CALIFORNIA UTILITIES' REGULATORY MATTERS

3 Months Ended

Sep. 30, 2015

Notes to Consolidated Financial Statements [Abstract]

NOTE 10. CALIFORNIA UTILITIES' REGULATORY MATTERS

We discuss regulatory 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.

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 March 2015, the California Utilities revised their requests to make various updates and reflect the impact of the Tax Increase Prevention Act signed into law in December 2014. At SoCalGas, this resulted in a reduction of $10 million compared to its original request, or a total revenue requirement in 2016 of $2.342 billion. This is an increase of $246 million or 12 percent over 2015, excluding the impact of the 2015 revenue requirement increase discussed below under “SoCalGas Matters — Increase to CPUC-Authorized Annual Revenue Requirement.” At SDG&E, the March 2015 revised request resulted in a reduction of $6 million compared to its original request, or a total revenue requirement in 2016 of $1.905 billion. This is an increase of $111 million or 6 percent over 2015. This increase includes an adjustment of $16 million to the comparable 2015 estimated revenue requirement since the November 2014 filings.

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 deductions, discussed below. The settlement agreements are with eight of eleven intervening parties. For SoCalGas, the settlement proposes a reduction of $133 million compared to its original request, or a total revenue requirement in 2016 of $2.219 billion. This is an increase of $122 million or 6 percent over 2015. For SDG&E, the settlement proposes a reduction of $100 million compared to its original request (as revised), or a total revenue requirement in 2016 of $1.811 billion. This is an increase of $17 million, or one percent over 2015. 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.

The settlement agreements described above exclude a proposal that, for both SDG&E and SoCalGas, certain intra-rate case income tax benefits should be, in effect, refunded and passed to ratepayers. 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. The proposal recommends that the CPUC adjust SDG&E’s rate base by $93 million and SoCalGas’ rate base by $92 million, and additionally reduce both utilities’ revenue requirements by amounts currently being tracked in tax memorandum accounts for the year 2015. At September 30, 2015, the pretax balances tracked in these memorandum accounts total $46 million for SoCalGas and $34 million for SDG&E. If this proposal is adopted, the outcome would reduce the revenue requirement amounts agreed to in the respective settlement agreements described above.

We anticipate all matters to be resolved with the final resolution of the 2016 GRC. We expect the CPUC to issue a draft decision in the proceeding in the first quarter of 2016.

Natural Gas Pipeline Operations Safety Assessments

In June 2014, the CPUC issued a final decision in the Triennial Cost Allocation Proceeding (TCAP) addressing SDG&E’s and SoCalGas’ Pipeline Safety Enhancement Plan (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;
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 September 30, 2015, SDG&E and SoCalGas have recorded PSEP costs of $7 million and $153 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 ending 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. In August 2015, the ORA, TURN and the Southern California Generation Coalition (SCGC) served testimony to the CPUC that 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. In August 2015, the California Utilities also provided testimony to the CPUC, contesting the proposed disallowances. 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 October 2015, the CPUC issued a proposed 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 pipeline. At September 30, 2015, SoCalGas and SDG&E estimate amounts related to these costs to be approximately $5 million and $3 million, respectively.

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 originally proposed, the project consisted 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. In March 2015, the CPUC issued a revised scoping ruling establishing a schedule, directing that the Moreno-Whitewater portion of the original project be excluded from scope and that any other future projects would be addressed separately. The estimated cost of the revised project, including updated cost estimates, remains unchanged from the original cost estimate of between $800 million and $850 million, while providing comparable benefits for customers. If approved by the CPUC and subject to environmental permitting, given the revised project scope and updated schedule in this proceeding, the project could commence construction in 2017 and be in service by the end of 2019.

Pipeline Safety & Reliability Project

In September 2015, SDG&E and SoCalGas filed an application with the CPUC seeking authority to recover the full cost of the Pipeline Safety & Reliability Project. The project involves construction of an approximately 47-mile, 36-inch natural gas transmission pipeline in San Diego County from SDG&E’s existing Rainbow Metering Station near the Riverside County line to Marine Corps Air Station (MCAS) Miramar. We estimate the project costs to be $600 million and that it will take approximately 24 to 36 months to construct after CPUC approval is received, depending on the timing of other approvals. The new pipeline 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. The project is a part of the PSEP work described above. The final resolution of this project will help define the scope of work to be completed under PSEP.

