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REGULATORY MATTERS

12 Months Ended

Dec. 31, 2018

REGULATORY MATTERS

REGULATORY ASSETS AND LIABILITIES

We show the details of regulatory assets and liabilities in the following table and discuss them below.



REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	December 31,
	2018			2017
SDG&E:
Fixed-price contracts and other derivatives	$	(150	)	$	96
Deferred income taxes refundable in rates	(236		)	(281		)
Pension and other postretirement benefit plan obligations	186			153
Removal obligations	(1,848		)	(1,846		)
Unamortized loss on reacquired debt	7			9
Environmental costs	28			29
Sunrise Powerlink fire mitigation	120			119
Regulatory balancing accounts⁽¹⁾
Commodity – electric	(8		)	82
Gas transportation	45			22
Safety and reliability	70			48
Public purpose programs	(62		)	(70		)
Other balancing accounts	145			233
Other regulatory liabilities, net⁽²⁾	(177		)	(70		)
Total SDG&E	(1,880		)	(1,476		)
SoCalGas:
Pension and other postretirement benefit plan obligations	470			513
Employee benefit costs	49			45
Removal obligations	(833		)	(924		)
Deferred income taxes refundable in rates	(336		)	(437		)
Unamortized loss on reacquired debt	7			8
Environmental costs	28			22
Workers’ compensation	9			12
Regulatory balancing accounts⁽¹⁾
Commodity – gas, including transportation	196			151
Safety and reliability	332			266
Public purpose programs	(325		)	(274		)
Other balancing accounts	(68		)	(114		)
Other regulatory liabilities, net⁽²⁾	(130		)	(64		)
Total SoCalGas	(601		)	(796		)
Sempra Mexico:
Deferred income taxes recoverable in rates	81			83
Other regulatory assets	6			—
Total Sempra Energy Consolidated	$	(2,394	)	$	(2,189	)


⁽¹⁾	At December 31, 2018 and 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $78 million and $63 million, respectively. At December 31, 2018 and 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $185 million and $118 million, respectively.


⁽²⁾	Includes regulatory assets earning a rate of return.

In the table above:

▪

Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts. We discuss fixed-price contracts and other derivatives further in Note 11.

▪

Deferred income taxes refundable/recoverable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Mexico expect to refund/recover net regulatory liabilities/assets related to deferred income taxes over the lives of the assets that give rise to the related accumulated deferred income tax balances. Regulatory assets include certain income tax benefits associated with flow-through repair allowance deductions, which we discuss further below.


▪	Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets and are being recovered in rates as the plans are funded.


▪	The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.


▪	Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs in excess of cumulative amounts incurred (or paid).


▪	Regulatory assets related to unamortized loss on reacquired debt are recovered over the remaining amortization periods of the losses on reacquired debt. These periods range from 1 year to 9 years for SDG&E and from 3 years to 7 years for SoCalGas.


▪	Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made. We discuss environmental issues further in Note 16.


▪	The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 51-year period. We discuss the trust further in Note 16.


▪	The regulatory asset related to workers’ compensation represents accrued costs for future claims that will be recovered from customers in future rates as expenditures are made.

▪

Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs, including commodity costs. Depreciation and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. Absent balancing account treatment, variations in covered costs, such as the cost of fuel supply and certain O&M costs, from amounts approved by the CPUC would increase volatility in utility earnings. Balancing account treatment eliminates the volatility in earnings that would otherwise result from variances in the covered costs compared to the authorized amounts.

Amortization expense on regulatory assets for the years ended December 31, 2018, 2017 and 2016 was $5 million, $50 million and $65 million, respectively, at Sempra Energy Consolidated, $2 million, $49 million and $63 million, respectively, at SDG&E, and $3 million, $1 million and $2 million, respectively, at SoCalGas.

CALIFORNIA UTILITIES

CPUC General Rate Case

The CPUC uses a GRC proceeding to set sufficient rates to allow the California Utilities to recover their reasonable cost of O&M and to provide the opportunity to realize their authorized rates of return on their investment.

