010, certain California electric retail sellers, including SDG&E, were required to deliver 20 percent of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by both the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC), are known as the Renewables Portfolio Standard (RPS) Program. In April 2011, the Governor of California signed Senate Bill X1 2 (33% RPS Program), which goes into effect December 9, 2011 and supersedes the current RPS Program. It will require 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.

The 33% RPS Program contains new flexible compliance mechanisms, more restrictive than the prior mechanisms, that can be used to comply with or meet the 33% RPS Program mandates in 2011 and beyond. The new mechanisms provide for a CPUC waiver under certain conditions, including: 1) a finding of inadequate transmission, 2) delays in the start-up of commercial operations of renewable energy projects due to permitting or interconnection or 3) unexpected curtailment by an electric system balancing authority, such as the California Independent System Operator (ISO).

SDG&E continues to procure renewable energy supplies to achieve the 33% RPS Program requirements. A substantial number of these supply contracts, however, are contingent upon many factors, including:

access to electric transmission infrastructure;
timely regulatory approval of contracted renewable energy projects;
the renewable energy project developers' ability to obtain project financing and permitting; and

successful development and implementation of the renewable energy technologies.

For 2010, SDG&E satisfied its RPS procurement requirements through a combination of contracted deliveries and application of the flexible compliance mechanism, including the application of certain mechanisms that are no longer available under the 33% RPS Program. For 2011 and beyond, SDG&E believes it will be able to comply with the 33% RPS Program requirements based on its contracting activity and, if necessary, application of the new flexible compliance mechanisms. SDG&E's failure to comply with the RPS Program requirements could subject it to a CPUC-imposed penalty of 5 cents per kilowatt hour of renewable energy under-delivery.

SDG&E Purchase of El Dorado

SDG&E purchased Sempra Generation's El Dorado natural gas generation plant on October 1, 2011, pursuant to an option to acquire the plant that was exercised in 2007. In accordance with the CPUC's approval, SDG&E acquired El Dorado (now named Desert Star Energy Center) at a price equal to the closing book value of the plant upon transfer. SDG&E made a compliance filing with the CPUC in September 2011 stating the book value purchase price as $215 million. The final purchase price is subject to change pending completion of an independent audit of Sempra Generation's net book value of the plant as of the close of business on September 30, 2011. SDG&E expects this audit to be completed by year-end 2011.

East County Substation

In response to a CPUC application filed by SDG&E for authorization to proceed with the East County Substation project, the CPUC and Bureau of Land Management jointly issued a favorable final environmental impact report and environmental impact statement in October 2011. We expect a CPUC decision on this project in the first quarter of 2012. We provide additional detail on the East County Substation project and CPUC application in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

GENERAL RATE CASE (GRC)

The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the Sempra Utilities to recover their reasonable cost of operations and to provide the opportunity to realize their authorized rates of return on their investment. In December 2010, the Sempra 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. The CPUC issued a ruling in March 2011 setting the proceeding scope and schedule that projected a final CPUC decision around the month of March 2012 and granted the utilities' requests to establish regulatory accounts to allow recovery of their authorized 2012 revenue requirements retroactive to January 1, 2012.

In July 2011, the Sempra Utilities filed amendments to revise their original applications, primarily to reflect the impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. With these amendments, SDG&E is requesting a revenue requirement in 2012 of $1.845 billion, an increase of $231 million (or 14.3%) over 2011. SoCalGas is requesting a revenue requirement in 2012 of $2.107 billion, an increase of $263 million (14.3%) over 2011. The Division of Ratepayer Advocates and other intervening parties are recommending that the CPUC reduce the utilities' revenue requirements in 2012 by approximately 5 percent compared to 2011.

UTILITY INCENTIVE MECHANISMS

The CPUC applies performance-based measures and incentive mechanisms to all California utilities, under which the Sempra 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 15 of the Notes to Consolidated Financial Statements in the Annual Report, and updates below.

Natural Gas Procurement

In the third quarter of 2011, the CPUC approved and SoCalGas recorded SoCalGas' application for its Gas Cost Incentive Mechanism (GCIM) award of $6 million for natural gas procured for its core customers during the 12-month period ending March 31, 2010.

