CALIFORNIA UTILITIES' REGULATORY MATTERS

12 Months Ended

Dec. 31, 2014

Notes to Consolidated Financial Statements [Abstract]

Sempra Utilities' Regulatory Matters

NOTE 14. CALIFORNIA UTILITIES’ REGULATORY MATTERS

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.

The California Utilities filed their 2016 General Rate Case (2016 GRC) applications in November 2014. These filings requested revenue requirement increases of $133 million and $256 million for SDG&E and SoCalGas, respectively, over their 2015 revenue requirements. In February 2015, the CPUC issued a scoping memo setting the schedule for the proceeding, including the issuance of a proposed decision by the end of 2015.

In May 2013, the CPUC approved a final decision in the California Utilities’ 2012 GRC (Final 2012 GRC Decision). The Final 2012 GRC Decision was effective retroactive to January 1, 2012, and SDG&E and SoCalGas recorded the cumulative earnings effect of the retroactive application of the Final 2012 GRC Decision of $69 million and $37 million, respectively, in the second quarter of 2013. For SDG&E and SoCalGas, respectively, these amounts included 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 being 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 December 31, 2014, SDG&E reported on its Consolidated Balance Sheet $162 million as a regulatory asset, all classified as current, representing the retroactive revenue from the Final 2012 GRC Decision to be recovered by SDG&E in rates through December 2015. At December 31, 2014, SoCalGas reported on its Consolidated Balance Sheet a regulatory asset of $52 million, all classified as current, representing the retroactive revenue from the Final GRC Decision to be recovered in rates through December 2015.

CPUC Cost of Capital

A CPUC 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 CPUC-regulated electric distribution and generation as well as natural gas distribution, transmission and storage assets.

In addition, a cost of capital proceeding also addresses the automatic cost of capital adjustment mechanism (CCM) 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. The market-based benchmark for SDG&E’s and SoCalGas’ CCM is the 12-month average monthly A-rated utility bond index, as published by Moody’s for the 12-month period of October 1st through September 30th (CCM Period) of each calculation year. In the last cost of capital proceeding, SDG&E’s and SoCalGas’ CCM benchmark rate was set at 4.24 percent. If at the end of the CCM Period the monthly average benchmark rate falls outside of the established range of 3.24 percent to 5.24 percent, SDG&E’s and SoCalGas’ authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the benchmark rate. In addition, the authorized recovery rate for SDG&E’s and SoCalGas’ cost of debt and preferred stock would be adjusted to their respective actual weighted average costs, with no change to the authorized capital structure. All three adjustments with the new rate would become effective on January 1st of the following year in which the benchmark range was exceeded. For the twelve-month period ended September 30, 2014, the 12-month average of monthly Moody’s A-rated utility bond index was 4.46 percent.

The CCM only applies during the intervening years between scheduled cost of capital proceedings. In the year the cost of capital proceeding is scheduled, the cost of capital proceeding takes precedence over CCM and will set new rates for the following year.

In December 2014, the CPUC granted both SDG&E and SoCalGas an extension of their filing deadlines for their next cost of capital applications by one year, from April 2015 to April 2016. The CPUC also extended the current CCM until the April 2016 filing date. The one year extension was made in response to a joint request by SDG&E, SoCalGas, Pacific Gas and Electric Company (PG&E) and Edison with the CPUC in November 2014.

SDG&E’s current CPUC-authorized ROR is 7.79 percent and SoCalGas’ current CPUC-authorized ROR is 8.02 percent based on their authorized capital structures as follows:

COST OF CAPITAL AND AUTHORIZED RATE STRUCTURE
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%

SDG&E files separately with the FERC for authorized ROE on FERC-regulated electric transmission operations and assets as described below in “Federal Energy Regulatory Commission (FERC) Formulaic Rate Matters”.