2019 General Rate Case

On October 6, 2017, SDG&E and SoCalGas filed their 2019 GRC applications requesting CPUC approval of test year revenue requirements for 2019 and attrition year adjustments for 2020 through 2022. SDG&E and SoCalGas are seeking revenue requirements for 2019 of $2.203 billion and $2.937 billion, respectively, which is an increase of $221 million and $481 million over their respective 2018 revenue requirements (the 2019 proposed and 2018 actual revenue requirements reflect the impact of various updates made during the course of the proceeding). The California Utilities are proposing post-test year revenue requirement annual attrition percentages that are estimated to result in annual increases of approximately 5 percent to 7 percent at SDG&E and approximately 6 percent to 8 percent at SoCalGas. The original GRC applications filed in October 2017 did not reflect the impact of the TCJA, which we discuss below in “2016 General Rate Case” and in Note 8. In April 2018, SDG&E and SoCalGas updated their applications to reflect the impact of the TCJA and filed a joint proposal to address the impacts. The TCJA impact to SDG&E is a reduction of approximately $58 million to its 2019 test year revenue requirement; however, SDG&E’s 2019 requested revenue requirement is unchanged as we evaluate potentially higher costs associated with mitigating wildfire risks. The TCJA impact to SoCalGas’ 2019 requested revenue requirement is a reduction of approximately $58 million, which is reflected in its updated request.

During the course of the proceeding, Cal PA recommended 2019 revenue requirements of $1.918 billion and $2.695 billion for SDG&E and SoCalGas, respectively, which is a net decrease of $64 million for SDG&E and a net increase of $239 million for SoCalGas compared to the 2018 revenue requirements. Cal PA proposes a three-year annual attrition percentage of 4 percent for

SDG&E and a range of 4 percent to 5 percent for SoCalGas. Cal PA recommends addressing SDG&E’s potential ownership of OMEC in a separate proceeding. As a result, Cal PA’s proposed 2019 revenue requirement does not include the estimated $68 million associated with owning and operating the generating facility. SDG&E’s potential acquisition of OMEC is subject to a CPUC-approved agreement under which the current owner of the facility can exercise a put option at a designated price. As we discuss in Note 1, SDG&E and OMEC LLC signed a resource adequacy capacity agreement in October 2018, which, if approved by the CPUC on a final and non-appealable basis before the expiration of the put option on April 1, 2019, would result in OMEC LLC waiving its right to exercise the put option. TURN and other intervenors oppose various components of our revenue requirement requests in the 2019 GRC applications.

As part of the 2019 GRC, the CPUC reviewed the California Utilities’ interim accountability reports, which compare the authorized and actual spending for certain safety-related activities for 2014 through 2016. In June 2017, SDG&E and SoCalGas filed their first interim accountability reports comparing authorized and actual spending in 2014 and 2015 for certain safety-related activities. Similar data for 2016 was provided with the 2019 GRC application filings in a second interim accountability report filed in October 2017. The stated purpose of the initial interim accountability reports is to provide data and metrics for key safety and risk mitigation areas that will be considered in the 2019 GRC. In October 2018, the CPUC confirmed that the 2014, 2015 and 2016 interim accountability reports were compliant with the requirements and also recommended improvements for subsequent reports.

The results of the rate case may materially and adversely differ from what is contained in the GRC applications.

We expect a preliminary decision from the CPUC in the first half of 2019.

Risk Assessment Mitigation Phase Reporting and Impact on the 2019 GRC Application Filings

In December 2014, the CPUC issued a decision incorporating a risk-based decision-making framework into all future GRC application filings for major natural gas and electric utilities in California. In November 2016, as part of the new framework, SDG&E and SoCalGas filed their first RAMP report presenting a comprehensive assessment of their key safety risks and proposed activities for mitigating such risks. The report details these key safety risks, which include critical operational issues such as natural gas pipeline safety and wildfire safety, and addresses their classification, scoring, mitigation, alternatives, safety culture, quantitative analysis, data collection and lessons learned. SDG&E and SoCalGas included funding requests in their respective 2019 GRC filings for proposed projects or activities outlined in their RAMP reports. In April 2018, the CPUC granted SDG&E’s and SoCalGas’ motion to close the proceeding as all RAMP procedures had been completed. In December 2018, the CPUC approved a joint settlement agreement that establishes the required elements for the risk and mitigation analysis to be used in RAMP and GRC proceedings with minor modifications.

Senate Bill 549. SB 549 was signed into law in September 2017 and became effective January 1, 2018. The bill requires that SDG&E and SoCalGas (as electric and gas corporations) annually notify the CPUC when revenue authorized by the CPUC for maintenance, safety or reliability is redirected to other purposes. Beginning in December 2018, the CPUC began incorporating and will continue to incorporate this requirement into the accountability reports.

