

REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	December 31,
	2019			2018
SDG&E:
Fixed-price contracts and other derivatives	$	8		$	(150	)
Deferred income taxes refundable in rates	(108		)	(236		)
Pension and other postretirement benefit plan obligations	103			186
Removal obligations	(2,056		)	(1,848		)
Environmental costs	45			28
Sunrise Powerlink fire mitigation	121			120
Regulatory balancing accounts⁽¹⁾⁽²⁾
Commodity – electric	102			(8		)
Gas transportation	22			45
Safety and reliability	77			70
Public purpose programs	(124		)	(62		)
2019 GRC retroactive impacts	111			—
Other balancing accounts	106			145
Other regulatory liabilities, net⁽²⁾	(153		)	(170		)
Total SDG&E	(1,746		)	(1,880		)
SoCalGas:
Deferred income taxes refundable in rates	(203		)	(336		)
Pension and other postretirement benefit plan obligations	400			470
Employee benefit costs	44			49
Removal obligations	(728		)	(833		)
Environmental costs	40			28
Regulatory balancing accounts⁽¹⁾⁽²⁾
Commodity – gas, including transportation	(118		)	196
Safety and reliability	295			332
Public purpose programs	(273		)	(325		)
2019 GRC retroactive impacts	400			—
Other balancing accounts	(7		)	(68		)
Other regulatory liabilities, net⁽²⁾	(101		)	(114		)
Total SoCalGas	(251		)	(601		)
Sempra Mexico:
Deferred income taxes recoverable in rates	83			81
Other regulatory assets	6			6
Total Sempra Energy Consolidated	$	(1,908	)	$	(2,394	)

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 and liabilities include certain income tax benefits and expenses associated with flow-through items, which we discuss in Note 8.

Amortization expense on regulatory assets for the years ended December 31, 2019, 2018 and 2017 was $7 million, $5 million and $50 million, respectively, at Sempra Energy Consolidated, $3 million, $2 million and $49 million, respectively, at SDG&E, and $4 million, $3 million and $1 million, respectively, at SoCalGas.

The 2019 GRC FD adopts a test year 2019 revenue requirement of $1,990 million for SDG&E’s combined operations ($1,590 million for its electric operations and $400 million for its natural gas operations), which is $213 million lower than the $2,203 million that SDG&E had requested in its updated application. SDG&E’s adopted 2019 revenue requirement represents an increase of $107 million (5.70%) over its authorized 2018 revenue requirement.

The 2019 GRC FD adopts a test year 2019 revenue requirement of $2,770 million for SoCalGas, which is $167 million lower than the $2,937 million that SoCalGas had requested in its updated application. SoCalGas’ adopted 2019 revenue requirement represents an increase of $314 million (12.80%) over its authorized 2018 revenue requirement.



AUTHORIZED REVENUE REQUIREMENT INCREASES FOR 2020 AND 2021
(Dollars in millions)
	2020 increase from 2019				2021 increase from 2020
	Revenue increase		Percent increase		Revenue increase		Percent increase
SDG&E:
O&M	$	20	2.64	%	$	19	2.47	%
Capital-related costs	114		9.74		83		6.47
Total increase	$	134	6.74		$	102	4.83
SoCalGas:
O&M	$	36	2.64	%	$	34	2.40	%
Capital-related costs	184		14.36		116		7.93
Total increase	$	220	7.92		$	150	5.00

The adopted revenue requirements associated with the period from January 1, 2019 through December 31, 2019 are being recovered in rates over a 24-month period beginning in January 2020. At December 31, 2019, SDG&E recorded an associated regulatory asset of $111 million, with $56 million as noncurrent, and SoCalGas recorded an associated regulatory asset of $400 million, with $200 million as noncurrent.

In January 2020, the CPUC issued a final decision implementing a four-year GRC cycle for California IOUs. The California Utilities were directed to file a petition for modification to revise their 2019 GRC to add two additional attrition years, resulting in a transitional five-year GRC period (2019-2023).

The 2019 GRC FD approves for the California Utilities the establishment of two-way liability insurance premium balancing accounts, including wildfire insurance premium costs based on a specific level of coverage. The 2019 GRC FD also permits the California Utilities to seek recovery of additional liability insurance coverage.

