2.2.0.25falsefalse010900 - Disclosure - SEMPRA UTILITIES' REGULATORY MATTERStruefalsefalse1falsefalseUSDfalsefalse1/1/2011 - 3/31/2011 USD ($) $FROM_Jan01_2011_TO_Mar31_2011http://www.sec.gov/CIK0001032208duration2011-01-01T00:00:002011-03-31T00:00:00PureStandardhttp://www.xbrl.org/2003/instancepurexbrli0USDStandardhttp://www.xbrl.org/2003/iso4217USDiso42170SharesStandardhttp://www.xbrl.org/2003/instancesharesxbrli0USDUSD$2true0sre_NotesToConsolidatedFinancialStatementsAbstractsrefalsenadurationNo definition available.falsefalsefalsefalsefalsefalsefalsefalsefalsefalse1falsefalsefalse00falsefalsefalsefalsefalseOtherxbrli:stringItemTypestringNo definition available.falsefalseNotes to Consolidated Financial Statements [Abstract]3false0us-gaap_PublicUtilitiesDisclosureTextBlockus-gaaptruenadurationNo definition available.falsefalsefalsefalsefalsefalsefalsefalsefalsefalse1falsefalsefalse00NOTE 9. SEMPRA UTILITIES' REGULATORY MATTERSPOWER PROCUREMENT AND RESOURCE PLANNINGRenewable EnergyIn 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 (2011 RPS Program) which, when in effect, will supersede the RPS Program and 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. We expect the 2011 RPS Program to become effective in the second quarter of 2011, and certain implementation details will be addressed by the CPUC.The 2011 RPS Program contains new flexible compliance mechanisms, more restrictive than the prior mechanisms, that can be used to comply with or meet the 2011 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 or 2) delays in the start-up of commercial operations of renewable energy projects due to permitting or interconnection. SDG&E continues to procure renewable energy supplies to achieve the 2011 RPS Program requirements. A substantial number of these supply contracts, however, are contingent upon many factors, including: <ul><li style="margin-left:9.35px;list-style:square;">access to electric transmission infrastructure; </li><li style="margin-left:9.35px;list-style:square;">timely regulatory approval of contracted renewable energy projects; </li><li style="margin-left:9.35px;list-style:square;">the renewable energy project developers' ability to obtain project financing and permitting; and </li></ul><ul><li style="margin-left:9.35px;list-style:square;">successful development and implementation of the renewable energy technologies. </li></ul>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 2011 RPS Program. For 2011 and beyond, SDG&E believes it will be able to comply with the 2011 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. 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. We provide further detail about the GRC applications in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.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 ProcurementIn June 2010, SoCalGas applied to the CPUC for approval of a Gas Cost Incentive Mechanism (GCIM) award of $6 million for natural gas procured for our core customers during the 12-month period ending March 31, 2010. SoCalGas expects a CPUC decision in the third quarter of 2011. In the first quarter of 2010, SoCalGas recorded a GCIM award of $12 million for SoCalGas' 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. The Sempra Utilities plan to file requests with the CPUC in June 2011 for any incentive awards for the 2009 program year with a decision expected in 2012. The CPUC is also considering modifications to the incentive mechanism that would apply to the 2012 – 2014 program period. We expect a decision on these program modifications in 2011.SDG&E REQUEST FOR AUTHORITY TO INVEST IN WIND FARMIn July 2010, SDG&E filed a request with the CPUC seeking authority to make a tax equity investment in the holding company of a wind farm project. In April 2011, SDG&E filed a settlement agreement with the CPUC resolving all issues with the parties in the proceeding. If the CPUC approves the settlement agreement as filed, SDG&E would 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, which would be included in the utility's rate base in an amount not to exceed 64.99 percent of the project costs or an aggregate amount of $250 million. 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 costs. We expect a CPUC decision on the settlement agreement in mid-2011, and the project to be in commercial operation in the second half of 2012.INSURANCE COST RECOVERYSDG&E filed a request 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 requested a $29 million revenue requirement for the incremental increase in its general liability and wildfire liability insurance premium costs for the 2009/2010 policy period and proposed a mechanism for recovery of future liability insurance costs incurred in the 2010/2011 policy period and the first six months of the 2011/2012 policy period. 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 December 2010, the CPUC approved SDG&E's request for the $29 million revenue requirement, which was implemented in rates effective January 1, 2011, and 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. SDG&E filed a request in April 2011 for an incremental revenue requirement of $63 million for the 2010/2011 policy period. We expect a CPUC decision on the request in the second half of 2011. SDG&E also plans to file a request in the third quarter of 2011 for any incremental insurance premiums incurred for the first six months of the 2011/2012 policy period. EXCESS WILDFIRE CLAIMS COST RECOVERYSDG&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. 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 future wildfires will provide a framework for discussions on recovery of these costs. We provide additional information about 2007 wildfire litigation costs and their recovery in Note 10. NATURAL GAS PIPELINE OPERATIONS SAFETY ASSESSMENTSAs 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. Those recommendations may include changes to design, construction, operation and maintenance practices of natural gas facilities in California. The report of the independent review panel is expected in the second quarter of 2011.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. NOTE 9. 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