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.

Natural Gas Procurement

In February 2015, the CPUC issued a final decision approving SoCalGas’ application for a gas cost incentive mechanism (GCIM) award of $13.7 million for natural gas procured for its core customers during the 12-month period ended March 31, 2014. SoCalGas recorded this award in the first quarter of 2015.

In June 2015, SoCalGas filed an application for a GCIM award of $7.25 million for natural gas procured for its core customers during the 12-month period ended March 31, 2015. We expect a CPUC decision in the first half of 2016.

Energy Efficiency Programs

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 Pacific Gas and Electric Company, 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.

SDG&E MATTERS

SONGS

We discuss regulatory and other matters related to SONGS in Note 9.

2007 Wildfire Cost Recovery

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 Federal Energy Regulatory Commission (FERC)-jurisdictional rates ($80 million), and reflects a voluntary 10 percent shareholder contribution applied to the net WEMA balance ($42 million). In a prior decision, the CPUC granted SDG&E authority to record its costs associated with the October 2007 wildfires in the WEMA and to seek rate recovery subject to a reasonableness review of the costs. 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.

We provide additional information about 2007 wildfire litigation costs and their recovery in Note 11.

Power Procurement and Resource Planning

Cleveland National Forest Transmission Projects

SDG&E filed an application with the CPUC in October 2012 for a permit to construct various transmission line replacement projects in and around the Cleveland National Forest (CNF). The proposed projects will replace and fire-harden five existing transmission lines at an estimated cost of between $400 million and $450 million, as originally proposed. As directed by the CPUC, SDG&E filed an amended application in June 2013 to provide notice of certain alternatives proposed by the United States 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 final environmental impact report (EIR/EIS), developed jointly by the CPUC and USFS, was issued in July 2015 identifying alternatives to the proposed project which, if approved by both the CPUC and USFS, would result in an increase to the estimated cost of the projects. SDG&E currently expects separate USFS and CPUC decisions on the transmission projects in the first half of 2016 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, as originally proposed, 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 return on equity (ROE) adder for this project. In April 2015, FERC issued an order granting SDG&E’s request for 100 percent abandoned plant cost recovery, but denying an ROE adder for the project. In September 2015, a draft environmental report was issued recommending an environmentally superior alternative that would underground more of the project than originally proposed. SDG&E estimates that the cost of the recommended alternative is $250 million to $300 million. SDG&E expects a CPUC decision on 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 for the South Orange County Reliability Enhancement project. A draft environmental report was issued in the first quarter of 2015. In August 2015, portions of the draft environmental report were recirculated for public comment on additional project alternatives. SDG&E expects a final CPUC decision on the estimated $350 million to $400 million project in the first half of 2016. As the project is planned in phases, SDG&E currently expects the entire project to be in service in 2020.

Electric Vehicle Charging Program

In April 2014, SDG&E filed a proposal with the CPUC requesting approval of a program under which SDG&E would build and own a total of 5,500 electric vehicle charging stations at an estimated cost of $103 million, of which $59 million is capital investment. Under the program, SDG&E will provide an hourly Vehicle-to-Grid Integration (VGI) rate that will help incent participants to charge their vehicles during times of the day that benefit the power grid. In June 2015, SDG&E and sixteen other parties representing the electric vehicle charging industry, auto manufacturers, labor, and environmental and social justice organizations filed a settlement agreement proposing a modified program that still allows SDG&E to build and own a total of 5,500 charging stations. The settlement is opposed by certain consumer advocates and other parties. SDG&E expects a CPUC decision in the fourth quarter of 2015.

