California's legislative response to the 2000 – 2001 energy crisis resulted in the DWR purchasing a substantial portion of power for California's electricity users. In 2001, the DWR entered into long-term contracts with suppliers, including Sempra Natural Gas, to provide power for the utility procurement customers of each of the California investor-owned utilities (IOUs), including SDG&E. The CPUC allocates the power and its administrative responsibility, including collection of power contract costs from utility customers, among the IOUs.

Effective in 2003, the IOUs resumed responsibility for electric commodity procurement above their allocated share of the DWR's long-term contracts, and the CPUC:

This process is intended to identify anticipated needs for generation and transmission resources in order to support transmission grid reliability and to better serve customers.

In 2010, the State of California required certain California electric retail sellers, including SDG&E, to deliver 20 percent of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by both the CPUC and the California Energy Commission (CEC), are known as the Renewables Portfolio Standard (RPS) Program. In December 2011, California Senate Bill 2(1X) (33% RPS Program) went into effect, superseding the previous RPS Program. It 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.

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:

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 purchased Sempra Natural Gas' 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 was $214 million based on the completion of an independent audit of Sempra Natural Gas' net book value of the plant as of the close of business on September 30, 2011.

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. The project, which will include construction of a new 500/230/138- kilovolt (kV) substation, rebuilding of the existing Boulevard Substation and construction of a new 138-kV transmission line connecting the two substations, is estimated to cost approximately $435 million. It would allow interconnections from new renewable-generation sources and enhance the reliability of electric service to a number of communities. We expect a CPUC decision on this project in the first half of 2012.

Edison (78.21%), SDG&E (20%) and the city of Riverside (1.79%) jointly own SONGS. Edison completed the replacement of the steam generators at San Onofre Units 2 and 3 in April 2010 and February 2011, respectively. The final phase of the project, disposal of the old steam generators, is planned to be completed in 2012. SDG&E's share of the capital investment in this project is $180 million, including $160 million incurred through December 31, 2011. The CPUC approved SDG&E's participation in the replacement project. SDG&E has requested continuation of full recovery of current operating and maintenance costs via balancing account treatment in its 2012 General Rate Case application, discussed below.

The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment. In December 2010, the California Utilities filed their 2012 General Rate Case (GRC) applications to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. Both SDG&E and SoCalGas filed revised applications with the CPUC in July 2011. Evidentiary hearings were completed in January 2012 and final briefs reflecting the results from these hearings are scheduled to be filed with the CPUC by May 1, 2012. The final decision for the 2012 GRC will be made effective retroactive to January 1, 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. 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 and other intervening parties are recommending that the CPUC reduce the utilities' revenue requirements in 2012 by approximately 5 percent compared to 2011.

The CPUC applies performance-based measures and incentive mechanisms to all California IOUs. Under these, the California Utilities have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties. Both SDG&E and SoCalGas have incentive mechanisms associated with:

Incentive awards are included in our earnings when we receive any required CPUC approval of the award. We would record penalties for results below the specified benchmarks in earnings when we believe it is more likely than not that the CPUC would assess a penalty.

UTILITY INCENTIVE AWARDS 2009-2011
(Dollars in millions)
	Years ended December 31,
	2011		2010		2009
Sempra Energy Consolidated
Energy efficiency and demand side management	$	16	$	15	$	2
Unbundled natural gas storage and hub services		4		15		19
Natural gas procurement		6		12		7
Operational incentives		3		1		1
Total awards	$	29	$	43	$	29
SDG&E
Energy efficiency and demand side management	$	14	$	5	$	―
Operational incentives		1		1		1
Total awards	$	15	$	6	$	1
SoCalGas
Energy efficiency and demand side management	$	2	$	10	$	2
Unbundled natural gas storage and hub services		4		15		19
Natural gas procurement		6		12		7
Operational incentives		2		―		―
Total awards	$	14	$	37	$	28

The CPUC established incentive mechanisms that are based on the effectiveness of energy efficiency and demand side management programs. In December 2009, the CPUC awarded $0.3 million and $2.1 million to SDG&E and SoCalGas, respectively, for their performance during the 2006 – 2008 program period. In February 2010, the California Utilities filed a petition with the CPUC to correct errors in the computation of these awards. In December 2010, the CPUC additionally awarded $5.1 million and $9.9 million to SDG&E and SoCalGas, respectively, as the final true-up incentive awards for the 2006 – 2008 program period, which amounts incorporate the California Utilities' petition to correct computational errors.

In December 2011, the CPUC awarded $13.7 million to SDG&E and $2.0 million to SoCalGas for their 2009 program year results.

