CALIFORNIA UTILITIES' REGULATORY MATTERS	3 Months Ended
Sep. 30, 2013
Notes to Consolidated Financial Statements [Abstract]
Sempra Utilities' Regulatory Matters	NOTE 9. CALIFORNIA UTILITIES' REGULATORY MATTERS We discuss matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and details of any new matters below. JOINT MATTERS CPUC General Rate Case (GRC) The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment. In December 2010, the California Utilities filed their 2012 General Rate Case (2012 GRC) applications to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements would change on an annual basis over the subsequent three-year (2013-2015) period. In May 2013, the CPUC approved a final decision (Final GRC Decision) in the California Utilities' 2012 GRC. The Final GRC Decision establishes a 2012 revenue requirement of $1.733 billion for SDG&E and $1.959 billion for SoCalGas. This represents an increase of $119 million (7.4 percent) and $115 million (6.2 percent) over SDG&E's and SoCalGas' authorized 2011 revenue requirements, respectively. The Final GRC Decision is effective retroactive to January 1, 2012, and SDG&E and SoCalGas recorded the cumulative earnings effect of the retroactive application of the Final GRC Decision of $69 million and $37 million, respectively, in the second quarter of 2013. For SDG&E and SoCalGas, respectively, these amounts include an incremental earnings impact of $52 million and $25 million related to 2012 and $17 million and $12 million related to the first quarter of 2013. The amount of revenue associated with the retroactive period is expected to be recovered in SDG&E's rates over a 28-month period beginning in September 2013, and in SoCalGas' rates over a 31-month period beginning in June 2013. At September 30, 2013, SDG&E reported on its Condensed Consolidated Balance Sheet $366 million as a regulatory asset, with $203 million classified as noncurrent, representing the retroactive revenue from the Final GRC Decision to be recovered by SDG&E in rates during the period September 2013 through December 2015. At September 30, 2013, SoCalGas reported on its Condensed Consolidated Balance Sheet a regulatory asset of $117 million, with $65 million as noncurrent, representing the retroactive revenue from the Final GRC Decision to be recovered in rates through December 2015. The Final GRC Decision also establishes a four-year GRC period (through 2015) with a revenue attrition mechanism for the escalation of the adopted revenue requirements for years 2013, 2014, and 2015 based on fixed annual factors of 2.65 percent, 2.75 percent and 2.75 percent, respectively. For SDG&E, the Final GRC Decision also provides the revenue requirement for cost recovery of wildfire insurance premiums beginning January 1, 2012, as we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. We provide additional information regarding the 2012 GRC in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. CPUC Cost of Capital A cost of capital proceeding determines a utility's authorized capital structure and authorized rate of return on rate base (ROR), which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE), weighted on a basis consistent with the authorized capital structure. 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. 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, which granted SDG&E and SoCalGas an authorized ROR of 7.79 percent and 8.02 percent, respectively. The CPUC-authorized ROR in effect prior to the effective date of this decision was 8.40 percent for SDG&E and 8.68 percent for SoCalGas. We provide additional details regarding the cost of capital proceeding in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. Phase 2 addressed the cost of capital adjustment mechanisms for SDG&E, SoCalGas, Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E). SDG&E, SoCalGas, PG&E, Edison and the Office of Ratepayer Advocates (ORA) (formerly the Division of Ratepayer Advocates) sponsored a joint stipulation in Phase 2 of the proceeding. In March 2013, the CPUC's final decision adopted the joint stipulation, as proposed. SDG&E retains its current cost of capital adjustment mechanism, and SoCalGas has implemented this same adjustment mechanism, which we describe in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. Both utilities are forgoing their proposed off-ramp provision. Natural Gas Pipeline Operations Safety Assessments 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 process discussed above. In December 2011, the assigned Commissioner to the rulemaking proceeding for the pipeline safety regulations ruled that SDG&E's and SoCalGas' Triennial Cost Allocation Proceeding (TCAP) would be the most logical proceeding to conduct the reasonableness and ratemaking review of the companies' PSEP. In January 2012, the CPUC Consumer Protection and Safety Division (CPSD) issued a Technical Report of the California Utilities' PSEP. The report, along with testimony and evidentiary hearings, will be used to evaluate the PSEP in the regulatory process. Generally, the report found that the PSEP approach to pipeline replacement and pressure testing and other proposed enhancements is reasonable. In February 2012, the assigned Commissioner in the TCAP issued a ruling setting a schedule for the review of the SDG&E and SoCalGas PSEP with evidentiary hearings held in August 2012. SDG&E and SoCalGas now expect the Administrative Law Judge to issue a proposed decision in Phase 1A of this proceeding in the fourth quarter of 2013. We anticipate that the proposed decision, if adopted, would require SoCalGas and SDG&E to update the costs included in their previous filings, as well as to reflect additional records that have been recovered resulting in a reduction of the number of pipeline miles without records. 