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CALIFORNIA UTILITIES' REGULATORY MATTERS
 12 Months Ended
Dec. 31, 2015
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 set sufficient rates 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.

2016 General Rate Case (2016 GRC)

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 September 2015, the California Utilities filed settlement agreements with the CPUC that resolve all material matters related to the proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through repair allowance tax deductions, discussed below. The settlement agreements are with eight of eleven intervening parties. For SoCalGas, the settlement proposes a total revenue requirement in 2016 of $2.219 billion, which is $133 million less than its original request. The proposed settlement represents an increase of $122 million or 6 percent over the 2015 total revenue requirement, excluding the impact of the 2015 revenue requirement increase discussed below under “SoCalGas Matters – Increase to CPUC-Authorized Annual Revenue Requirement.” For SDG&E, the settlement proposes a total revenue requirement in 2016 of $1.811 billion, which is $100 million less than its original request (as revised). The proposed settlement represents an increase of $17 million, or one percent over the 2015 total revenue requirement. This increase reflects a $16 million adjustment to the 2015 estimated revenue requirement since the November 2014 filings. The filed settlement agreements also call for attrition adjustments of 3.5 percent for both 2017 and 2018. The California Utilities also filed a separate agreement, reached with ORA, proposing that a fourth year (2019) be added to the GRC period, with a revenue requirement increase of 4.3 percent over 2018. Because the 2016 settlement has not been finalized, the California Utilities will collect rates identical to 2015 authorized amounts until a 2016 decision is approved.

The settlement agreements described above exclude a proposal, for both SDG&E and SoCalGas, regarding certain intra-rate case income tax benefits. The proposal recommends that the CPUC adjust SoCalGas’ rate base by $92 million and SDG&E’s rate base by $93 million, and additionally reduce both utilities’ revenue requirements by amounts currently being tracked in tax memorandum accounts for the year 2015. At December 31, 2015, the pretax balances tracked in these memorandum accounts total $74 million for SoCalGas and $39 million for SDG&E. We believe the proposed treatment would violate and contradict long standing rate making and income tax policy, and would represent a material departure from historical practice. If this proposal is adopted, the outcome would reduce the revenue requirement amounts agreed to in the respective settlement agreements described above. SDG&E and SoCalGas do not expect that the prospective reduction to rate base described above would result in an immediate earnings impact if this proposal is adopted. However, if this proposal is adopted, the amounts currently being tracked in the tax memorandum accounts for 2015 could result in a material charge against earnings when the draft decision is received.

We anticipate all matters to be resolved in the CPUC’s final decision on the 2016 GRC proceeding. We expect the CPUC to issue a final decision in the proceeding in the second quarter of 2016.

2012 General Rate Case (Final 2012 GRC Decision)

In May 2013, the CPUC approved a final decision in the California Utilities’ 2012 GRC. 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 was 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 recovered by SDG&E in rates in 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 2012 GRC Decision recovered in rates in 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, 2015, the 12-month average of monthly Moody’s A-rated utility bond index was 4.04 percent, which is within the established range of 3.24 percent and 5.24 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.

In November 2015, the CPUC granted both SDG&E and SoCalGas an extension of their filing deadlines for one more year to April 2017. This additional extension was made in response to a joint request with the CPUC by SDG&E, SoCalGas, PG&E and Edison. The CPUC also extended the current CCM until the April 2017 filing date. However, in the event the adjustment mechanism is triggered, the utilities agree that no changes to the current cost of capital will be made under the mechanism. In February 2016, the CPUC approved a joint PFM filed by the California Utilities, the ORA and TURN to effectuate the agreement among the parties.

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&ESoCalGas
Authorized weightingAuthorized rate of recoveryWeighted authorized RORAuthorized weightingAuthorized rate of recoveryWeighted authorized ROR
45.25%5.00%2.26%Long-Term Debt45.60%5.77%2.63%
2.75%6.22%0.17%Preferred Stock2.40%6.00%0.14%
52.00%10.30%5.36%Common Equity52.00%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. The California Utilities’ total estimated cost for Phase 1 of the two-phase plan is $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E) over the 10-year period of 2012 to 2022. We anticipate that these costs may be updated to reflect the development of more detailed estimates, actual costs experienced as portions of the work are completed and changes in scope. 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. The costs that are the subject of these plans were outside the scope of the 2012 GRC proceedings concluded in 2013. Similarly, these costs are not included in the California Utilities’ 2016 GRC filings.