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 natural gas transmission pipelines located in populated areas that have not been pressure tested. The California Utilities filed their Pipeline Safety Enhancement Plan (PSEP) with the CPUC in August 2011. In their 2011 filing with the CPUC, the California Utilities estimated the total cost for Phase 1 of the two-phase plan to be $3.1 billion ($2.5 billion for SoCalGas and $600 million for SDG&E) over the 10-year period of 2012 to 2022. As a result of on-going efforts since this original filing, the California Utilities have been able to eliminate over two hundred miles of pipeline from the testing scope and have revised their total estimated cost for Phase 1 to $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E). The California Utilities requested that the incremental capital investment required as a result of any approved plan be included in rate base and that cost recovery be allowed for any other incremental cost not eligible for rate-base recovery.

In April 2012, the CPUC transferred the PSEP to the Triennial Cost Allocation Proceeding (TCAP) and authorized 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.

Also 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. The CPUC’s Safety and Enforcement Division 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 utilities’ pipeline safety plans filed pursuant to SB 705.

In June 2014, the CPUC issued a final decision in the TCAP proceeding addressing SDG&E’s and SoCalGas’ PSEP. Specifically, the decision:

• approved the utilities’ model for implementing PSEP;
• approved a process, including a reasonableness review, to determine the amount that the utilities will be authorized to recover from ratepayers for the interim costs incurred through the date of the final decision to implement PSEP, which is recorded in the regulatory accounts authorized by the CPUC as noted above;
• approved balancing account treatment, subject to a reasonableness review, for incremental costs yet to be incurred to implement PSEP; and
• established the criteria to determine the amounts that would not be eligible for cost recovery, including:

• certain costs incurred or to be incurred searching for pipeline test records,
• the cost of pressure testing pipelines installed after July 1, 1961 for which the company has not found sufficient records of testing, and
• any undepreciated balances for pipelines installed after 1961 that were replaced due to insufficient documentation of pressure testing.

As a result of this decision, SoCalGas recorded an after-tax earnings charge of $5 million in 2014 for costs incurred in prior periods for which SoCalGas was disallowed recovery. After taking the amounts disallowed for recovery into consideration, as of December 31, 2014, SDG&E and SoCalGas have recorded PSEP costs of $2 million and $85 million, respectively, in the CPUC-authorized regulatory account. In regard to requesting recovery from customers for PSEP costs incurred and recorded in accordance with the TCAP decision, SDG&E and SoCalGas are authorized to file an application with the CPUC for recovery of such costsup to the date of the TCAP decision and then annually for costs incurred through the end of each calendar year beginning with the period ending December 31, 2015. SoCalGas and SDG&E currently expect to be able to file such applications by the third quarter of the year following and would expect a decision from the CPUC approximately 12 to 18 months following the date of the application (i.e. a decision on the recovery of costs recorded in the PSEP regulatory accounts as of December 31, 2015 would be expected by mid-2017). In response to this significant delay in receiving the authority to recover PSEP costs incurred from customers, in October 2014, SDG&E and SoCalGas filed a request with the CPUC for authority to recover PSEP costs from customersas incurred, subject to refund pending the results of a reasonableness review by the CPUC, instead of in the subsequentyear. In December 2014, SDG&E and SoCalGas filed an application with the CPUC for recovery of $0.1 million and $46 million, respectively, in costs recorded in the regulatory account through June 11, 2014. We requested a decision in 2015.

In July 2014, the ORA and TURN filed a joint application for rehearing of the CPUC’s June 2014 final decision. The ORA and TURN alleged that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In November 2014, the CPUC denied the ORA and TURN request for rehearing of the decision adopting the PSEP. In December 2014, ORA and TURN sought rehearing of the CPUC’s decision on rehearing. In late December 2014, SoCalGas and SDG&E filed their opposition to this second application for rehearing, and are continuing to implement PSEP in accordance with the June 2014 CPUC decision.

