SUMMARY OF SDG&E NET BOOK INVESTMENT AND RATE BASE INVESTMENT IN SONGS(1)
(Dollars in millions)
			Unit 2		Unit 3		Common Plant		Total
Net book investment:
	Net property, plant and equipment, including
	construction work in progress	$	152	$	115	$	120	$	387
	Materials and supplies		―		―		10		10
	Nuclear fuel		―		―		115		115
	Net book investment	$	152	$	115	$	245	$	512

Rate base investment		$	103	$	93	$	79	$	275
(1)	Excludes nuclear decommissioning-related assets and liabilities.

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

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

Because a final decision for the 2012 GRC was not issued in 2012, the California Utilities have recorded 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 expect a final CPUC decision for the 2012 GRC, which will be made effective retroactive to January 1, 2012, in the first half of 2013.

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 use in establishing rates to recover the cost of debt and equity used to finance their investment in electric and natural gas distribution, natural gas transmission and electric generation assets. In addition, a cost of capital proceeding also addresses the automatic ROR adjustment mechanism which applies market-based benchmarks to determine whether an adjustment to the authorized ROR is required during the interim years between cost of capital proceedings.

SDG&E and SoCalGas filed separate applications with the CPUC in April 2012 to update their cost of capital effective January 1, 2013. Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E) also filed separate cost of capital applications with the CPUC. SDG&E proposed to adjust its authorized capital structure by increasing the amount of its common equity from 49.0 percent to 52.0 percent. SDG&E also proposed to lower its authorized ROE from 11.1 percent to 11.0 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.40 percent to 8.15 percent. SoCalGas proposed to adjust its authorized capital structure by increasing the amount of its common equity from 48.0 percent to 52.0 percent. SoCalGas also proposed to increase its authorized ROE from 10.82 percent to 10.9 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.68 percent to 8.44 percent. In addition, SDG&E proposed to continue its currently approved cost of capital adjustment mechanism, which uses a utility bond benchmark. SoCalGas proposed switching from its current cost of capital adjustment mechanism, which is based on U.S. Treasury Bonds, to a mechanism using the same utility bond benchmark as SDG&E. Both SDG&E and SoCalGas proposed adding 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 addressed each utility's cost of capital for 2013, with a final decision issued in December 2012, details of which follow. Phase 2 addresses the cost of capital adjustment mechanisms for SDG&E, SoCalGas, Edison and PG&E, with a final decision expected in the first half of 2013.

The CPUC's final decision for Phase 1 authorized the capital structure and rates of returns as outlined in the table below:

COST OF CAPITAL FINAL DECISION RECAP

SDG&E				SoCalGas
Authorized Weighting	Authorized Rate of Recovery	Weighted Authorized ROR		Authorized Weighting	Authorized Rate of Recovery	Weighted Authorized ROR
45.25%	5.00%	2.26%	Long-Term Debt	45.60%	5.77%	2.63%
2.75%	6.22%	0.17%	Preferred Stock	2.40%	6.00%	0.14%
52.00%	10.30%	5.36%	Common Equity	52.00%	10.10%	5.25%
100.00%		7.79%		100.00%		8.02%

These newly authorized rates of returns are effective January 1, 2013 and, when compared to the rates of returns that were in effect through December 31, 2012, will result in a reduction of SDG&E's and SoCalGas' annual authorized revenue by $34 million and $22 million, respectively.

SDG&E, SoCalGas, PG&E, Edison and the DRA sponsored a joint stipulation in Phase 2 of the proceeding. As proposed, SDG&E would retain its current cost of capital adjustment mechanism, discussed below, and SoCalGas would implement this same adjustment mechanism. Both utilities would forgo their proposed off-ramp provision. The joint stipulation is unopposed and was accepted into the record of the proceeding at an evidentiary hearing in January 2013. A draft decision was issued on February 22, 2013 approving the joint stipulation as submitted. A final CPUC decision is expected in the second quarter of 2013.

SDG&E's current, and SoCalGas' proposed, 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 the 12-month average falls outside of a specified range, then the utility'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, the utility's authorized recovery rate for the cost of debt and preferred stock would also be adjusted to their respective actual weighted average cost. Therefore, for intervening years between scheduled cost of capital updates, the utility'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.

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, but the associated cost recovery and return of and on invested capital will be determined as part of the Triennial Cost Allocation Proceeding (TCAP), as we discuss below. 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' 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 on the California Utilities' PSEP. The report, along with testimony and evidentiary hearings, will be used to evaluate the PSEP in the regulatory process. Generally, the report found that the PSEP approach to pipeline replacement and pressure testing and other proposed enhancements is reasonable.

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

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

In December 2012, the CPUC issued a final decision accepting the utility safety plans filed pursuant to SB 705.