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 determined the following for Phase 1 of the program:

  • 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 that were no longer subject to recovery. After taking the amounts disallowed for recovery into consideration, as of December 31, 2015, SDG&E and SoCalGas have recorded PSEP costs of $10 million and $162 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 costs up to the date of the TCAP decision and then annually for costs incurred through the end of each calendar year beginning with the period ended December 31, 2015. SoCalGas and SDG&E currently expect to file such applications no later than the second 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 October 2014, SDG&E and SoCalGas filed a petition for modification with the CPUC requesting authority to begin to recover PSEP costs from customers in the year in which the costs are incurred, subject to refund pending the results of a reasonableness review by the CPUC, instead of in a subsequent year. This request is pending at the CPUC.

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. In June 2015, SDG&E and SoCalGas agreed to remove certain projects from the filing and defer their review to future proceedings and, as a result, are now requesting recovery of $0.1 million and $26.8 million, respectively. The ORA, TURN, and the Southern California Generation Coalition (SCGC) have recommended disallowances related to completed projects, as well as facilities build-out costs, de-scoped projects, and project management and consulting costs. The ORA’s recommended disallowance would result in an $11.1 million decrease to SoCalGas’ original recovery application of $26.8 million, to $15.7 million. The disallowance recommended by TURN and SCGC would result in a $2.3 million decrease to SoCalGas’ original recovery application of $26.8 million, to $24.5 million. We expect a decision on this application in the first half of 2016.

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, the 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. In March 2015, the CPUC issued a decision denying the ORA’s and TURN’s second request for rehearing, but keeping the record in the proceeding open to admit additional evidence on the limited issue of pressure testing of pipelines installed between January 1, 1956 and July 1, 1961. As part of this review, the CPUC will allow parties to submit additional evidence relevant to this narrow issue to ensure a complete record, with no additional discovery allowed. The ORA and TURN filed their responses on May 1, 2015. In December 2015, the CPUC issued a final decision finding that ratepayers should not bear the costs associated with pressure testing subject pipelines, or, if replaced, ratepayers should bear neither the average cost of pressure testing nor the undepreciated balance of abandoned pipelines. Through December 31, 2015, the after-tax disallowed costs for SoCalGas and SDG&E are $3.2 million and $0.5 million, respectively. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. A CPUC decision on the rehearing request is expected in 2016.

Utility Incentive Mechanisms

The CPUC applies performance-based measures and incentive mechanisms to all California investor-owned utilities (IOUs), 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 probable 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 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 year 2012 and for the first half of program year 2013. In December 2015, the CPUC approved awards to SoCalGas and SDG&E of $4.2 million and $6.5 million, respectively, for the second half of program year 2013 and all of program year 2014.

In September 2015, the CPUC issued a decision granting two rehearing requests filed by the ORA and TURN regarding the utility incentive awards for SDG&E and SoCalGas, as well as Edison and PG&E, for program years 2006 through 2008, which totaled $16.2 million for SDG&E and $17.3 million for SoCalGas. The decision directs that the rehearing ensure that the incentive awards granted were just and reasonable and based on calculations verified by the CPUC, or otherwise refunded to customers. We expect a CPUC decision in the second half of 2016.

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.

In 2015, 2014 and 2013, the CPUC approved GCIM awards for SoCalGas of $13.7 million, $5.8 million and $5.4 million, respectively, for the 12-month periods ending March 31, 2014, 2013 and 2012, respectively. In December 2015, the CPUC approved a $7.25 million GCIM award for SoCalGas for the 12-month period ended March 31, 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, 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 was applied to calendar year 2015 and will 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

We discuss SDG&E’s major projects below in “California Utilities – Major Projects.”

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 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 RPS requirements 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.

SB 350, signed into law in October 2015, increased the RPS requirements to 50 percent by 2030, with interim targets of 40 percent by the end of 2024, and 45 percent by the end of 2027. SDG&E expects to be fully compliant with these RPS requirements. We expect the CPUC to begin implementation of SB 350 in 2016.

Sunrise Powerlink Electric Transmission Line

In August 2015, SDG&E filed a petition with the CPUC requesting that it revise and confirm the project cost cap for the Sunrise Powerlink, a 500-kilovolt (kV) electric transmission line between the Imperial Valley and the San Diego region that was energized and placed in service in June 2012. While post-energization construction activities for the project were completed in 2013, certain matters relating to outstanding claims were not resolved until the first quarter of 2015. The filing requests CPUC approval of the final expenditure report for the project and the proposed revisions to the total project cost cap. As evidenced in the final report, and summarized in the table below, actual expenditures for the project totaled $1,887.4 million (in 2012 dollars, on a net present value basis), which exceeds the total project cost cap approved by the CPUC in 2008 (CPUC Approval Decision) by $4.4 million.