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. We provide additional information regarding these rulemaking proceedings and the California Utilities' PSEP in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. Utility Incentive Mechanisms The CPUC applies performance-based measures and incentive mechanisms to all California investor-owned utilities, under which the California Utilities have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals. We provide additional information regarding these incentive mechanisms in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and below. Natural Gas Procurement In the first quarter of 2012, SoCalGas recorded its Gas Cost Incentive Mechanism (GCIM) award of $6.2 million for natural gas procured for its core customers during the 12-month period ending March 31, 2011. In July 2013, the CPUC approved SoCalGas' application requesting a GCIM award of $5.4 million for the 12-month period ending March 31, 2012, which SoCalGas recorded in the third quarter of 2013. In June 2013, SoCalGas applied to the CPUC for approval of a GCIM award of $5.8 million for natural gas procured for its core customers during the 12-month period ending March 31, 2013. SoCalGas expects a CPUC decision on this application in the first half of 2014. Energy Efficiency In September 2013, SoCalGas and SDG&E filed their incentive award claims of $3.1 million and $3.9 million, respectively, for their energy efficiency performance in program year 2011. We expect CPUC approval of the awards by the end of 2013. Both SoCalGas and SDG&E plan to file incentive award claims for the 2012 program year in the third quarter of 2014. We currently expect the award amounts to be approximately equal to the amounts claimed for the 2011 program year. In September 2013, the CPUC approved a new Efficiency Savings and Performance Incentive mechanism that would apply for the 2013–2014 program period. The mechanism will be applied on an annual basis and remain in effect for future program cycles unless modified by the CPUC. We currently expect the annual amount of the energy efficiency awards for both SoCalGas and SDG&E under this new mechanism to approximate the amount of awards claimed for the 2011 program year. SDG&E MATTERS San Onofre Nuclear Generating Station (SONGS) SONGS Outage and Retirement 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 Southern California Edison (Edison), the majority owner, and is subject to the jurisdiction of the Nuclear Regulatory Commission (NRC) and the CPUC. On June 6, 2013, Edison notified SDG&E that it had reached a decision to permanently retire SONGS Units 2 and 3 and seek approval to start the decommissioning activities for the entire facility. Edison advised SDG&E that its management had made the unilateral decision to retire the Units once Edison concluded that the considerable uncertainty about when, or if, the NRC would allow a restart of Unit 2 could not be resolved. Given this uncertainty, Edison decided to retire both Units and seek the authority from the NRC to commence the decommissioning of SONGS. By way of background, the steam generators were replaced in Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units have been shut down since early 2012 after a water leak occurred in the Unit 3 steam generator. Edison concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2's steam generators, as well. In March 2012, in response to the shutdown of SONGS, the NRC issued a Confirmatory Action Letter (CAL) which, among other things, outlined the requirements Edison would be required to meet before the NRC would approve a restart of either of the Units. In October 2012, Edison submitted a restart plan to the NRC proposing to operate Unit 2 at a reduced power level for a period of five months, at which time the Unit would be brought down for further inspection. Edison did not file a restart plan for Unit 3, pending further inspection and analysis of what the required repairs or modifications would need to be to return the Unit back to service in a safe manner. The NRC had been reviewing the restart plan for Unit 2 proposed by Edison since that time, and in May 2013, the Atomic Safety and Licensing Board (ASLB), an adjudicatory arm of the NRC, concluded that the CAL process constituted a de facto license amendment proceeding that was subject to a public hearing. This conclusion by the ASLB resulted in further uncertainty regarding when a final decision might be made on restarting Unit 2. CPUC SONGS Order Instituting Investigation (OII) In response to the prolonged outage, the CPUC issued the OII, pursuant to California Public Utilities' Code Section 455.5. The OII consolidates all SONGS issues in various related proceedings into a single proceeding. The OII, among other things, ruled that all revenues associated with the investment in, and operation of, SONGS since January 1, 2012 are subject to refund to customers, pending the outcome of the proceeding. The OII proceeding will also determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage, including purchased replacement power costs that are typically recovered through the Energy Resource Recovery Account (ERRA) balancing account subject only to a reasonableness review by the CPUC. The first phase of the OII addresses 2012 costs. Two hearings were held in 2013 on this first phase, in May to address the 2012 capital and operation and maintenance costs, and in August to address the appropriate determination of the cost of purchased replacement power. We expect a CPUC decision on the first phase of the OII in the fourth quarter of 2013. The second phase of the OII addresses the appropriate rate recovery treatment of the investment in SONGS assets. Hearings on this second phase were held in October 2013, and we expect a CPUC decision on this phase of the OII in the first half of 2014. The third and fourth phases of the OII will address the reasonableness of the steam generator replacement project costs. No hearing dates for these two phases have been scheduled. Since the unscheduled outage started, SDG&E has procured power to meet its customers' needs to replace the power that would have been supplied to SDG&E from SONGS, had SONGS been in operation. The estimated cost of the purchased replacement power, determined consistent