2016 General Rate Case

In June 2016, the CPUC issued a final decision in the 2016 GRC. The 2016 GRC FD adopted a 2016 revenue requirement of $1.791 billion for SDG&E and $2.204 billion for SoCalGas. The 2016 GRC FD was effective retroactive to January 1, 2016, and the California Utilities recorded the retroactive impacts in the second quarter of 2016. The 2016 GRC FD also required certain refunds to be paid to customers and establishes a two-way income tax expense memorandum account, each discussed below.

The 2016 GRC FD results in certain accounting impacts associated with flow-through income tax repairs deductions. In general, the 2016 GRC FD considers that the income tax benefits obtained from income tax repairs deductions exceeded amounts forecasted by the California Utilities from 2011 to 2015, and that they were attributed to shareholders during that time. The 2016 GRC FD reallocated the economic benefit of this tax deduction forecasting difference to ratepayers. Accordingly, revenues corresponding to income tax repair deductions that exceeded forecasted amounts were ordered to be refunded to customers. Pursuant to this refund requirement, in 2016, SDG&E and SoCalGas recorded regulatory liabilities for these amounts, resulting in reductions to revenue of $52 million ($31 million after tax) and $83 million ($49 million after tax), respectively.

The 2016 GRC FD required SDG&E and SoCalGas to each establish a two-way income tax expense memorandum account to track certain revenue variances resulting from certain differences between the income tax expense forecasted in the GRC and the income tax expense incurred from 2016 through 2018. The variances to be tracked include tax expense differences relating to:


▪	net revenue changes;


▪	mandatory tax law, tax accounting, tax procedural, or tax policy changes; and


▪	elective tax law, tax accounting, tax procedural, or tax policy changes.

At December 31, 2018, the recorded regulatory liability associated with these tracked amounts totaled $89 million and $94 million for SDG&E and SoCalGas, respectively. The recorded liability is primarily related to lower income tax expense incurred than was forecasted in the GRC relating to tax repairs deductions, self-developed software deductions and certain book-over-tax depreciation. The tracking accounts will remain open until the CPUC decides to close the accounts, which we expect will be reviewed in the 2019 GRC proceedings.

The 2016 GRC FD revenue requirement was authorized using a federal income tax rate of 35 percent. As a result of the TCJA, the federal income tax rate became 21 percent effective January 1, 2018. Since SDG&E and SoCalGas continue to collect authorized revenues based on a 35 percent tax rate, SDG&E and SoCalGas are recording revenue deferrals, aligned with authorized seasonality factors, that reflect the estimated reduction in the revenue requirement. As of December 31, 2018, SDG&E and SoCalGas recorded regulatory liabilities of $75 million and $68 million, respectively, in anticipation of amounts that will benefit customers in future rates. SDG&E also recorded a $67 million regulatory liability at December 31, 2018, relating to its FERC jurisdictional rates, in anticipation of amounts that will benefit customers in future rates for the decrease in the federal income tax rate.

CPUC Cost of Capital

In September 2017, SDG&E and SoCalGas filed advice letters to update their cost of capital for the actual cost of long-term debt through August 2017 and forecasted cost through 2018. SDG&E and SoCalGas did not file for changes to preferred stock costs, because no issuances of preferred stock through 2018 were anticipated.

In October 2017, the CPUC approved the embedded cost of debt presented in advice letters filed by SDG&E and SoCalGas, resulting in a revised return on rate base for SDG&E of 7.55 percent and for SoCalGas of 7.34 percent, effective January 1, 2018, as depicted in the table below:



AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE – CPUC

SDG&E							SoCalGas
Authorized weighting		Return on rate base		Weighted return on rate base			Authorized weighting		Return on rate base		Weighted return on rate base
45.25	%	4.59	%	2.08	%	Long-Term Debt	45.60	%	4.33	%	1.97	%
2.75		6.22		0.17		Preferred Stock	2.40		6.00		0.14
52.00		10.20		5.30		Common Equity	52.00		10.05		5.23
100.00	%			7.55	%		100.00	%			7.34	%

The changes to the embedded cost of debt and return on rate base resulting from the updates included in the filed advice letters are summarized below:



CHANGES TO THE EMBEDDED COST OF DEBT

	SDG&E						SoCalGas
	Cost of debt			Return on rate base			Cost of debt			Return on rate base
Previously	5.00		%	7.79		%	5.77		%	8.02		%
Authorized, effective January 1, 2018	4.59		%	7.55		%	4.33		%	7.34		%
Differences	(41	)	bps	(24	)	bps	(144	)	bps	(68	)	bps

The costs of long-term debt and the ROEs shown above will remain in effect through December 31, 2019. The cost of capital changes will also apply to capital expenditures in 2019 for incremental projects not funded through the GRC revenue requirement. SDG&E and SoCalGas are required to file cost of capital applications by the end of April 2019 for a January 1, 2020 implementation date. The automatic CCM did not operate in 2018 and will be evaluated in the 2019 cost of capital proceeding.