SUNRISE POWERLINK ELECTRIC TRANSMISSION LINE – PROPOSED REVISIONS TO TOTAL PROJECT COST CAP
(Dollars in millions)
Total
Construction costsUndergrounding onMitigation(2012 dollars, net
and AFUDCAlpine Blvd.and monitoring costspresent value basis)
Final status report$1,490.9$11.7$384.8$1,887.4
2008 CPUC approval decision1,594.291.0197.81,883.0
Difference$(103.3)$(79.3)$187.0$4.4

Subsequent to the required approvals of the U.S. Department of Interior, Bureau of Land Management in January 2009 and the U.S. Forest Service (USFS) in July 2010, which formed the basis of the CPUC Approval Decision summarized above, the CPUC’s Energy Division and the federal agencies published the Sunrise Final Mitigation Monitoring, Compliance, and Reporting Program (MMCRP). The MMCRP increased the amount of required mitigation activities and costs by $187 million. Offsetting this cost, in part, was a reduction in the total mileage of undergrounding on Alpine Boulevard by approximately two miles. The terms of the CPUC Approval Decision contemplate the potential reduction in undergrounding mileage at an estimated $11 million per one quarter mile. The CPUC Approval Decision did not anticipate the changes in monitoring and mitigation costs. In its petition, SDG&E proposes that the applicable total cost cap be revised and confirmed at the amount of $1,887.4 million. This amount will be the basis used in SDG&E’s FERC-regulated transmission rates. SDG&E expects a CPUC decision on the petition in 2016.

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 the 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 2014, the CPUC authorized SDG&E to collect $221 million of revenue requirement as a result of an ERRA Trigger. SDG&E collected the revenue requirement over the period April 2014 through December 31, 2015. In December 2015, the CPUC approved SDG&E’s 2016 ERRA revenue requirement of $1.3 billion, an increase of $43 million from its 2015 revenue requirement. SDG&E implemented the increased revenue requirement, to be collected in 2016, beginning January 1.

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 Formula 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 sought dismissal of the CPUC’s appeal on procedural grounds, and in December 2015, the Court of Appeal dismissed the appeal.

In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of an estimated $379 million in costs related to the October 2007 wildfires that have been recorded to the Wildfire Expense Memorandum Account (WEMA). These costs represent a portion of the estimated total of $2.4 billion in costs and legal fees that SDG&E has incurred to resolve third-party damage claims arising from the October 2007 wildfires. The requested amount of $379 million is the net estimated cost incurred by SDG&E after deductions for insurance reimbursement ($1.1 billion), third party settlement recoveries ($824 million) and allocations to FERC-jurisdictional rates ($80 million), and reflects a voluntary 10 percent shareholder contribution applied to the net WEMA balance ($42 million). SDG&E requested a CPUC decision by the end of 2016 and is proposing to recover the costs in rates over a six- to ten-year period. Intervening parties have recommended a phased approach, with Phase 1 addressing the reasonableness of SDG&E’s actions leading up to the fires and a CPUC decision in the second half of 2017. Phase 2 would address the reasonableness of settlements entered into by SDG&E, with a CPUC decision in the second half of 2018.

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

Aliso Canyon Natural Gas Storage Facility

We discuss various regulatory matters regarding the Aliso Canyon natural gas storage facility and leak in Note 15.

Increase to CPUC-Authorized Annual Revenue Requirement

In July 2011, SoCalGas updated its testimony in the 2012 GRC to reflect the impact of the extension of temporary bonus depreciation by the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act). The 2010 Tax Act’s extension of bonus depreciation for U.S. federal income tax purposes for years 2010 through 2012 resulted in significant additional tax depreciation deductions. These additional deductions generated U.S. federal NOLs and the creation of an NOL-based deferred tax asset. The 2012 GRC decision denied recovery of any return associated with the NOL-based deferred tax asset unless an IRS Private Letter Ruling (PLR) was obtained, at which point SoCalGas would be authorized to file an advice letter seeking an increase to its revenue requirement.

In February 2015, the IRS issued a PLR that agreed with SoCalGas that the denial of any return on the NOL-based deferred tax asset was a violation of tax normalization rules. In March 2015, SoCalGas filed an advice letter to the CPUC providing the PLR and requesting an increase to its authorized GRC revenue requirement for 2012 through 2015. In April 2015, the CPUC approved the advice letter, and SoCalGas recorded the approved increases for 2012 through 2015, as follows:

APPROVED INCREASES TO THE 2012 GRC ANNUAL REVENUE REQUIREMENTS
(Dollars in millions)
PretaxAfter-tax
2012(1)$6.4$3.8
2013(1)6.33.7
2014(1)6.43.8
2015(2)6.63.9
$25.7$15.2
(1)The approved increase to after-tax earnings was recorded in the second quarter of 2015.
(2)The approved increase to after-tax earnings for the first and second quarters of 2015 of $1.4 million and $0.8 million, respectively, was recorded in the second quarter of 2015. The approved increase to after-tax earnings for the third and fourth quarters of 2015 of $0.6 million and $1.1 million, respectively, was recorded in the respective quarters.