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 reviewed and approved by the CPUC in December 2012, 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 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. 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 2010-2012
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
Sempra Energy Consolidated
Energy efficiency	$	6	$	16	$	15
Unbundled natural gas storage and hub services		3		4		15
Natural gas procurement		6		6		12
Operational incentives		5		3		1
Total awards	$	20	$	29	$	43
SDG&E
Energy efficiency	$	3	$	14	$	5
Operational incentives		2		1		1
Total awards	$	5	$	15	$	6
SoCalGas
Energy efficiency	$	3	$	2	$	10
Unbundled natural gas storage and hub services		3		4		15
Natural gas procurement		6		6		12
Operational incentives		3		2		―
Total awards	$	15	$	14	$	37

The CPUC established incentive mechanisms that are based on the effectiveness of energy efficiency programs. In December 2010, the CPUC 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 incorporated 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 issued a final decision in December 2012 adopting a mechanism for the 2010 – 2012 program cycle and approving shareholder awards of $3.3 million for SDG&E and $2.7 million for SoCalGas for their energy efficiency program performance in 2010 under the mechanism. The decision established an annual process for the utilities to obtain awards for their performance in 2011 and 2012. Incentives for the 2011 and 2012 program years would be awarded in 2013 and 2014, respectively.

We expect a final decision on an incentive mechanism for the 2013 – 2014 program period in 2013.

The CPUC has established a revenue sharing mechanism, effective through 2014, 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. SoCalGas is seeking to extend the mechanism through 2015. Annual net revenues (revenues less allocated service costs) under the mechanism are shared on a graduated basis, as follows:

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. SoCalGas procures natural gas for SDG&E's core natural gas customers' requirements. SoCalGas' gas cost incentive mechanism (GCIM) is applied on the combined portfolio basis.

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.

In the first quarter of 2012, the CPUC approved and SoCalGas recorded SoCalGas' application for its GCIM award of $6.2 million for natural gas procured for its core customers during the 12-month period ending March 31, 2011.

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 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 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. Any performance incentives for 2012 and thereafter would be established in the California Utilities' GRC proceeding, currently pending before the CPUC.

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.

In October 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 by numerous parties regarding the implementation of cap and trade. No injunction has been issued by any court delaying adoption of the cap and trade program and it is proceeding forward.

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.

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 a result of these findings, Edison has plugged and removed from service all tubes showing excessive wear in each of the steam generators. In addition, Edison has preventively plugged all tubes in contact with the retainer bars or in the area of the tube bundles where tube-to-tube contact occurred. As of the filing date of this report, both Units 2 and 3 remain offline.

Any remedial action that will permit restart of one or both of the Units will need to be approved by the NRC. In March 2012, the NRC issued a Confirmatory Action Letter (CAL) that required NRC permission to restart Unit 2 and Unit 3 and outlined actions that Edison must complete before permission to restart either Unit may be sought. The NRC could also choose to impose additional inspections and assessment processes that could result in significant costs or additional delay. In October 2012, Edison submitted a restart plan to the NRC for Unit 2, proposing to operate Unit 2 at a reduced power level for five months and then shut it down for further inspection. The plan submitted to the NRC does not address Unit 3. It is not clear at this time whether Unit 3 can be restarted without extensive additional repairs, and Edison has not indicated when it believes Unit 3 may be ready to restart operations. The timing of the restart of either of the Units is dependent upon approval by the NRC. The NRC may employ other procedures before making any determination about whether to grant permission pursuant to the terms of the CAL. 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 CAL or whether any such request would be granted in whole or in part.

Through December 31, 2012, SDG&E's proportional investment in the steam generators, net of accumulated depreciation, was approximately $179 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, in excess of avoided nuclear fuel costs, incurred by SDG&E as a result of the unscheduled SONGS outage (commencing in 2012 on January 31 for Unit 3 and March 5 for Unit 2) through December 31, 2012 were approximately $77 million. Total replacement power costs will not be known until the Units are returned to service.

Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. For the year ended December 31, 2012, SDG&E has recognized (and collected through customer rates) an estimated $199 million of revenue associated with its investment in SONGS and related operating costs. Following is a summary of SDG&E's December 31, 2012 net book investment, excluding any decommissioning-related assets and liabilities, and its rate base investment in SONGS:

SUMMARY OF SDG&E NET BOOK INVESTMENT AND RATE BASE INVESTMENT IN SONGS(1)
(Dollars in millions)
			Unit 2		Unit 3		Common Plant		Total
Net book investment:
	Net property, plant and equipment, including
	construction work in progress	$	152	$	115	$	120	$	387
	Materials and supplies		―		―		10		10
	Nuclear fuel		―		―		115		115
	Net book investment	$	152	$	115	$	245	$	512

Rate base investment		$	103	$	93	$	79	$	275
(1)	Excludes nuclear decommissioning-related assets and liabilities.

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

Under Section 455.5, any determination to adjust rates would be made after hearings are conducted in connection with Edison's 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.