Southern Gas System Reliability Project

In December 2013, SoCalGas and SDG&E filed a joint application with the CPUC seeking authority to recover the full cost of the Southern Gas System Reliability Project. Also known as the North-South Gas Project, the project will enhance reliability on the southern portions of the California Utilities’ integrated natural gas transmission system (Southern System). The estimated cost of the project, as originally filed, is between $800 million to $850 million. As proposed, the project consists of three components: 1) constructing an approximately 60-mile, 36-inch natural gas transmission pipeline between the SoCalGas Adelanto compressor station and the Moreno pressure limiting station; 2) upgrading the Adelanto compressor station; and 3) constructing an approximately 31-mile, 36-inch pipeline from the Moreno pressure limiting station to a pressure limiting station in Whitewater. In November 2014, the California Utilities revised the scope of the proposed project to only include connecting the Adelanto compressor station and Moreno pressure limiting station with approximately 65 miles of 36-inch pipeline and upgrading the Adelanto compressor station, and eliminating the Moreno-Whitewater pipeline. As a result of the revised scope of the project, the California Utilities assessed the estimated cost of the revised project and confirmed the original cost estimate of $800 million to $850 million, while still providing almost all of the benefits for customers. Given the revised project scope, an updated schedule in this proceeding is currently being developed. Depending upon this updated schedule and subject to environmental permitting and approval by the CPUC, we expect the project to be in service by the end of 2019.

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. 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. SDG&E has incentive mechanisms associated with:

• operational incentives

• energy efficiency

SoCalGas has incentive mechanisms associated with:

• energy efficiency
• natural gas procurement

• unbundled natural gas storage and system operator hub services

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.

Energy Efficiency

The CPUC established incentive mechanisms that are based on the effectiveness of energy efficiency programs. In December 2012, the CPUC issued a final decision 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 SoCalGasfor 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.

In December 2013, the CPUC awarded $3.1 million to SoCalGas and $3.9 million to SDG&E for their 2011 program year results. In December 2014, the CPUC approved awards to SoCalGas and SDG&E of $5.9 million and $7.5 million, respectively, for program years 2012 and 2013. Of these amounts, SoCalGas and SDG&E will receive initial 2013 program awards of $1.5 million and $2.5 million, respectively, and the CPUC will address the remaining 2013 program awards in 2015.

Unbundled Natural Gas Storage and System Operator Hub Services

The CPUC has established a revenue sharing mechanism, effective through 2015, which provides for the sharing between ratepayers and SoCalGas (shareholders) of the net revenues generated by SoCalGas’ unbundled natural gas storage and system operator hub services. Annual net revenues (revenues less allocated service costs) under the mechanism are shared on a graduated basis, as follows:

• the first $15 million of net revenue to be shared 90 percent ratepayers/10 percent shareholders;
• the next $15 million of net revenue to be shared 75 percent ratepayers/25 percent shareholders;
• all additional net revenues to be shared evenly between ratepayers and shareholders; and

• the maximum total annual shareholder-allocated portion of the net revenues cannot exceed $20 million.

SoCalGas is seeking to extend the mechanism through at least 2019, but revise the sharing to 60 percent ratepayers/40 percent shareholders to reflect changes in the market for storage services. The current annual shareholder earnings cap of $20 million would remain in place.

Natural Gas Procurement

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.

The CPUC issued final decisions in 2014, 2013 and 2012 approving GCIM awards for SoCalGas of $5.8 million, $5.4 million and $6.2 million, respectively, for the 12-month periods ending March 31, 2013, 2012 and 2011, respectively. SoCalGas filed an application with the CPUC for approval of a $13.7 million GCIM award for natural gas procured for its core customers during the 12-month period ending March 31, 2014. In February 2015, the CPUC issued a final decision approving the $13.7 million GCIM award as requested by SoCalGas. SoCalGas will recognize this award in its financial results for the first quarter of 2015.

Operational Incentives

The CPUC may establish operational incentives and associated performance benchmarks as part of a general rate case or cost of service proceeding. In the California Utilities’ Final 2012 GRC Decision described above, SDG&E was directed to establish a performance measure and incentive for electric reliability. In September 2014, the CPUC approved SDG&E’s proposed mechanism, which will apply to calendar year 2015 and be considered in the 2016 GRC. The CPUC did not establish any operational incentives for SoCalGas in the Final 2012 GRC Decision.

SDG&E MATTERS

SONGS

We discuss regulatory and other matters related to SONGS in Note 13.