SDG&E

FERC Rate Matters and Cost of Capital

SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets.

SDG&E’s current estimated FERC return on rate base under the TO4 formula rate request filing is 7.51 percent based on its capital structure as follows:



SDG&E COST OF CAPITAL AND RATE STRUCTURE – FERC

	Weighting		Return on rate base		Weighted return on rate base
Long-Term Debt	43.44	%	4.21	%	1.83	%
Common Equity	56.56		10.05		5.68
	100.00	%			7.51	%

FERC Formulaic Rate Filing

SDG&E submitted its TO5 filing with the FERC in October 2018 to be effective January 1, 2019, subject to refund. This proceeding will establish the revenue requirement, including rate of return, for SDG&E’s FERC-regulated electric transmission operations and assets. SDG&E’s TO5 filing proposes to continue most aspects of its existing FERC-authorized formula rate. SDG&E’s TO5 filing is requesting: (1) rates to be determined by a base period of historical costs and a forecast of capital investments, (2) a true-up period, which is similar to a balancing account that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including its authorized return on investment, (3) a true-up of accumulated deferred income tax and (4) a refund of amounts collected in rates in 2018 that presumed a 35 percent federal income tax rate. The net impact of our TO5 filing is a revenue requirement of $911 million, an increase in rates of $88 million, or 10.6 percent, above 2018’s revenue requirement.

This TO5 proceeding will also set SDG&E’s authorized FERC ROE. SDG&E’s current authorized FERC ROE is 10.05 percent, and SDG&E’s TO5 filing proposes a FERC ROE of 11.2 percent. On December 31, 2018, the FERC issued its order accepting and suspending the TO5 filing and establishing hearing and settlement judge procedures. In the order, the FERC suspended the TO5 filing for five months, during which the existing TO4 rates will remain in effect. After the suspension period ends, the proposed TO5 rates will take effect, subject to refund and the outcome of the hearing and settlement judge procedures. A FERC settlement judge has been appointed, and we expect settlement conferences to begin in the first quarter of 2019.

SEMPRA SOUTH AMERICAN UTILITIES

Luz del Sur serves primarily regulated customers in Peru and revenues are based on rates set by the OSINERGMIN. The rates are reviewed and adjusted every four years. OSINERGMIN’s final distribution rate-setting resolution for the 2018-2022 period was published on October 16, 2018 and went into effect on November 1, 2018. The resolution decreases the rates Luz del Sur can charge its regulated customers, resulting in a modest reduction in regulated revenues per annum. Luz del Sur submitted a petition for reconsideration to the regulator in November 2018 and obtained a favorable response in late December 2018 that reduces the negative impact to rates from the resolution published on October 16, 2018. The adjustment is retroactive to November 1, 2018.

Chilquinta Energía serves regulated and unregulated customers in Chile. Distribution revenues and rates are reviewed and set by the CNE every four years; the most recent review process was completed in November 2016, covering the period from November 2016 through October 2020. On September 28, 2018, a distribution interim rate case, which included an adjustment to rates, was approved to allow adequate recovery of the incremental investment, including the deployment of smart meters to all customers, necessary to comply with the new distribution standards set by the CNE in December 2017. These interim adjusted rates will be applicable from September 28, 2018 through October 2020.

Chilquinta Energía’s most recent review process for zonal transmission rates was completed in September 2017. The final decree approving the rates was published on October 5, 2018. The authorized transmission rates will cover the period from January 2018 through December 2019.

As we discuss in Note 5, Chilquinta Energía acquired CTNG in December 2018. CTNG owns both national and zonal transmission assets. CTNG’s most recent review process for national transmission rates was completed in 2015 and covers the period from January 2016 to December 2019. The review process for zonal transmission rates was completed in 2017 and covers the periods from January 2018 to December 2019.