with the methodology used in the CPUC's OII into the SONGS outage, incurred from January 2012 through June 6, 2013, the date Edison notified SDG&E of the early closure of SONGS, was approximately $166 million. Of this total, $93 million was incurred in 2012 and has been approved for collection in rates pursuant to prior ERRA proceedings. The remaining $74 million, discussed below, represents replacement power costs incurred in 2013 through June 6 that have not been approved for recovery in rates. In addition to the estimated cost of the purchased replacement power mentioned above, SDG&E's share of SONGS' operating costs, including depreciation, and the return on its investment in SONGS from January 1, 2012 through June 30, 2013, was approximately $300 million. We provide additional information regarding the OII in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. Accounting for the Early Retirement of SONGS Given the decision by Edison to close SONGS, SDG&E management assessed the appropriate accounting for an early-retired plant. In conducting this assessment, management took into consideration, among other things, the interrelationship of any recovery of SDG&E's investment in SONGS, the cost of operations, the cost of purchased replacement power and the probability of having to refund to customers a portion or all of the revenue subject to refund. Management's assessment took into account that the CPUC is considering all of these elements on a combined basis in the OII. After considering the regulatory precedent regarding rate recovery of investments in and costs incurred related to early-retired plants, management considered a number of possible regulatory outcomes from the OII proceeding, none of which management considered certain, and given SDG&E's non-operator and minority interest position and the regulatory precedent on such matters, management believes that it is probable that SDG&E will recover in rates a substantial portion of its investment in SONGS, the associated costs incurred to date and the cost of the purchased replacement power. The amount that management has deemed to be probable of recovery was determined based on management's assessment of the likelihood of the potential regulatory outcomes identified. As a result of Edison's decision to permanently retire SONGS Units 2 and 3, and as a result of our assessment described above, SDG&E established a new regulatory asset included in Other Assets–Other Regulatory Assets on the Condensed Consolidated Balance Sheet. As of September 30, 2013, the balance in this new regulatory asset was $431 million and was comprised of the following: The net book value of SDG&E's investment in SONGS plant and nuclear fuel of $516 million, which prior to the date of the plant retirement, had been reported as Property, Plant and Equipment on the Condensed Consolidated Balance Sheet; SDG&E's SONGS-related materials and supplies of $10 million, which prior to the date of the plant retirement, had been reported as Inventory on the Condensed Consolidated Balance Sheet; SDG&E's 2013 cost of replacement power that is in excess of the amount previously authorized for recovery in ERRA of $74 million which, prior to the date of the plant retirement, would have been reported as Regulatory Balancing Accounts, Net in Current Assets on the Condensed Consolidated Balance Sheet; Miscellaneous costs incurred or expected to be incurred by SDG&E associated with the early closure of the plant of $31 million; net of A reserve for disallowance of rate recovery of $200 million reported as Loss from Plant Closure on the Condensed Consolidated Statement of Operations. The amount that SDG&E will eventually recover will require a regulatory decision from the CPUC that could result in recovery of an amount that is significantly different than management's estimate. In addition to recoveries through the regulatory process, SDG&E intends to pursue various avenues for recovery from other potentially responsible parties and insurance carriers. However, these anticipated recoveries, if any, cannot be included in our current estimates. SDG&E will continue to assess the probability of recovery in rates of this new regulatory asset, as well as: 1) the cost of the purchased replacement power of $93 million approved in prior ERRA proceedings for collection in rates, and 2) the operations and maintenance expenses incurred by SDG&E since the start of the forced outages, which amounted to approximately $220 million through September 30, 2013. Should SDG&E conclude that recovery in rates is less than the amount anticipated or no longer probable, SDG&E will record an additional charge against earnings at the time such a conclusion is reached. Nuclear Regulatory Commission (NRC) Proceedings In September 2013, Edison received an NRC Inspection Report which identified a preliminary finding with low to moderate safety significance and an apparent violation regarding Unit 3's steam generators. In addition, the report identified a preliminary finding with very low safety significance for Unit 2's steam generators for failing to ensure that MHI's modeling and analysis were adequate. Simultaneously, the NRC issued an Inspection Report to MHI containing a Notice of Nonconformance for its flawed computer modeling in the design of the replacement steam generators. Nuclear Decommissioning and Funding As a result of Edison's decision to permanently retire SONGS Units 2 and 3, Edison has begun the decommissioning phase of the plant. The process of decommissioning a nuclear power plant is governed by NRC regulations. The regulations categorize the decommissioning activities into three phases: initial activities, major decommissioning and storage activities, and license termination. Initial activities include providing notice of permanent cessation of operations (accomplished on June 12, 2013) and notice of permanent removal of fuel from the reactor vessels (provided by Edison to the NRC on June 28 and July 22, 2013 for Units 3 and 2, respectively). Within two years after the