The CPUC has not yet established a schedule for reviewing and approving incentive awards for the 2010 – 2012 program period. The CPUC is also considering modifications to the incentive mechanism that would apply to future program periods (2013 and beyond), but has not established a schedule for a decision.

The California Utilities procure natural gas on behalf of their core natural gas customers. The CPUC has established incentive mechanisms to allow the California Utilities the opportunity to share in the savings and/or costs from buying natural gas for their core customers at prices below or above monthly market-based benchmarks. In 2008, the SDG&E and SoCalGas core natural gas supply portfolios were combined, and SoCalGas now procures natural gas for SDG&E's core natural gas customers' requirements. All SDG&E assets associated with its core natural gas supply portfolio were transferred or assigned to SoCalGas. Accordingly, SDG&E's incentive mechanism for natural gas procurement awards or penalties ended as of the effective date of the combination of the core natural gas supply portfolios, and SoCalGas' gas cost incentive mechanism (GCIM) is applied on the combined portfolio basis going forward.

In September 2011, the CPUC approved SoCalGas' application for its 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 January 2010, the CPUC approved a GCIM award of $12 million for SoCalGas' procurement activities during the 12-month period ending March 31, 2009.

The CPUC has established a revenue sharing mechanism which provides for the sharing between ratepayers and SoCalGas (shareholders) of the net revenues generated by SoCalGas' unbundled natural gas storage and system operator hub services. Annual net revenues (revenues less allocated service costs) are shared on a graduated basis, as follows:

The CPUC may establish operational incentives and associated performance benchmarks as part of a general rate case or cost of service proceeding. Through the end of 2011, the California Utilities had operational incentives that applied to their performance in the area of employee safety.

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 rate of return is the rate that the California Utilities may earn on their 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's authorized ROE is 11.10 percent and its authorized ROR is 8.40 percent. SDG&E's current authorized capital structure is

Unless the benchmark interest rates, as described below, change from current levels, the authorized ROE and ROR will remain in effect until SDG&E's next cost of capital proceeding is completed. SDG&E's next cost of capital application is scheduled to be filed in April 2012 for a 2013 test year, consistent with the schedule for cost of capital applications for each of Edison and Pacific Gas and Electric Company (PG&E).

SoCalGas' authorized ROE is 10.82 percent and its authorized ROR is 8.68 percent. These rates continue to be effective until market interest rate changes are large enough to trigger an automatic adjustment or until either the CPUC orders a periodic review or SoCalGas files a cost of capital application. In its 2012 GRC application, SoCalGas advised the CPUC that it plans to file a cost of capital application in April 2012 for a 2013 test year, at the same time as the other California IOUs. SoCalGas' current authorized capital structure is

In addition to establishing the authorized ROR, 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 cost of capital proceedings. SDG&E's cost of capital 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 the range of 5.02 percent to 7.02 percent, SDG&E's authorized rate of return would be adjusted, upward or downward, by one-half of the difference between the 12-month average and 6.02 percent (SDG&E's benchmark interest rate), effective January 1 following the year in which the benchmark range was exceeded. 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.

SoCalGas' cost of capital trigger mechanism (the Market Indexed Capital Adjustment Mechanism or 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 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 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.

At December 31, 2011, neither SDG&E's nor SoCalGas' benchmark range has 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 early February 2012 is also below the MICAM floor. Therefore, SoCalGas' MICAM mechanism calls for an adjustment of its 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. However, as SoCalGas has advised the CPUC of its plan to file a cost of capital application in April 2012 along with the other California IOUs, SoCalGas expects that the decision from this cost of capital application will supersede the rates that would result from the MICAM trigger. As there haven't been any objections raised to SoCalGas' proposal to file a cost of capital application, management believes that the CPUC will accept SoCalGas' application. Absent a SoCalGas cost of capital application and proceeding, 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 8.05 percent, a reduction of 63 basis points from its current authorized ROR.

SDG&E's project to install advanced meters with integrated two-way communications functionality, including electric remote disconnect and home area network capability, was substantially completed by the end of 2011.

In April 2010, the CPUC issued a decision approving SoCalGas' application to upgrade approximately six million natural gas meters with an advanced metering infrastructure (AMI), subject to certain safeguards to better ensure its cost effectiveness for ratepayers. The approved cost of the project is $1.05 billion (including approximately $900 million in capital investment), with SoCalGas being subject to risk/reward sharing for costs above or below this amount. Installation of the meters is expected to begin in early 2013 and continue through mid 2017.