SEMPRA MEXICO

On July 23, 2018, the CRE adjusted Ecogas’ natural gas distribution rates charged to end-users in 2014 through 2016. Ecogas recorded a regulatory asset of $7 million for this tariff adjustment, which is recoverable in rates effective September 1, 2018 through December 31, 2020.SAN ONOFRE NUCLEAR GENERATING STATION

SDG&E has a 20-percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which ceased operations in June 2013. On June 6, 2013, after an extended outage beginning in 2012, as a result of issues with the steam generators used in the facility, Edison, the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.

SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of costs. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Consolidated Statements of Operations.

SONGS STEAM GENERATOR REPLACEMENT PROJECT

The replacement steam generators, which caused a water leak due to unexpected tube wear, were designed and provided by MHI. In 2013, Edison instituted arbitration proceedings against MHI seeking recovery of damages resulting from the issues with the steam generators used in SONGS Units 2 and 3. The other SONGS co-owners, SDG&E and the City of Riverside, participated as claimants and respondents.

On March 13, 2017, the International Chamber of Commerce International Court of Arbitration Tribunal (the Tribunal) overseeing the arbitration found MHI liable for breach of contract, subject to a contractual limitation of liability, and rejected claimants’ other claims. The Tribunal awarded $118 million in damages to the SONGS co-owners, but determined that MHI was the prevailing party and awarded it 95 percent of its arbitration costs. The damage award is offset by these costs, resulting in a net award of approximately $60 million in favor of the SONGS co-owners. SDG&E’s specific allocation of the damage award is $24 million reduced by costs awarded to MHI of approximately $12 million, resulting in a net damage award of $12 million, which was paid by MHI to SDG&E in March 2017. In accordance with the Amended Settlement Agreement discussed below, SDG&E recorded the proceeds from the MHI arbitration by reducing O&M for previously incurred legal costs of $11 million, and shared the remaining $1 million equally between ratepayers and shareholders.

SETTLEMENT AGREEMENT TO RESOLVE THE CPUC’S ORDER INSTITUTING INVESTIGATION INTO THE SONGS OUTAGE

In 2012, in response to the SONGS outage, the CPUC issued the SONGS OII, which was intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage.

In 2014, the CPUC issued a final decision approving an Amended Settlement Agreement which provided for various disallowances, refunds and rate recoveries, including authorizing SDG&E to recover in rates its remaining investment in SONGS, excluding its investment in the Steam Generator Replacement Project.

In 2016, the CPUC issued two procedural rulings: the first, to reopen the record of the OII to address the issue of whether the Amended Settlement Agreement is reasonable and in the public interest, and the second, directing parties to the SONGS OII to determine whether an agreement could be reached to modify the Amended Settlement Agreement previously approved by the CPUC, to resolve allegations that unreported ex parte communications between Edison and the CPUC resulted in an unfair advantage at the time the settlement agreement was negotiated.

In July 2018, the CPUC approved a Revised Settlement Agreement among SDG&E, Edison, Cal PA, TURN and other intervenors that resolved all issues under consideration in the SONGS OII and made one modification to the Amended Settlement Agreement to remove the requirement to fund a GHG emissions reduction research program. In August 2018, parties to the Revised Settlement Agreement submitted a notice that they accepted the settlement agreement, as modified.

In connection with the Revised Settlement Agreement, and in exchange for the release of certain SONGS-related claims, SDG&E and Edison entered into the Utility Shareholder Agreement, described below.

Disallowances, Refunds and Recoveries

Under the Revised Settlement Agreement, SDG&E and Edison ceased rate recovery of SONGS costs as authorized under the Amended Settlement Agreement as of December 19, 2017, when the present value of their combined remaining SONGS regulatory assets equaled $775 million, of which $152 million represents SDG&E’s share. Under the Utility Shareholder Agreement, Edison is obligated to pay SDG&E the full amount of SDG&E’s revenue requirement not recovered from ratepayers, as described below. In October 2018, SDG&E began refunding to customers SONGS-related amounts recovered in rates after December 19, 2017.