announcement of retirement, the licensee (Edison) must submit a post-shutdown decommissioning activities report, an irradiated fuel management plan and a site-specific decommissioning cost estimate. Edison currently estimates that it will provide the other initial activity phase plans and cost estimates to the NRC by the end of 2014. In accordance with state and federal requirements and regulations, SDG&E has assets held in trusts, referred to as the Nuclear Decommissioning Trust (NDT), to fund decommissioning costs for SONGS Units 1, 2 and 3. As of September 30, 2013, the fair value of SDG&E's NDT assets was $981 million. Except for the use of funds for the planning of decommissioning activities, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs. SDG&E currently plans to file a request with the CPUC for such authorization by the end of 2013. Until CPUC approval is received, SDG&E will use working capital to pay for any SONGS decommissioning costs incurred, and such expenditures will be reimbursed from the NDT upon that approval. SDG&E and Edison have a joint application pending with the CPUC requesting continued rate recovery of the estimated cost for decommissioning of SONGS. SDG&E is currently authorized to recover $8 million annually to fund additional investments in the NDT to pay for the cost of decommissioning SONGS. In its pending application with the CPUC, SDG&E is requesting to recover $16 million on an annual basis to fund additional investments in the NDT. We expect a decision on this application in the first half of 2014. We provide additional information regarding the NDT and the SONGS decommissioning in Note 6 of the Notes to Consolidated Financial Statements in the Annual Report. Power Procurement and Resource Planning South Bay Substation SDG&E filed an application in 2010 with the CPUC for a permit to construct a new substation to replace the aging and obsolete South Bay substation and accommodate the retirement of the South Bay Power Plant. The existing substation will be demolished when the new substation has been constructed, energized and all transmission lines have been transferred. On October 17, 2013, the CPUC approved SDG&E's permit to construct the South Bay Substation Relocation Project at SDG&E's proposed site, which will be located south of the existing site. The project, estimated at $145 million to $175 million, will replace the existing 138/69-kilovolt (kV) substation with the new 230/69/12-kV Bay Boulevard Substation. SDG&E is in the process of obtaining the additional permits required to begin construction, including the coastal development permit from the California Coastal Commission. SDG&E currently expects the project to be in service by 2017. East County Substation In June 2012, the CPUC approved SDG&E's application for authorization to proceed with the East County Substation project, estimated to cost $435 million. The Bureau of Land Management (BLM) issued its record of decision in August 2012. SDG&E began construction in the second quarter of 2013 and expects the substation to be placed in service in the second half of 2014. FERC Formulaic Rate Matters SDG&E submitted its Electric Transmission Formula Rate (TO4) filing with the Federal Energy Regulatory Commission (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 the TO3 Formula. 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 similar to balancing account treatment that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including its authorized return on investment. This TO4 proceeding will also set SDG&E's authorized return on equity (ROE) on FERC rate base. SDG&E's TO4 filing proposes a FERC ROE of 11.3 percent. Parties have protested SDG&E's proposed ROE and have requested an ROE in the high 8 percent to low 10 percent range. They have also protested other aspects of the TO4 filing. Although the FERC issued orders conditionally adopting the rates proposed by SDG&E based on the 11.3 percent ROE, effective September 1, 2013, such revenues are subject to refund. Settlement negotiations are currently ongoing. If no settlement is reached, hearings at the FERC will begin in May 2014. Based upon recent decisions, and the fact that SDG&E does not currently have any incentive adders in relation to existing projects, the outcome of this proceeding likely may result in an ROE closer to 10 percent. With respect to SDG&E's TO3 Formula, a hearing has been scheduled for early 2014 to address SDG&E's proposed recovery of $23.2 million of costs related to excess wildfire claims in transmission rates for the period September 1, 2012 through August 31, 2013. Excess Wildfire Claims Cost Recovery at the CPUC 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. In December 2012, the CPUC issued a final decision that ultimately did not approve the proposed 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 at September 30, 2013, the resulting after-tax charge against earnings would have been up to $186 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 of the Notes to Consolidated Financial Statements in the Annual Report. We provide additional information about 2007 wildfire litigation costs and their recovery in Note 10. SOCALGAS MATTER Aliso Canyon Natural Gas Storage Compressor Replacement In September 2009, SoCalGas filed an application with the CPUC requesting approval to replace certain obsolete natural gas turbine compressors used in the operations of SoCalGas' Aliso Canyon natural gas storage reservoir with a new electric compressor station. In April 2012, the CPUC issued a draft environmental impact report (EIR) for the project concluding that no significant or unavoidable adverse environmental impacts have been identified from the construction or operation of the proposed project. In July 2013, the CPUC issued a final EIR confirming the conclusions and findings in the draft EIR. On October 29, 2013, the CPUC issued a proposed decision that adopts the EIR and approves the estimated $200 million project. We expect the CPUC to issue a final decision in November 2013.