Distribution Resource Plan

In July 2015, SDG&E filed an application with the CPUC submitting its Distribution Resource Plan. Distributed energy resources (DER) are typically smaller power sources, including advanced renewable and energy storage technologies, that are connected to the distribution grid and located near load centers. The distribution resource plan sets out a planning and investment framework comprised of three basic categories: 1) capital investments that can be potentially deferred or replaced by DER solutions; 2) capital investment needed to accommodate higher DER deployment levels; and 3) traditional distribution investments that cannot be deferred or displaced by DER. SDG&E’s planning framework would be used to determine future capital investment needs, which would then be addressed through its GRC process. The Distribution Resource Plan also proposes a number of demonstration projects and describes potential projects and investment that would support higher DER deployment. SDG&E expects a CPUC decision in the first half of 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-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 costs		Undergrounding on		Mitigation		(2012 dollars, net
	and AFUDC		Alpine Blvd.		and monitoring costs		present value basis)
Final status report	$	1,490.9	$	11.7	$	384.8	$	1,887.4
2008 CPUC approval decision		1,594.2		91.0		197.8		1,883.0
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 (BLM) in January 2009 and the 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. Off-setting 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 billion. 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.

SOCALGAS MATTERS

Triennial Cost Allocation Proceeding (TCAP) – Adoption of Seasonal Factors

The TCAP decision issued by the CPUC in June 2014 for SoCalGas included, among other matters, the requirement for SoCalGas to apply seasonal factors throughout the year to SoCalGas’ annual authorized revenue for its core natural gas customers effective January 1, 2015. Core customers are primarily residential and small commercial and industrial customers. The seasonal factors adopted are based on the core demand forecast provided by SoCalGas in the TCAP application. Prior to this decision, this annual authorized revenue was recognized ratably over the year. While this “seasonalization” will not impact SoCalGas’ total calendar year revenue or earnings for 2015 or beyond, and does not change the annual total authorized revenue or our earnings from that revenue, it will cause variability in revenue and earnings from quarter to quarter. We expect that as a result of applying the seasonal factors during interim periods to the annual authorized revenue requirement, the core natural gas customer authorized revenue recognized in the first and fourth quarters of each year beginning with 2015 will be higher (approximately 34 percent in the first quarter and 29 percent in the fourth quarter) than that recognized in the second and third quarters of each year (approximately 21 percent in the second quarter and 16 percent in the third quarter). This compares to recognizing 25 percent of the annual authorized revenue in each quarter in prior years. As a result, beginning in 2015, substantially all of SoCalGas’ annual earnings will be recognized in the first and fourth quarters of the year.

Seasonalization will not impact interim period cash flows or customers’ bills. However, it should reduce the interim period variability in regulatory balancing accounts, as we expect customer billings to more closely align with interim period revenue recognition. This seasonalization is consistent with SDG&E’s natural gas and power distribution authorized revenue treatment.

The CPUC regulatory framework authorizes SoCalGas to recover the actual cost of natural gas procured and delivered to its core customers in rates substantially as incurred. The regulatory framework also permits SoCalGas to recover its cost of operations, including depreciation of its fixed assets, in authorized revenue based on estimated annual natural gas demand forecasts approved in the TCAP, and any difference between actual gas demand and the annual natural gas demand approved in the TCAP is recovered in authorized revenue in the subsequent year. This design, commonly known as “decoupling,” is intended to minimize any impact on SoCalGas’ earnings of changes in the cost of natural gas procured and any variability in customer demand for natural gas. The adoption of applying seasonal factors to authorized annual revenue requirement for interim periods does not change the application of decoupling.

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 net operating losses (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’ position 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 provide the PLR to the CPUC and request an increase to its authorized GRC revenue requirement for 2012 through 2015 to comply with the normalization requirements as interpreted by the IRS in the PLR. In April 2015, the CPUC approved SoCalGas’ advice letter. The approved increases to the pretax annual revenue requirements are $6.4 million for 2012, $6.3 million for 2013, $6.4 million for 2014 and $6.6 million for 2015. The resulting increase to after-tax earnings of an aggregate of $11.3 million for years 2012 through 2014 and $1.4 million and $0.8 million related to the first and second quarters of 2015, respectively, was recorded in the second quarter of 2015. The amount recorded in the third quarter of 2015 was $0.6 million after tax, and the remaining 2015 after-tax earnings of $1.1 million resulting from this revenue increase will be recognized in the fourth quarter of 2015.