Power Procurement and Resource Planning

Background—Electric Industry Regulation

California’s legislative response to the 2000 – 2001 energy crisis resulted in the California Department of Water Resources (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 power contracts expired in 2013, with one remaining transportation contract allocated to SDG&E that will expire in 2018.

Renewable Energy

SDG&E is subject to the Renewables Portfolio Standard (RPS) Program administered by both the CPUC and the California Energy Commission, 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 proceeding 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 ISO.

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

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

• successful development and implementation of the renewable energy technologies.

In August 2014, SDG&E made a required filing with the CPUC indicating that its procurement of renewable energy during the period January 1, 2011 through December 31, 2013 exceeded the 20-percent minimum amount required by RPS. 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 CPUC-imposed penalties, which could materially affect its business, cash flows, financial condition, results of operations and/or prospects. The limit on the total amount of penalties for failure to comply with the RPSrequirements is $75 million for the first compliance period (2011-2013); $75 million for the second compliance period (2014-2016); $100 million for the third compliance period (2017-2020); and $25 million for each annual compliance period beginning in 2021.

Cleveland National Forest Transmission Projects

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 (CNF). The proposed projects will replace and fire-harden five existing transmission lines and six existing distribution lines at an estimated cost of between $400 million and $450 million. As directed by the CPUC, SDG&E filed an amended application in June 2013 to provide notice of certain alternatives proposed by the U.S. Forest Service (USFS) in connection with SDG&E’s request for a Master Special Use Permit (MSUP). USFS approval of the MSUP will establish land rights and conditions for SDG&E’s continued operation and maintenance of facilities located within the CNF. CPUC approval is not required for the MSUP, even though construction of the projects is subject to review by both the USFS and CPUC. A draft environmental impact report (EIR/EIS), developed jointly by the CPUC and USFS, was issued in September 2014 and a final EIR/EIS is expected in early 2015. SDG&E currently expects a CPUC decision approving the transmission projects in the second half of 2015 and then expects the various phases of this project to be placed in service starting in 2016 and continuing through the end of the project in 2019.

Sycamore-Peñasquitos Transmission Project

In March 2014, the CAISO selected SDG&E, as a result of a competitive bid process, to construct the Sycamore-Peñasquitos 230-kilovolt (kV) transmission project, which will provide a 16.7-mile transmission connection between SDG&E’s Sycamore Canyon and Peñasquitos substations. In July 2014, the CPUC notified SDG&E that the application requesting a Certificate of Public Convenience and Necessity (CPCN) to construct the line, which was filed with the CPUC in April 2014, is complete. The estimated $120 million to $150 million project was identified by the CAISO and a state task force as necessary to ensure grid reliability given the closure of SONGS. The project will also serve to strengthen renewable energy infrastructure in the region. In October 2014, SDG&E filed a request with FERC seeking, among other things, a 100 basis point ROE adder for this project. We expect a FERC decision on this filing in 2015. SDG&E expects a CPUC decision approving the project in the first half of 2016, with the line expected to be in service in mid-2017.

South Orange County Reliability Enhancement

SDG&E filed an application with the CPUC in May 2012 requesting a CPCN forthe 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 draft environmental report to be issued in early 2015 and a final CPUC decision approving the estimated $400 million to $500 million project in the first half of 2016. SDG&E obtained approval for the project from the CAISO in May 2011. As the project is planned in phases, SDG&E currently expects the entire project to be in service in 2020.

South Bay Substation and Relocation Project

SDG&E filed an application in 2010 with the CPUC for a permit to construct a new substation, the Bay Boulevard substation, to replace the aging and obsolete South Bay substation to accommodate regional energy demands. The existing substation will be demolished when the Bay Boulevard substation has been constructed, energized and all transmission lines have been transferred. In October 2013, the CPUC approved SDG&E’s permit to construct the Bay Boulevard substation at SDG&E’s proposed site. The project is estimated at $145 million to $175 million. In March 2014, the California Coastal Commission approved the coastal development permit for the project, subject to certain additional environmental enhancements. In July 2014, SDG&E filed a petition with the CPUC to request modifications to the prior CPUC decision to authorize the additional construction activities required by the coastal development permit. In January 2015, the CPUC issued a decision approving the petition for modification. SDG&E is in the process of obtaining the remaining approvals and permits required to begin construction. SDG&E currently expects the project to be in service in 2017.