CALIFORNIA UTILITIES' REGULATORY MATTERS

3 Months Ended

Sep. 30, 2013

Notes to Consolidated Financial Statements [Abstract]

NOTE 9. CALIFORNIA UTILITIES' REGULATORY MATTERS

We discuss matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and details of any new matters below.

JOINT MATTERS

CPUC General Rate Case (GRC)

The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment. In December 2010, the California Utilities filed their 2012 General Rate Case (2012 GRC) applications to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements would change on an annual basis over the subsequent three-year (2013-2015) period.

In May 2013, the CPUC approved a final decision (Final GRC Decision) in the California Utilities' 2012 GRC. The Final GRC Decision establishes a 2012 revenue requirement of $1.733 billion for SDG&E and $1.959 billion for SoCalGas. This represents an increase of $119 million (7.4 percent) and $115 million (6.2 percent) over SDG&E's and SoCalGas' authorized 2011 revenue requirements, respectively. The Final GRC Decision is effective retroactive to January 1, 2012, and SDG&E and SoCalGas recorded the cumulative earnings effect of the retroactive application of the Final GRC Decision of $69 million and $37 million, respectively, in the second quarter of 2013. For SDG&E and SoCalGas, respectively, these amounts include an incremental earnings impact of $52 million and $25 million related to 2012 and $17 million and $12 million related to the first quarter of 2013.

The amount of revenue associated with the retroactive period is expected to be recovered in SDG&E's rates over a 28-month period beginning in September 2013, and in SoCalGas' rates over a 31-month period beginning in June 2013. At September 30, 2013, SDG&E reported on its Condensed Consolidated Balance Sheet $366 million as a regulatory asset, with $203 million classified as noncurrent, representing the retroactive revenue from the Final GRC Decision to be recovered by SDG&E in rates during the period September 2013 through December 2015. At September 30, 2013, SoCalGas reported on its Condensed Consolidated Balance Sheet a regulatory asset of $117 million, with $65 million as noncurrent, representing the retroactive revenue from the Final GRC Decision to be recovered in rates through December 2015.

The Final GRC Decision also establishes a four-year GRC period (through 2015) with a revenue attrition mechanism for the escalation of the adopted revenue requirements for years 2013, 2014, and 2015 based on fixed annual factors of 2.65 percent, 2.75 percent and 2.75 percent, respectively.

For SDG&E, the Final GRC Decision also provides the revenue requirement for cost recovery of wildfire insurance premiums beginning January 1, 2012, as we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

We provide additional information regarding the 2012 GRC in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

CPUC Cost of Capital

A cost of capital proceeding determines a utility's authorized capital structure and authorized rate of return on rate base (ROR), which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE), weighted on a basis consistent with the authorized capital structure. 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. 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, which granted SDG&E and SoCalGas an authorized ROR of 7.79 percent and 8.02 percent, respectively. The CPUC-authorized ROR in effect prior to the effective date of this decision was 8.40 percent for SDG&E and 8.68 percent for SoCalGas. We provide additional details regarding the cost of capital proceeding in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. Phase 2 addressed the cost of capital adjustment mechanisms for SDG&E, SoCalGas, Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E).

SDG&E, SoCalGas, PG&E, Edison and the Office of Ratepayer Advocates (ORA) (formerly the Division of Ratepayer Advocates) sponsored a joint stipulation in Phase 2 of the proceeding. In March 2013, the CPUC's final decision adopted the joint stipulation, as proposed. SDG&E retains its current cost of capital adjustment mechanism, and SoCalGas has implemented this same adjustment mechanism, which we describe in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. Both utilities are forgoing their proposed off-ramp provision.

Natural Gas Pipeline Operations Safety Assessments

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 process discussed above.

In December 2011, the assigned Commissioner to the rulemaking proceeding for the pipeline safety regulations ruled that SDG&E's and SoCalGas' Triennial Cost Allocation Proceeding (TCAP) would be the most logical proceeding to conduct the reasonableness and ratemaking review of the companies' PSEP.

In January 2012, the CPUC Consumer Protection and Safety Division (CPSD) issued a Technical Report of the California Utilities' PSEP. The report, along with testimony and evidentiary hearings, will be used to evaluate the PSEP in the regulatory process. Generally, the report found that the PSEP approach to pipeline replacement and pressure testing and other proposed enhancements is reasonable.

In February 2012, the assigned Commissioner in the TCAP issued a ruling setting a schedule for the review of the SDG&E and SoCalGas PSEP with evidentiary hearings held in August 2012. SDG&E and SoCalGas now expect the Administrative Law Judge to issue a proposed decision in Phase 1A of this proceeding in the fourth quarter of 2013. We anticipate that the proposed decision, if adopted, would require SoCalGas and SDG&E to update the costs included in their previous filings, as well as to reflect additional records that have been recovered resulting in a reduction of the number of pipeline miles without records.

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.

