

REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	June 30, 2019			December 31, 2018

SDG&E:
Fixed-price contracts and other derivatives	$	(122	)	$	(150	)
Deferred income taxes refundable in rates	(150		)	(236		)
Pension and other postretirement benefit plan obligations	188			186
Removal obligations	(1,982		)	(1,848		)
Unamortized loss on reacquired debt	6			7
Environmental costs	27			28
Sunrise Powerlink fire mitigation	119			120
Regulatory balancing accounts⁽¹⁾
Commodity – electric	135			(8		)
Gas transportation	8			45
Safety and reliability	82			70
Public purpose programs	(98		)	(62		)
Other balancing accounts	122			145
Other regulatory liabilities, net⁽²⁾	(222		)	(177		)
Total SDG&E	(1,887		)	(1,880		)
SoCalGas:
Pension and other postretirement benefit plan obligations	466			470
Employee benefit costs	49			49
Removal obligations	(779		)	(833		)
Deferred income taxes refundable in rates	(233		)	(336		)
Unamortized loss on reacquired debt	6			7
Environmental costs	28			28
Workers’ compensation	9			9
Regulatory balancing accounts⁽¹⁾
Commodity – gas, including transportation	(33		)	196
Safety and reliability	365			332
Public purpose programs	(352		)	(325		)
Other balancing accounts	54			(68		)
Other regulatory liabilities, net⁽²⁾	(182		)	(130		)
Total SoCalGas	(602		)	(601		)
Sempra Mexico:
Deferred income taxes recoverable in rates	81			81
Other regulatory assets	8			6
Total Sempra Energy Consolidated	$	(2,400	)	$	(2,394	)

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 in “2016 General Rate Case” below and in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report. 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 included in SDG&E’s GRC application associated with owning and operating the generating facility. As we discuss in Note 1, on March 28, 2019, OMEC LLC exercised the put option requiring SDG&E to purchase the power plant by October 3, 2019, which is subject to the results of certain pending rehearing requests. The Utility Reform Network and other intervenors oppose various components of our revenue requests in the 2019 GRC applications.

As we discuss in Notes 4 and 8 of the Notes to Consolidated Financial Statements in the Annual Report, 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. At June 30, 2019, the recorded regulatory liability associated with these tracked amounts totaled $93 million and $100 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 may 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 of 21 percent became 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 June 30, 2019, SDG&E and SoCalGas recorded regulatory liabilities of $113 million and $106 million, respectively, in anticipation of amounts that will benefit customers in future rates. SDG&E also recorded a $93 million regulatory liability at June 30, 2019, 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.

In April 2019, SDG&E and SoCalGas filed separate applications with the CPUC to update their cost of capital effective January 1, 2020. SDG&E proposed to adjust its authorized capital structure by increasing the amount of its common equity from 52 percent to 56 percent. SDG&E also proposed to increase its authorized ROE from 10.2 percent to 14.3 percent, including a premium for wildfire risk, and to increase its authorized return on rate base from 7.55 percent to 10.03 percent. On August 1, 2019, SDG&E filed supplemental testimony to update its ROE request, which modifies its proposal to increase its authorized ROE from 10.2 percent to 12.38 percent, including a revised premium for wildfire risk that reflects the impacts of AB 1054 and AB 111. Accordingly, SDG&E also modified its proposal to increase its authorized return on rate base from 7.55 percent to 8.95 percent. SoCalGas proposed to adjust its authorized capital structure by increasing the amount of its common equity from 52 percent to 56 percent. SoCalGas also proposed to increase its authorized ROE from 10.05 percent to 10.7 percent and to increase its authorized return on rate base from 7.34 percent to 7.85 percent. The schedule for the proceeding indicates a final decision in 2019.

In October 2018, SDG&E submitted its TO5 filing to the FERC. This proceeding establishes the transmission revenue requirement, including rate of return, for SDG&E’s FERC-regulated electric transmission operations and assets. SDG&E’s TO5 filing proposed, among other items, an increase to SDG&E’s current authorized FERC ROE from 10.05 percent to 11.2 percent. On December 31, 2018, the FERC issued its order accepting and suspending SDG&E’s TO5 filing and established hearing and settlement judge procedures. In the order, the FERC suspended the TO5 filing for five months, during which the existing TO4 rates remained in effect. The suspension period ended on June 1, 2019, when the proposed TO5 rates took effect, subject to refund and the outcome of the rate filing. As a result, until a new ROE is authorized, the current ROE of 10.05 percent is the basis of SDG&E’s FERC-related revenue recognition. In July 2019, the settlement judge reported that SDG&E and the settling parties had reached an impasse and directed the matter forward to hearings, which does not preclude continued settlement discussions among SDG&E and the settling parties. The hearing schedule indicates an initial decision in the second half of 2020. When we receive a final decision, SDG&E will record the cumulative earnings effect of retroactive application to June 1, 2019 for any difference between the current ROE and the approved ROE.

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 completed once Units 2 and 3 are dismantled and the spent fuel is removed from the site. The majority of the dismantlement work is expected to take 10 years. The spent fuel is currently being stored on-site, until the DOE identifies a spent fuel storage facility and puts in place a program for the fuel’s disposal, as we discuss below. 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

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 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
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value
At June 30, 2019:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies⁽¹⁾	$	46	$	—	$	—		$	46
Municipal bonds⁽²⁾	278		11		—			289
Other securities⁽³⁾	230		7		(1		)	236
Total debt securities	554		18		(1		)	571
Equity securities	164		310		(7		)	467
Cash and cash equivalents	6		—		—			6
Total	$	724	$	328	$	(8	)	$	1,044
At December 31, 2018:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	$	52	$	1	$	—		$	53
Municipal bonds	266		4		(1		)	269
Other securities	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

SDG&E’s ARO related to decommissioning costs for the SONGS units was $611 million at June 30, 2019. 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 for all three units is based on a cost study prepared in 2017 that is pending CPUC approval. The ARO 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 2019 dollars is approximately $834 million.

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 California Coastal Commission approved Edison’s application for the proposed expansion of the ISFSI at SONGS. The ISFSI expansion began construction in 2016 and the transfer of the spent nuclear fuel from Units 2 and 3 to the ISFSI began in 2018. Edison suspended this transfer on August 3, 2018 due to an incident that occurred when a spent fuel canister was getting loaded into the ISFSI. The incident did not result in any harm to the public or workers and the canister was subsequently safely loaded into the ISFSI. In May 2019, the NRC completed its on-site inspection activities noting that it was satisfied with the corrective actions taken in response to the August 3, 2018 incident and had no objection to the resumption of spent fuel transfer operations. On July 10, 2019, the NRC released a supplemental inspection report affirming that Edison addressed previously identified issues regarding its fuel transfer operations to the NRC’s satisfaction. Edison resumed spent fuel transfer operations in July 2019. The ISFSI will 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 will lead to 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. However, 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.

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 SONGS owners, including SDG&E, also maintain nuclear property damage insurance at $1.5 billion, with a $500 million property damage sublimit on the ISFSI, which 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