Pursuant to the 2016 GRC FD, SDG&E and SoCalGas each established a two-way income tax expense memorandum account to track, among other items, 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. SDG&E and SoCalGas recorded regulatory liabilities associated with the 2016 through 2018 tracked forecasting differences of $86 million and $89 million, respectively. The 2019 GRC FD clarifies that forecasting differences, which we previously included in this tracked activity, are not subject to tracking in the income tax expense memorandum account. Final resolution of the scope of the two-way income tax expense memorandum account for the 2016 through 2018 period is pending at the CPUC and could impact the disposition of these regulatory liabilities. We expect resolution in the first half of 2020.

The 2016 GRC FD revenue requirement was authorized using a federal income tax rate of 35%. As a result of the TCJA, the federal income tax rate became 21% effective January 1, 2018. Since SDG&E and SoCalGas continued to collect authorized revenues based on a 35% tax rate, SDG&E and SoCalGas recorded regulatory liabilities of $88 million and $75 million, respectively. Pursuant to the 2019 GRC FD, SDG&E and SoCalGas are refunding the regulatory balances over a 24-month period starting in January 2020. SDG&E also recorded a $66 million regulatory liability at December 31, 2019, relating to its FERC jurisdictional rates, which it began refunding in June 2019.

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% to 56%. SDG&E also proposed to increase its authorized ROE from 10.2% to 14.3% (with the aggregate ROE proposal including a quantified premium for wildfire liability risk), and to increase its authorized return on rate base from 7.55% to 10.03%. In August 2019, SDG&E filed supplemental testimony to update its ROE request from 10.2% to 12.38% to reflect the impacts of the Wildfire Legislation, including a revised premium for wildfire liability risk, and its authorized return on rate base from 7.55% to 8.95%. SoCalGas proposed to adjust its authorized capital structure by increasing the amount of its common equity from 52% to 56%, its authorized ROE from 10.05% to 10.7% and its authorized return on rate base from 7.34% to 7.85%.

In December 2019, the CPUC approved the cost of capital and rate structures (shown in the table below) for SDG&E and SoCalGas that are effective January 1, 2020 and will remain in effect through December 31, 2022. SDG&E did not propose a 2020 cost of preferred equity in this proceeding. In January 2020, SDG&E filed an advice letter to continue the cost of preferred equity for test year 2020 at 6.22%, which is pending CPUC approval.



CPUC AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE

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	%	4.23	%	1.93	%
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	%			7.30	%

The CCM was reauthorized in the 2020 cost of capital proceeding to continue through 2022. The CCM benchmark rate for the 2020 cost of capital is the average monthly utility bond index, as published by Moody’s, for the 12-month period from October 2018 through September 2019. SDG&E’s CCM benchmark rate is 4.491%, based on Moody’s Baa- utility bond index, and SoCalGas’ CCM benchmark rate is 4.024%, based on Moody’s A- utility bond index. The index applicable to each utility is based on each utility’s credit rating.

The CCM benchmark rates for SDG&E and SoCalGas are the basis of comparison to determine if future measurement periods “trigger” the CCM. The 12 months ending September 2020 shall be the first “CCM Period” to determine if there has been a trigger at SDG&E or SoCalGas. The trigger occurs if the change in the applicable average Moody’s utility bond index relative to the CCM benchmark is larger than plus or minus 1.000%. Accordingly, if a change of more than plus or minus 1.000% occurs, SDG&E’s, SoCalGas’, or both utilities’ authorized ROE would be adjusted, upward or downward, by one half of the difference between the CCM benchmark and the 12-month average determined during the CCM Period. In addition, the authorized recovery rate for the respective utilities’ cost of debt and preferred stock would be adjusted to their respective actual weighted-average cost, with no change to the authorized capital structure. In the event of a CCM trigger, the CCM benchmark is also reestablished. These adjustments would become effective in authorized rates on January 1 of the year following the CCM trigger.