We provide additional information regarding these rulemaking proceedings and the California Utilities' PSEP in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Utility Incentive Mechanisms

The CPUC applies performance-based measures and incentive mechanisms to all California investor-owned utilities, under which the California Utilities have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals.

We provide additional information regarding these incentive mechanisms in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and below.

Natural Gas Procurement

In the first quarter of 2012, SoCalGas recorded its Gas Cost Incentive Mechanism (GCIM) award of $6.2 million for natural gas procured for its core customers during the 12-month period ending March 31, 2011. In July 2013, the CPUC approved SoCalGas' application requesting a GCIM award of $5.4 million for the 12-month period ending March 31, 2012, which SoCalGas recorded in the third quarter of 2013. In June 2013, SoCalGas applied to the CPUC for approval of a GCIM award of $5.8 million for natural gas procured for its core customers during the 12-month period ending March 31, 2013. SoCalGas expects a CPUC decision on this application in the first half of 2014.

Energy Efficiency

In September 2013, SoCalGas and SDG&E filed their incentive award claims of $3.1 million and $3.9 million, respectively, for their energy efficiency performance in program year 2011. We expect CPUC approval of the awards by the end of 2013. Both SoCalGas and SDG&E plan to file incentive award claims for the 2012 program year in the third quarter of 2014. We currently expect the award amounts to be approximately equal to the amounts claimed for the 2011 program year.

In September 2013, the CPUC approved a new Efficiency Savings and Performance Incentive mechanism that would apply for the 2013–2014 program period. The mechanism will be applied on an annual basis and remain in effect for future program cycles unless modified by the CPUC. We currently expect the annual amount of the energy efficiency awards for both SoCalGas and SDG&E under this new mechanism to approximate the amount of awards claimed for the 2011 program year.

SDG&E MATTERS

San Onofre Nuclear Generating Station (SONGS)

SONGS Outage and Retirement

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 Southern California Edison (Edison), the majority owner, and is subject to the jurisdiction of the Nuclear Regulatory Commission (NRC) and the CPUC.

On June 6, 2013, Edison notified SDG&E that it had reached a decision to permanently retire SONGS Units 2 and 3 and seek approval to start the decommissioning activities for the entire facility. Edison advised SDG&E that its management had made the unilateral decision to retire the Units once Edison concluded that the considerable uncertainty about when, or if, the NRC would allow a restart of Unit 2 could not be resolved. Given this uncertainty, Edison decided to retire both Units and seek the authority from the NRC to commence the decommissioning of SONGS.

By way of background, the steam generators were replaced in Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units have been shut down since early 2012 after a water leak occurred in the Unit 3 steam generator. Edison concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2's steam generators, as well. In March 2012, in response to the shutdown of SONGS, the NRC issued a Confirmatory Action Letter (CAL) which, among other things, outlined the requirements Edison would be required to meet before the NRC would approve a restart of either of the Units.

In October 2012, Edison submitted a restart plan to the NRC proposing to operate Unit 2 at a reduced power level for a period of five months, at which time the Unit would be brought down for further inspection. Edison did not file a restart plan for Unit 3, pending further inspection and analysis of what the required repairs or modifications would need to be to return the Unit back to service in a safe manner. The NRC had been reviewing the restart plan for Unit 2 proposed by Edison since that time, and in May 2013, the Atomic Safety and Licensing Board (ASLB), an adjudicatory arm of the NRC, concluded that the CAL process constituted a de facto license amendment proceeding that was subject to a public hearing. This conclusion by the ASLB resulted in further uncertainty regarding when a final decision might be made on restarting Unit 2.

CPUC SONGS Order Instituting Investigation (OII)

In response to the prolonged outage, the CPUC issued the OII, pursuant to California Public Utilities' Code Section 455.5. The OII consolidates all SONGS issues in various related proceedings into a single proceeding. The OII, among other things, ruled that all revenues associated with the investment in, and operation of, SONGS since January 1, 2012 are subject to refund to customers, pending the outcome of the proceeding. The OII proceeding will also determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage, including purchased replacement power costs that are typically recovered through the Energy Resource Recovery Account (ERRA) balancing account subject only to a reasonableness review by the CPUC.

The first phase of the OII addresses 2012 costs. Two hearings were held in 2013 on this first phase, in May to address the 2012 capital and operation and maintenance costs, and in August to address the appropriate determination of the cost of purchased replacement power. We expect a CPUC decision on the first phase of the OII in the fourth quarter of 2013.

The second phase of the OII addresses the appropriate rate recovery treatment of the investment in SONGS assets. Hearings on this second phase were held in October 2013, and we expect a CPUC decision on this phase of the OII in the first half of 2014.

The third and fourth phases of the OII will address the reasonableness of the steam generator replacement project costs. No hearing dates for these two phases have been scheduled.