Utility Shareholder Agreement

In January 2018, SDG&E and Edison entered into the Utility Shareholder Agreement under which Edison has an obligation to compensate SDG&E for the revenue requirement amounts that SDG&E will no longer recover because of the Revised Settlement Agreement. In exchange for Edison’s reimbursement, the parties mutually released each other from the “SONGS Issues,” a defined term that consists of 18 broad categories. The effect of the agreement is that the parties released each other from any and all claims that each party had or could have asserted related to the steam generator replacement failure and its aftermath. The Utility Shareholder Agreement became effective upon CPUC approval of the Revised Settlement Agreement. Edison’s payment obligation commenced in October 2018, and amounts are due to SDG&E quarterly thereafter until April 2022. At December 31, 2018, SDG&E has a receivable from Edison, including accrued interest, totaling $124 million, with $40 million classified as current and $84 million classified as noncurrent. This receivable reflects amounts Edison is obligated to pay to SDG&E in lieu of amounts SDG&E would have collected from ratepayers associated with the SONGS regulatory asset.

NUCLEAR DECOMMISSIONING AND FUNDING

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be done once Units 2 and 3 are dismantled and the spent fuel is removed from the site. Edison contracted with a JV of AECOM and EnergySolutions (known as SONGS Decommissioning Solutions) as the general contractor to complete the dismantlement of SONGS. The majority of the dismantlement work is expected to take 10 years. SDG&E is responsible for approximately 20 percent of the total contract price.

In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. The NDT assets are presented on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.

In March 2018, SDG&E and Edison jointly filed an application requesting CPUC approval of revised remaining decommissioning cost estimates (for costs estimated to be incurred in 2018 and beyond) for SONGS Unit 1 of $207 million (in 2014 dollars), of which SDG&E’s share is $41 million, and SONGS Units 2 and 3 of $3.2 billion (in 2014 dollars), of which SDG&E’s share is $638 million. In addition, SDG&E has estimated internal decommissioning costs (for costs estimated to be incurred in 2018 and beyond) of $3 million (in 2014 dollars) for SONGS Unit 1 and $43 million (in 2014 dollars) for SONGS Units 2 and 3. Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. SDG&E has received authorization from the CPUC to access NDT funds of up to $455 million for 2013 through 2019 (2019 forecasted) SONGS decommissioning costs. This includes up to $93 million authorized by the CPUC in January 2019 to be withdrawn from the NDT for forecasted 2019 SONGS Units 2 and 3 costs as decommissioning costs are incurred. In December 2018, the CPUC issued a final decision finding the decommissioning cost estimates for SONGS Unit 1 generally reasonable with certain disallowances. The decision also found $136 million (in 2014 dollars) of SONGS Units 2 and 3 decommissioning expenses for 2014 and $222 million (in 2014 dollars) of SONGS Units 2 and 3 decommissioning expenses for 2015 to be reasonable.

In December 2016, the IRS and the U.S. Department of the Treasury issued proposed regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The proposed regulations state that costs related to the construction and maintenance of independent spent fuel management installations are included in the definition of “nuclear decommissioning costs.” The proposed regulations will be effective prospectively once they are finalized; however, the IRS has stated that it will not challenge taxpayer positions consistent with the proposed regulations for taxable years ending on or after the date the proposed regulations were issued. SDG&E is awaiting the adoption of, or additional refinement to, the proposed regulations before determining whether the proposed regulations will allow SDG&E to access the NDT funds for reimbursement or payment of the spent fuel management costs incurred in 2017 and subsequent years. Further clarification of the proposed regulations could enable SDG&E to access the NDT to recover spent fuel management costs before Edison reaches final settlement with the DOE regarding the DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below. The IRS held public hearings on the proposed regulations in October 2017. It is unclear when clarification of the proposed regulations might be provided or when the proposed regulations will be finalized.

Nuclear Decommissioning Trusts

The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations. These trusts are shown on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 12.



NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value
At December 31, 2018:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies⁽¹⁾	$	52	$	1	$	—		$	53
Municipal bonds⁽²⁾	266		4		(1		)	269
Other securities⁽³⁾	238		1		(5		)	234
Total debt securities	556		6		(6		)	556
Equity securities	168		253		(10		)	411
Cash and cash equivalents	7		—		—			7
Total	$	731	$	259	$	(16	)	$	974
At December 31, 2017:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	$	54	$	—	$	—		$	54
Municipal bonds	245		7		(2		)	250
Other securities	215		3		(1		)	217
Total debt securities	514		10		(3		)	521
Equity securities	171		326		(1		)	496
Cash and cash equivalents	16		—		—			16
Total	$	701	$	336	$	(4	)	$	1,033


⁽¹⁾	Maturity dates are 2019-2048.