In June 2011, SoCalGas applied to the CPUC for approval of a 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 CPUC decision in the first half of 2012.

In the first quarter of 2010, SoCalGas recorded a GCIM award of $12 million for its procurement activities during the 12-month period ending March 31, 2009, approved by the CPUC in January 2010.

Energy Efficiency

The CPUC established incentive mechanisms that are based on the effectiveness of energy efficiency and demand side management programs. In June 2011, the Sempra Utilities filed requests with the CPUC seeking incentive awards of $15.1 million for SDG&E and $2.0 million for SoCalGas for their 2009 program year results. SDG&E's filing reflects changes that SDG&E believes were errors in the calculation method developed by the CPUC's Energy Division. The CPUC issued a ruling in September 2011 directing the Energy Division to issue a report confirming the amount of the utilities' incentive awards. The Energy Division issued its report on September 30, 2011 which acknowledged the calculation issues for SDG&E, but did not validate the incentive awards for either utility. SDG&E and SoCalGas continue to work with the Energy Division to validate the awards. We still expect a CPUC decision by the end of 2011.

The CPUC is also considering modifications to the incentive mechanism that would apply to the 2010 – 2012 program period, but has not established a schedule for a decision.

SOCALGAS COST OF CAPITAL

A cost of capital proceeding determines a utility's authorized capital structure and authorized rate of return, which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE). 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 Market Indexed Capital Adjustment Mechanism (MICAM). We provide more information about cost of capital in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

SoCalGas' cost of capital trigger mechanism 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 range of 3.88 percent (MICAM floor) to 6.88 percent (MICAM ceiling) 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 5.38 percent (SoCalGas' MICAM benchmark interest rate), 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 actual weighted average cost. Therefore, SoCalGas' authorized rate of return would adjust, upward or downward, as a result of all three cost adjustments.

Based on the Global Insight 12-month forward forecasted yield published in early October 2011, this forward forecasted yield is below the MICAM floor. As of October 31, 2011, the historical rolling average yield for the 30-year Treasury Bonds was above the MICAM floor. For the historical rolling average yield of the 30-year Treasury Bonds to be below the MICAM floor at the end of November, the daily average yield for the month of November would need to be at or below 1.20 percent. For the historical rolling average yield of the 30-year Treasury Bonds to be below the floor at the end of December, the average of the average daily yields for the months of November and December would need to be at or below 2.81 percent. The yield on the 30-year Treasury Bonds as of October 31, 2011 was 3.16 percent.

SDG&E REQUEST FOR AUTHORITY TO INVEST IN WIND FARM

In July 2011, the CPUC approved a settlement agreement filed by SDG&E in April 2011 regarding SDG&E's request to make a tax equity investment in the holding company of a wind farm project. This approval allows SDG&E to make an investment after the wind farm project has met all of the conditions precedent set forth in the definitive documents and upon the initiation of commercial operation of the project. The approved investment, which would be included in the utility's rate base, is the lesser of $250 million or 64.99 percent of the project's costs. SDG&E would also make an incremental investment, to be excluded from the utility's rate base, of no less than 10 percent of the project's costs. SDG&E expects the project to be in commercial operation in late 2012. Federal Energy Regulatory Commission (FERC) approval of SDG&E's investment and the power purchase agreement is also required. SDG&E filed for this approval in October 2011.

INSURANCE 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 2009/2010 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, 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 resulting from unforeseen circumstances. The CPUC's rules allow a utility to seek recovery of incurred costs that meet certain criteria, subject to a $5 million deductible per event.

In April 2011, SDG&E filed a request for an incremental revenue requirement of $63 million for the 2010/2011 policy period. We expect a CPUC decision on this request by the end of 2011. In September 2011, SDG&E filed a request for $28 million for incremental insurance premiums incurred for the first six months of the 2011/2012 policy period.

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 Southern California Edison (SCE) and Pacific Gas & Electric (PG&E). In July 2010, the CPUC approved SDG&E's and SoCalGas' requests for separate regulatory accounts to record the subject expenses while the joint utility 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. A February 2011 ruling directing the utilities to show cause why the application should not be dismissed was stayed to permit continued settlement discussions between the four utilities and the CPUC and with the other parties to the proceeding. In June 2011, the CPUC issued a ruling scheduling evidentiary hearings in October with a decision in 2012. In September 2011, the CPUC delayed hearings to January 2012. We expect the settlement discussions to continue.