Since the unscheduled outage started, SDG&E has procured power to meet its customers' needs to replace the power that would have been supplied to SDG&E from SONGS, had SONGS been in operation. The estimated cost of the purchased replacement power, determined consistent with the methodology used in the CPUC's OII into the SONGS outage, incurred from January 2012 through June 6, 2013, the date Edison notified SDG&E of the early closure of SONGS, was approximately $166 million. Of this total, $93 million was incurred in 2012 and has been approved for collection in rates pursuant to prior ERRA proceedings. The remaining $74 million, discussed below, represents replacement power costs incurred in 2013 through June 6 that have not been approved for recovery in rates.

In addition to the estimated cost of the purchased replacement power mentioned above, SDG&E's share of SONGS' operating costs, including depreciation, and the return on its investment in SONGS from January 1, 2012 through June 30, 2013, was approximately $300 million. We provide additional information regarding the OII in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Accounting for the Early Retirement of SONGS

Given the decision by Edison to close SONGS, SDG&E management assessed the appropriate accounting for an early-retired plant. In conducting this assessment, management took into consideration, among other things, the interrelationship of any recovery of SDG&E's investment in SONGS, the cost of operations, the cost of purchased replacement power and the probability of having to refund to customers a portion or all of the revenue subject to refund. Management's assessment took into account that the CPUC is considering all of these elements on a combined basis in the OII. After considering the regulatory precedent regarding rate recovery of investments in and costs incurred related to early-retired plants, management considered a number of possible regulatory outcomes from the OII proceeding, none of which management considered certain, and given SDG&E's non-operator and minority interest position and the regulatory precedent on such matters, management believes that it is probable that SDG&E will recover in rates a substantial portion of its investment in SONGS, the associated costs incurred to date and the cost of the purchased replacement power. The amount that management has deemed to be probable of recovery was determined based on management's assessment of the likelihood of the potential regulatory outcomes identified.

As a result of Edison's decision to permanently retire SONGS Units 2 and 3, and as a result of our assessment described above, SDG&E established a new regulatory asset included in Other Assets–Other Regulatory Assets on the Condensed Consolidated Balance Sheet. As of September 30, 2013, the balance in this new regulatory asset was $431 million and was comprised of the following:

The net book value of SDG&E's investment in SONGS plant and nuclear fuel of $516 million, which prior to the date of the plant retirement, had been reported as Property, Plant and Equipment on the Condensed Consolidated Balance Sheet;
SDG&E's SONGS-related materials and supplies of $10 million, which prior to the date of the plant retirement, had been reported as Inventory on the Condensed Consolidated Balance Sheet;
SDG&E's 2013 cost of replacement power that is in excess of the amount previously authorized for recovery in ERRA of $74 million which, prior to the date of the plant retirement, would have been reported as Regulatory Balancing Accounts, Net in Current Assets on the Condensed Consolidated Balance Sheet;
Miscellaneous costs incurred or expected to be incurred by SDG&E associated with the early closure of the plant of $31 million; net of

A reserve for disallowance of rate recovery of $200 million reported as Loss from Plant Closure on the Condensed Consolidated Statement of Operations.

The amount that SDG&E will eventually recover will require a regulatory decision from the CPUC that could result in recovery of an amount that is significantly different than management's estimate. In addition to recoveries through the regulatory process, SDG&E intends to pursue various avenues for recovery from other potentially responsible parties and insurance carriers. However, these anticipated recoveries, if any, cannot be included in our current estimates. SDG&E will continue to assess the probability of recovery in rates of this new regulatory asset, as well as: 1) the cost of the purchased replacement power of $93 million approved in prior ERRA proceedings for collection in rates, and 2) the operations and maintenance expenses incurred by SDG&E since the start of the forced outages, which amounted to approximately $220 million through September 30, 2013. Should SDG&E conclude that recovery in rates is less than the amount anticipated or no longer probable, SDG&E will record an additional charge against earnings at the time such a conclusion is reached.

Nuclear Regulatory Commission (NRC) Proceedings

In September 2013, Edison received an NRC Inspection Report which identified a preliminary finding with low to moderate safety significance and an apparent violation regarding Unit 3's steam generators. In addition, the report identified a preliminary finding with very low safety significance for Unit 2's steam generators for failing to ensure that MHI's modeling and analysis were adequate.

Simultaneously, the NRC issued an Inspection Report to MHI containing a Notice of Nonconformance for its flawed computer modeling in the design of the replacement steam generators.

Nuclear Decommissioning and Funding

As a result of Edison's decision to permanently retire SONGS Units 2 and 3, Edison has begun the decommissioning phase of the plant. The process of decommissioning a nuclear power plant is governed by NRC regulations. The regulations categorize the decommissioning activities into three phases: initial activities, major decommissioning and storage activities, and license termination. Initial activities include providing notice of permanent cessation of operations (accomplished on June 12, 2013) and notice of permanent removal of fuel from the reactor vessels (provided by Edison to the NRC on June 28 and July 22, 2013 for Units 3 and 2, respectively). Within two years after the announcement of retirement, the licensee (Edison) must submit a post-shutdown decommissioning activities report, an irradiated fuel management plan and a site-specific decommissioning cost estimate. Edison currently estimates that it will provide the other initial activity phase plans and cost estimates to the NRC by the end of 2014.