Federal Energy Regulatory Commission (FERC) Formulaic Rate Matters

In February 2013, SDG&E submitted its Electric Transmission Formula Rate (TO4) filing with the FERC to set the rate making methodology and rate of return for SDG&E’s FERC-regulated electric transmission operations and assets for a multi-year period beginning September 1, 2013. The TO4 filing proposed a FERC ROE of 11.3 percent and requested: 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. In June and July 2013, the FERC issued orders accepting the filing, subject to refund, and established settlement and hearing procedures, with rates being effective September 1, 2013.

On January 31, 2014, SDG&E filed an uncontested multi-party settlement at the FERC regarding the TO4 filing. The settlement, approved by FERC in May 2014, will be in effect through December 31, 2018, is subject to a one-time right of termination by any party, and established a 10.05 percent ROE. The settlement also requires SDG&E to make annual information filings on December 1 of a given year to update rates for the following calendar year. SDG&E also has the right to file for any ROE incentives that might apply under FERC rules. SDG&E’s debt to equity ratio will be set annually based on the actual ratio at the end of each year.

Energy Resource Recovery Account (ERRA)

The ERRA is the regulatory balancing account that SDG&E uses to recover the electric fuel and purchased power costs it incurs to provide energy to its bundled service customers. SDG&E files an application with the CPUC each year to establish the ERRA revenue requirement needed for the following calendar year. Additionally, to the extent the ERRA balance exceeds a certain tolerance or “ERRA Trigger”, SDG&E must file an application to adjust its rates upward or downward, as applicable, to address the under- or overcollected ERRA balance, respectively. In February 2014, the CPUC issued a decision granting SDG&E authority to increase rates to recover an ERRA Trigger revenue requirement of $221 million, which rate increase was effective on April 1, 2014 and will continue through December 31, 2015. In May 2014, the CPUC issued a final decision approving SDG&E’s proposed 2014 ERRA revenue requirement of $1.23 billion, an increase of $242 million compared to the 2013 ERRA revenue requirement of $988 million. SDG&E implemented the increased revenue requirement on August 1, 2014.

Excess Wildfire Claims Cost Recovery

In August 2009, SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC 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.

In February 2014, the Presiding Judge assigned by the FERC to SDG&E’s annual Electric Transmission Formula Rate filing (TO3 Cycle 6) issued an Initial Decision and an Order on Summary Judgment which authorizes SDG&E to recover all of the costs incurred and allocated to SDG&E’s FERC-regulated operations for the 12-month period ended March 31, 2012, resulting from settlement activities for 2007 wildfire claims. In connection with this proceeding, the CPUC filed an appeal in the Ninth Circuit Court of Appeal of an earlier decision by the FERC denying the CPUC’s request to postpone the FERC proceeding pending CPUC action on cost recovery of the excess wildfire costs. The FERC has sought dismissal of the CPUC’s appeal on procedural grounds. The Court of Appeal has not yet ruled on the merits.

SDG&E intends to pursue recovery of the costs it has incurred for settlement activities associated with the 2007 wildfire claims allocated to SDG&E’s CPUC-regulated operations by filing an application with the CPUC in 2015. SDG&E will continue to assess the potential for recovery of these costs in rates. We discuss the impact should SDG&E conclude that recovery in rates is no longer probable in “Legal Proceedings — SDG&E — 2007 Wildfire Litigation” in Note 15. We discuss how we assess the probability of recovery of our regulatory assets in Note 1.

SOCALGAS MATTERS

Advanced Metering Infrastructure

In November 2011, the ORA and 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 considered the request. In June 2014, the CPUC denied the ORA/TURN petition, and SoCalGas is continuing its deployment of AMI pursuant to the April 2010 CPUC decision approving the project.