In October 2018, SDG&E submitted its TO5 filing to the FERC proposing, among other items, an increase to SDG&E’s current authorized FERC ROE from 10.05% to 11.20%. This proceeding establishes the transmission revenue requirement, including rate of return, for SDG&E’s FERC-regulated electric transmission operations and assets. On December 31, 2018, the FERC issued its order accepting and suspending SDG&E’s TO5 filing for five months, during which the existing TO4 rates remained in effect, and established hearing and settlement procedures. 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% is the basis of SDG&E’s FERC-related revenue recognition.

In October 2019, SDG&E and all settling parties reached an agreement on all issues set for hearing in the proceeding. The agreement provides for a ROE of 10.60%, consisting of a base ROE of 10.10% plus an additional 50 bps for participation in the California ISO. SDG&E will refund the California ISO additional 50 bps of ROE as of the refund effective date (June 1, 2019) in this proceeding if the FERC issues an order ruling that California IOUs are no longer eligible for the additional California ISO

In May 2017, the CPUC issued an OII to determine whether SoCalGas violated any provisions of the California Public Utilities Code, General Orders, CPUC decisions, or other requirements pertaining to billing practices from 2014 through 2016. The CPUC examined the timeliness of monthly bills, extending the billing period for customers, and issuing estimated bills, including an examination of SoCalGas’ gas tariff rules. In January 2019, the CPUC ordered SoCalGas to pay $8 million in penalties, including $3 million that was paid in July 2019 to California’s general fund and $5 million to be credited to customers that received delayed bills (greater than 45 days) in the form of a $100 bill credit. SoCalGas filed an appeal of the CPUC’s conclusions in the order, which, in April 2019, the CPUC denied. SoCalGas filed a rehearing request in May 2019, which is pending before the CPUC. The CPUC granted SoCalGas’ request to delay distribution of the $100 bill credit to customers until a final decision on the rehearing.

SDG&E has a 20% ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which permanently ceased operations in June 2013 after an extended outage 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.

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.

In March 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% 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 was $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

In 2014, the CPUC issued a final decision approving an Amended Settlement Agreement that 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.

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.

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 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, 2019, SDG&E has a receivable from Edison, including accrued interest, totaling $86 million, with $38 million classified as current and $48 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.

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. We expect the majority of the dismantlement work to take 10 years after receipt of the required permits. The coastal development permit was issued in October 2019. The Samuel Lawrence Foundation filed a writ petition under the California Coastal Act in LA Superior Court in December 2019. The petition seeks to invalidate the permit and to obtain injunctive relief to stop decommissioning work. We expect major decommissioning work to begin in 2020, unless the court issues an injunction. 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 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% 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. SDG&E classifies debt and equity securities held in the NDT as available-for-sale. 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.

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 SONGS decommissioning costs. SDG&E has filed for authorization with the CPUC to withdraw up to $109 million from the NDT for forecasted 2020 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. 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 timely 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.

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.



NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value
At December 31, 2019:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies⁽¹⁾	$	57	$	—	$	—		$	57
Municipal bonds⁽²⁾	270		12		—			282
Other securities⁽³⁾	218		9		(1		)	226
Total debt securities	545		21		(1		)	565
Equity securities	176		339		(6		)	509
Cash and cash equivalents	8		—		—			8
Total	$	729	$	360	$	(7	)	$	1,082
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

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.

The present value of SDG&E’s ARO related to decommissioning costs for the SONGS units was $611 million at December 31, 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. We expect SDG&E’s undiscounted SONGS decommissioning payments to be $89 million in 2020, $82 million in 2021, $83 million in 2022, $63 million in 2023, $46 million in 2024, and $739 million thereafter.

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 the transfer of the spent nuclear fuel from Units 2 and 3 to the ISFSI began in 2018. Edison suspended this transfer in August 2018 due to an incident that was subsequently resolved to the NRC’s satisfaction according to the NRC’s supplemental inspection report released in July 2019. 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. In November 2019, Edison filed a claim for spent fuel management costs in the U.S. Court of Federal Claims for the time period from January 2017 through July 2018. It is unclear when Edison will pursue litigation claims for spent fuel management costs incurred on or after August 1, 2018. 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.

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 NEIL under all issued policies. SDG&E could be assessed up to $10.4 million of retrospective premiums based on overall member claims.

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.