In November 2011, the Division of Ratepayer Advocates (DRA) and The Utility Reform Network (TURN) filed a joint petition requesting that the CPUC reconsider its prior approval of SoCalGas' AMI project and stay AMI deployment while the CPUC considers the request. The CPUC has taken no action in response to the DRA/TURN request, and SoCalGas is continuing its deployment of AMI pursuant to the April 2010 CPUC decision.

In July 2011, the CPUC approved a settlement agreement regarding SDG&E's request to make a tax equity investment in the holding company of a wind farm project. In December 2011, the Federal Energy Regulatory Commission (FERC) approved SDG&E's involvement in the project and the associated power purchase agreement. These approvals allow 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.

In October 2010, the CPUC issued a decision approving a settlement agreement between SDG&E and the DRA, authorizing SDG&E to recover $43 million of capital costs incurred to replace and repair company facilities under CPUC jurisdiction damaged by the October 2007 wildfires. This decision was in response to an application that SDG&E filed with the CPUC in March 2009 seeking to recover $49.8 million of incremental costs ($43 million of capital costs and $6.8 million of operation and maintenance costs).

SDG&E also incurred $30.1 million of incremental costs for the replacement and repair of company facilities under FERC jurisdiction, which are currently being recovered in SDG&E's electric transmission rates.

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 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 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 2011, the CPUC approved SDG&E's request for an incremental revenue requirement of $63 million for the 2010/2011 policy period. SDG&E recorded the revenue resulting from this decision in the fourth quarter of 2011. In addition, SDG&E's fourth quarter 2011 earnings include revenue to recover $28 million of incremental insurance premiums incurred in the six month period of July through December 2011 for which a final decision from the CPUC is pending. We expect a CPUC decision on this request in the second quarter of 2012.

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. 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. 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. We expect a 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 15.

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. 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. 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. 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:

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 for the recovery of costs 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 proposed to include the costs of the PSEP in their next General Rate Case (for their authorized revenue requirements in 2016). 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 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 the TCAP, SDG&E and SoCalGas will, among other things, seek to: (1) establish and revise gas rates to reflect updated customer class allocations of each company's respective base margin costs authorized in the most recent GRC; (2) update demand forecasts; and (3) support continuation of balancing account treatment for noncore transportation revenue requirements. In February 2012, the assigned Commissioner to the TCAP issued a scoping memo for the companies' TCAP, including their PSEP. This scoping memo sets evidentiary hearings for the first phase of the TCAP, which addresses the scope and reasonableness of the PSEP, in the third quarter of 2012, with briefs scheduled to be filed early in the fourth quarter of 2012.

On January 17, 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 (once a schedule is established). Generally, the report found that the PSEP approach to pipeline replacement and pressure testing and other proposed enhancements is reasonable.

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

In October 2011, the California legislature enacted five separate legislative bills (SB44, SB216, SB705, SB879 and AB56) that address natural gas pipeline safety. Each bill addresses a different aspect of natural gas pipeline safety and imposes requirements on the CPUC and the natural gas pipeline operator. These include such things as the development of a safety plan; installation of automatic shut-off and remote controlled gas valves; emergency response; reporting; ratemaking; and increasing the maximum penalty for gas pipeline safety violations. Much of the legislation is addressed by the utility safety plans being reviewed by the CPUC, and the California Utilities do not expect that the legislation will have a material impact on their results of operations, financial condition or cash flows.

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 GHG emissions trading regulation.

On October 20, 2011, the CARB finalized details of the cap and trade regulation authorized by AB 32. CARB intends to implement its cap and trade program in 2013. Certain legal challenges have been raised regarding the implementation of cap and trade (Associations of Irritated Residents, et al. v. California Air Resources Board). In September 2011, the California Supreme Court declined to immediately halt implementation of the CARB's cap and trade program. The Supreme Court's decision was limited only to a stay application before the California Court of Appeals, and was not a ruling on the merits of the legal challenges against cap and trade, which is still subject to appeal. No injunction has been issued by any court delaying adoption of the cap and trade program and it is currently proceeding.

These legislative and regulatory mandates could affect costs and growth at the California Utilities and at our natural gas-fired power plants in Arizona and Mexico. Any cost impact at the California Utilities is expected to be recoverable through rates. As discussed in Note 15 under “Environmental Issues,” compliance with this and similar legislation could adversely affect our Sempra Natural Gas and Sempra Mexico segments. However, such legislation could also have a positive impact on our natural gas and renewables businesses because of an increasing preference for natural gas and renewables for electric generation, as opposed to other sources.