⁽²⁾	Maturity dates are 2019-2056.


⁽³⁾	Maturity dates are 2019-2064.

The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales.



SALES OF SECURITIES IN THE NDT
(Dollars in millions)
	Years ended December 31,
	2018			2017			2016
Proceeds from sales	$	890		$	1,314		$	1,134
Gross realized gains	42			157			111
Gross realized losses	(10		)	(14		)	(29		)

Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

ASSET RETIREMENT OBLIGATION AND SPENT NUCLEAR FUEL

SDG&E’s ARO related to decommissioning costs for the SONGS units was $626 million at December 31, 2018. That amount includes the cost to decommission Units 2 and 3, and the remaining cost to complete the decommissioning of Unit 1, which is substantially complete. The ARO at December 31, 2018 for all three units is based on a cost study prepared in 2017 that is pending CPUC approval. The ARO at December 31, 2018 for Units 2 and 3 reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. SDG&E’s share of total decommissioning costs in 2018 dollars is approximately $810 million.

U.S. DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL

Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC or temporarily in spent fuel pools. In October 2015, the CCC approved Edison’s application for the proposed expansion of the ISFSI at SONGS. The ISFSI expansion began construction in 2016 and is expected to be fully loaded with spent fuel in 2019 and to operate until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.

The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay results in increased costs for spent fuel storage. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel. In April 2016, Edison executed a spent fuel settlement agreement with the DOE for $162 million covering damages incurred from 2006 through 2013. In May 2016, Edison refunded SDG&E $32 million for its respective share of the damage award paid. In applying this refund, SDG&E recorded a $23 million reduction to the SONGS regulatory asset, an $8 million reduction of its nuclear decommissioning balancing account and a $1 million reduction in its SONGS O&M cost balancing account.

Under the terms of the 2016 spent fuel settlement agreement, Edison filed a claim with the DOE on behalf of the SONGS co-owners in 2016 for spent fuel management costs incurred in 2014 and 2015 and a claim in 2017 for costs incurred in 2016. The DOE settled these claims with Edison in 2017 and 2018, respectively. In May 2017, SDG&E received its $9 million respective share from Edison of the settlement for 2014 and 2015 costs incurred. In July 2018, SDG&E received its $9 million share from Edison of the settlement for 2016 costs incurred. SDG&E recorded the proceeds of these settlements in balancing accounts or as reductions to regulatory assets for the benefit of ratepayers.

The 2016 spent fuel settlement agreement governs the submission of claims for costs incurred through December 31, 2016. It is unclear whether Edison will enter into a new settlement with the DOE or pursue litigation claims for spent fuel management costs incurred on or after January 1, 2017.

NUCLEAR INSURANCE

Edison requested and was granted approval in January 2018 by the NRC to reduce the nuclear liability and property damage insurance requirement. However, these changes in SONGS nuclear insurance levels require approval from all SONGS owners, as described below.

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $450 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides an additional $110 million of coverage. If a nuclear liability loss occurs at SONGS and exceeds the $450 million insurance limit, this additional coverage would be available to provide a total of $560 million in coverage limits per incident. The SFP is a program that provides additional insurance. If a nuclear liability loss occurs at any U.S. licensed/commercial reactor and exceeds the $450 million insurance limit, all SFP participants would be required to contribute to the SFP. Effective January 5, 2018, the NRC approved Edison’s request to reduce the nuclear liability insurance requirement from $450 million to $100 million and withdraw from participation in the SFP for SONGS. On April 5, 2018, the SONGS co-owners approved withdrawing from participation in the SFP for SONGS, but maintaining the nuclear liability insurance coverage at current levels ($450 million). Confirmation of SONGS’ withdrawal from the SFP has been received and became effective January 5, 2018.

The SONGS owners, including SDG&E, also maintain nuclear property damage insurance that exceeds the minimum federal requirements of $1.06 billion. This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $10.4 million of retrospective premiums based on overall member claims. All of SONGS’ insurance claims arising out of the failures of the MHI replacement steam generators have been settled with NEIL. Effective January 10, 2018, the NRC approved Edison’s request to reduce its minimum property damage insurance requirement for SONGS from $1.06 billion to $50 million. However, on April 5, 2018, the SONGS co-owners approved maintaining its current property damage insurance at $1.5 billion, but with a new $500 million property damage sublimit on the ISFSI.

The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act) of $3.24 billion. This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.