CALIFORNIA UTILITIES — MAJOR PROJECTS

MAJOR PROJECTS – JOINT UTILITIES
(Dollars in millions)
Project descriptionEstimated cost Status
Southern Gas System Reliability Project
§ 2013 application seeking authority to recover the full cost of the project.$800to$850§ In March 2015, CPUC issued a revised project scope and updated schedule.
§ Will enhance reliability on the southern portions of the California Utilities’ integrated natural gas transmission system (Southern System). § If approved, and subject to environmental permitting, the project could commence construction in 2017 and be in service by the end of 2019.
§ Also known as the North-South Gas Project.
Pipeline Safety & Reliability Project
§ September 2015 application seeking authority to recover the full cost of the project, involving construction of an approximately 47-mile, 36-inch natural gas transmission pipeline in San Diego County.$600§ January 2016 ruling directing SDG&E and SoCalGas to file an amended application by March 21, 2016 and provide additional information and analysis regarding various project alternatives.
§ Will implement pipeline safety requirements and modernize the system; improve system reliability and resiliency by minimizing dependence on a single pipeline; and enhance operational flexibility to manage stress conditions by increasing system capacity. § After CPUC approval, and subject to timing of other approvals, will take approximately 24 to 36 months to construct.

MAJOR PROJECTS – SDG&E
(Dollars in millions)
Project descriptionEstimated cost Status
Cleveland National Forest (CNF) Transmission Projects
§ 2012 application for permit to construct various transmission line replacement projects in and around CNF.$400to$450§ Alternatives identified in July 2015 joint CPUC/USFS environmental impact report (EIR/EIS), if approved by CPUC and USFS, would result in an increase to the estimated cost of the projects.
§ To replace and fire-harden five existing transmission lines.§ Separate USFS and CPUC decisions on the transmission projects expected in the first half of 2016.
§ Various phases expected to be placed in service starting in 2016 and continuing through 2019.
Sycamore-Peñasquitos Transmission Project
§ 230-kV transmission project to provide 16.7-mile transmission connection between Sycamore Canyon and Peñasquitos substations. $120to$150§ In March 2014, California ISO selected SDG&E in a competitively bid process to construct the project, which we originally estimated to cost $120 million to $150 million.
§ California ISO and state task force identified as necessary to ensure grid reliability given the closure of SONGS. § September 2015 draft EIR/EIS recommends an alternative that undergrounds more of the project than originally proposed. The CPUC may consider this alternative which has an estimated cost of $250 million to $300 million.
§ CPUC decision expected in the first half of 2016, with the line expected to be in service in mid-2017.
South Orange County Reliability Enhancement
§ 2012 application for Certificate of Public Convenience and Necessity (CPCN) to enhance the capacity and reliability of electric service to the south Orange County area.$350to$400§ Final CPUC decision expected in the first half of 2016.
§ Replacing and upgrading approximately eight miles of transmission lines and rebuilding and upgrading a substation at an existing site.§ Planned in phases; entire project expected to be in service in 2020.
South Bay Substation and Relocation Project
§ 2010 application with the CPUC for permit to construct new Bay Boulevard substation to replace the aging and obsolete South Bay substation. $145to$175§ July 2014 petition filed with the CPUC requesting modifications to the prior CPUC decision to authorize additional construction activities required by the coastal development permit.
§ Demolish existing substation when the Bay Boulevard substation has been constructed, energized and all transmission lines have been transferred. § CPUC approved the petition for modification in January 2015. Project expected to be in service in 2017.
Electric Vehicle Charging Program
§ April 2014 proposal for program to build and own a total of 5,500 electric vehicle charging units at estimated cost of $103 million, of which $59 million is capital investment. $45§ January 2016 CPUC final decision denies proposal but authorizes a 3-year, $45 million program providing up to 3,500 charging units.
§ Hourly Vehicle-to-Grid Integration rate to incent vehicle charging during times of the day that benefit the power grid.
Distribution Resource Plan
§ July 2015 application filed with the CPUC submitting Distribution Resource Plan. Distributed energy resources (DER) are typically smaller power sources connected to the distribution grid and located near load centers. TBD§ SDG&E expects the CPUC to address the Distribution Resource Plan in a phased manner with more than one decision issued in the 2016 to 2017 time period.