In accordance with state and federal requirements and regulations, SDG&E has assets held in trusts, referred to as the Nuclear Decommissioning Trust (NDT), to fund decommissioning costs for SONGS Units 1, 2 and 3. As of September 30, 2013, the fair value of SDG&E's NDT assets was $981 million. Except for the use of funds for the planning of decommissioning activities, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs. SDG&E currently plans to file a request with the CPUC for such authorization by the end of 2013. Until CPUC approval is received, SDG&E will use working capital to pay for any SONGS decommissioning costs incurred, and such expenditures will be reimbursed from the NDT upon that approval.

SDG&E and Edison have a joint application pending with the CPUC requesting continued rate recovery of the estimated cost for decommissioning of SONGS. SDG&E is currently authorized to recover $8 million annually to fund additional investments in the NDT to pay for the cost of decommissioning SONGS. In its pending application with the CPUC, SDG&E is requesting to recover $16 million on an annual basis to fund additional investments in the NDT. We expect a decision on this application in the first half of 2014.

We provide additional information regarding the NDT and the SONGS decommissioning in Note 6 of the Notes to Consolidated Financial Statements in the Annual Report.

Power Procurement and Resource Planning

South Bay Substation

SDG&E filed an application in 2010 with the CPUC for a permit to construct a new substation to replace the aging and obsolete South Bay substation and accommodate the retirement of the South Bay Power Plant. The existing substation will be demolished when the new substation has been constructed, energized and all transmission lines have been transferred. On October 17, 2013, the CPUC approved SDG&E's permit to construct the South Bay Substation Relocation Project at SDG&E's proposed site, which will be located south of the existing site. The project, estimated at $145 million to $175 million, will replace the existing 138/69-kilovolt (kV) substation with the new 230/69/12-kV Bay Boulevard Substation. SDG&E is in the process of obtaining the additional permits required to begin construction, including the coastal development permit from the California Coastal Commission. SDG&E currently expects the project to be in service by 2017.

East County Substation

In June 2012, the CPUC approved SDG&E's application for authorization to proceed with the East County Substation project, estimated to cost $435 million. The Bureau of Land Management (BLM) issued its record of decision in August 2012. SDG&E began construction in the second quarter of 2013 and expects the substation to be placed in service in the second half of 2014.

FERC Formulaic Rate Matters

SDG&E submitted its Electric Transmission Formula Rate (TO4) filing with the Federal Energy Regulatory Commission (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 the TO3 Formula. 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 similar to balancing account treatment that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including its authorized return on investment.

This TO4 proceeding will also set SDG&E's authorized return on equity (ROE) on FERC rate base. SDG&E's TO4 filing proposes a FERC ROE of 11.3 percent. Parties have protested SDG&E's proposed ROE and have requested an ROE in the high 8 percent to low 10 percent range. They have also protested other aspects of the TO4 filing. Although the FERC issued orders conditionally adopting the rates proposed by SDG&E based on the 11.3 percent ROE, effective September 1, 2013, such revenues are subject to refund. Settlement negotiations are currently ongoing. If no settlement is reached, hearings at the FERC will begin in May 2014. Based upon recent decisions, and the fact that SDG&E does not currently have any incentive adders in relation to existing projects, the outcome of this proceeding likely may result in an ROE closer to 10 percent.

With respect to SDG&E's TO3 Formula, a hearing has been scheduled for early 2014 to address SDG&E's proposed recovery of $23.2 million of costs related to excess wildfire claims in transmission rates for the period September 1, 2012 through August 31, 2013.

Excess Wildfire Claims Cost Recovery at the CPUC

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. In December 2012, the CPUC issued a final decision that ultimately did not approve the proposed 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 at September 30, 2013, the resulting after-tax charge against earnings would have been up to $186 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 of the Notes to Consolidated Financial Statements in the Annual Report.

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

SOCALGAS MATTER

Aliso Canyon Natural Gas Storage Compressor Replacement

In September 2009, SoCalGas filed an application with the CPUC requesting approval to replace certain obsolete natural gas turbine compressors used in the operations of SoCalGas' Aliso Canyon natural gas storage reservoir with a new electric compressor station. In April 2012, the CPUC issued a draft environmental impact report (EIR) for the project concluding that no significant or unavoidable adverse environmental impacts have been identified from the construction or operation of the proposed project. In July 2013, the CPUC issued a final EIR confirming the conclusions and findings in the draft EIR. On October 29, 2013, the CPUC issued a proposed decision that adopts the EIR and approves the estimated $200 million project. We expect the CPUC to issue a final decision in November 2013.