SDG&E will also seek the recovery of costs incurred by SDG&E for the 2007 wildfire losses that are in excess of amounts recovered from its insurance coverage and other potentially responsible third parties. SDG&E believes that the approval of a new mechanism for cost recovery for wildfires could provide a framework for recovery of these costs.

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

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 proceeding to examine what changes should be made to existing pipeline safety regulations for California natural gas pipelines. The Sempra Utilities are parties to this proceeding. The CPUC also appointed an independent review panel to make recommendations for possible actions by the CPUC in light of the San Bruno incident. The panel issued its report in June 2011 providing a number of conclusions regarding the San Bruno incident specifically, as well as general recommendations for pipeline operations and their oversight by regulatory agencies going forward.

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. This proceeding is being addressed separately from the 2012 GRC discussed above. The Sempra Utilities filed their Pipeline Safety Enhancement Plan in August 2011. The comprehensive plan covers all of the utilities' approximately 4,000 miles of transmission lines (3,750 miles for SoCalGas and 250 miles for SDG&E) and would be implemented in two phases:

Phase 1 focuses on populated areas of SoCalGas' and SDG&E's service territories and would be implemented over a 10-year period, from 2012 to 2022.

Phase 2 covers unpopulated areas of SoCalGas' and SDG&E's service territories and will be filed with the CPUC at a later date.

The total cost estimate for Phase 1, over the 10-year period of 2012 to 2022, is $3.1 billion ($2.5 billion for SoCalGas and $600 million for SDG&E). In their August 2011 filing, the utilities requested the CPUC to authorize funding through 2015 of approximately $1.5 billion for SoCalGas, of which $1.2 billion would be capital investment, and $240 million for SDG&E, of which $230 million would be capital investment. After 2015, the utilities plan to include the costs of the Pipeline Safety Enhancement Plan in their General Rate Case. The utilities also proposed that the cost of the program be recovered through a surcharge, rather than by incorporating it into rates. The surcharge would increase over time, as more project work is completed.

In January 2011, the National Transportation Safety Board (NTSB) issued seven safety recommendations in connection with its investigation into the cause of the San Bruno incident. According to the NTSB, these safety recommendations “were issued to address record-keeping problems that could create conditions in which a pipeline is operated at a higher pressure than the pipe was built to withstand.” In response to a request from the CPUC, each of the Sempra Utilities reviewed its pipeline facilities located or operating in populated or high consequence areas, as defined by the NTSB, to identify those segments that have not had the maximum allowable operating pressure (MAOP) established through prior hydrostatic testing. Federal and state regulations allow natural gas pipelines installed prior to July 1, 1970 to establish MAOPs through prior operating history rather than through a strength test, but strength tests are required on natural gas pipelines installed subsequent to June 30, 1970 as an element in establishing MAOPs.

In response to the CPUC's request, the Sempra Utilities conducted a detailed review of 1,622 miles of pipelines (1,416 miles for SoCalGas and 206 miles for SDG&E) installed in the subject class locations, and on April 15, 2011, the Sempra Utilities submitted a report to the CPUC on the results of their review and the actions they are taking in response to the NTSB recommendations.

The Sempra Utilities' records review process did not reveal any significant concerns with the currently established MAOP for their pipelines, and the Sempra Utilities intend to continue to operate their pipelines in a safe and prudent manner.

AIR QUALITY AND GREENHOUSE GAS REGULATION

The California Legislature enacted Assembly Bill 32 (AB 32) and California Senate Bill 1368 in 2006. These laws mandate, among other things, reductions in greenhouse gas (GHG) emissions and the payment of GHG administration fees annually. The California Air Resources Board (CARB), the agency responsible for establishing the compliance rules and regulations for the regulation of GHG under AB 32, has adopted a number of regulations pursuant to AB 32, including CARB's GHG administration fees regulation and its greenhouse gas emissions trading regulation. On October 20, 2011, the CARB finalized details of the cap and trade regulation authorized by AB 32.