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

The steam generators were designed and supplied by Mitsubishi Heavy Industries (MHI) and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. 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 $138 million and excludes consequential damages, defined to include the cost of replacement power. Such limitations in the contract are subject to certain exceptions. In late 2012, Edison submitted invoices on behalf of all owners to MHI in the aggregate amount of $53 million for certain steam generator repair costs incurred, of which MHI has paid $45 million but reserved the right to challenge any of the charges in the invoice. In January 2013, MHI advised Edison that it rejected a portion of the first invoice and required further documentation regarding the remainder of the invoice. Edison expects to continue to invoice MHI for any additional costs incurred.

SDG&E is a named insured on the Edison insurance policies covering SONGS. These policies, issued by Nuclear Electric Insurance Limited (NEIL), cover nuclear property and non-nuclear property damage at the SONGS facility, as well as accidental outage insurance. Edison has placed NEIL on notice of potential claims for loss recovery. In October 2012, Edison submitted to NEIL a Partial Proof of Loss on behalf of Edison, SDG&E and the City of Riverside in connection with the outages of SONGS Units 2 and 3. The NEIL policies contain a number of exclusions and limitations that may reduce or eliminate coverage. SDG&E will assist Edison in pursuing claims recoveries from NEIL, as well as warranty claims with MHI, but there is no assurance that SDG&E will recover all or any of its applicable costs pursuant to these arrangements. We provide additional information about insurance related to SONGS in Note 15.

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.

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. The last of these contracts expires in 2013.

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.

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.

The 33% RPS Program contains flexible compliance mechanisms that can be used to comply with or meet the 33% RPS Program mandates in 2011 and beyond. The 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:

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 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 filed an application with the CPUC in October 2012 for a permit to construct various transmission replacement projects in and around the Cleveland National Forest. The proposed projects will replace and fire-harden five transmission lines at an estimated cost of $420 million. The projects are subject to federal review by the U.S. Forest Service (USFS). A joint environmental report (EIR/EIS) will be developed by the CPUC and USFS. SDG&E has requested a CPUC decision approving the transmission projects by the third quarter of 2013. We expect the projects to be in service by 2017.

SDG&E filed an application with the CPUC in May 2012 for a Certificate of Public Convenience and Necessity (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 expects a final CPUC decision approving the estimated $473 million project in the second half 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.

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) issued its record of decision in August 2012. SDG&E expects to begin construction by the second quarter of 2013 and the substation to be placed in service in 2014.

SDG&E purchased Sempra Natural Gas' El Dorado gas-fired electric 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 (renamed 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.

SDG&E submitted its Electric Transmission Formula Rate (TO4) filing with the FERC in February 2013 to be effective September 1, 2013. This proceeding will set the rate making methodology and rate of return for SDG&E's FERC-regulated electric transmission operations and assets. SDG&E's TO4 filing is requesting a rate making formula that is essentially the same as currently authorized by the FERC. SDG&E's TO4 filing is requesting: 1) rates to be determined by a base period of historical costs and a forecast of capital investments and 2) a true-up period which is similar to a balancing account that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including it authorized return on investment.

This TO4 proceeding will also set SDG&E's authorized ROE on FERC rate base. SDG&E's current authorized FERC ROE is 11.35 percent and SDG&E's TO4 filing is proposing a FERC ROE of 11.3 percent. SDG&E expects a decision on its TO4 filing in the second half of 2013.

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, 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 December 31, 2012 reflects the expected recovery of the cost of the incremental wildfire insurance premiums incurred in the current year.

SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC in August 2009 proposing a new framework and mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. 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 was 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. Legal briefs were completed in March 2012.

In December 2012, the CPUC issued a final decision that ultimately did not approve the proposed blanket framework for the utilities but allowed SDG&E to maintain its authorized memorandum account, so that SDG&E may file applications with the CPUC requesting recovery of amounts properly recorded in the memorandum account at a later time, subject to reasonableness review.

SDG&E intends to pursue recovery of such costs in a future application. SDG&E will continue to assess the potential for recovery of these costs in rates. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated as of December 31, 2012, the resulting after-tax charge against earnings would have been up to $190 million. In addition, in periods following any such conclusion, SDG&E's earnings will be adversely impacted by increases in the estimated cost to litigate or settle pending wildfire claims. We discuss how we assess the probability of recovery of our regulatory assets in Note 1.

We provide additional information about 2007 wildfire litigation costs and their recovery in Note 15.

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 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. We expect a final EIR and CPUC decision on the estimated $200 million project in 2013.

In November 2011, the DRA and The Utility Reform Network (TURN) filed a joint petition requesting that the CPUC reconsider its prior approval of SoCalGas' advanced metering infrastructure (AMI) project and stay AMI deployment while the CPUC considers the request. The CPUC, which is not obligated to respond to such requests, has taken no action in response to the DRA/TURN petition, and SoCalGas is continuing its deployment of AMI pursuant to the April 2010 CPUC decision approving the project.