SRE 10-Q Quarter ended June 30, 2018

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▪	actions and the timing of actions, including decisions, new regulations, and issuances of permits and other authorizations by the CPUC, DOE, DOGGR, FERC, EPA, PHMSA, DPH, PUCT, states, cities and counties, and other regulatory and governmental bodies in the U.S. and other countries in which we operate;

▪	the timing and success of business development efforts and construction projects, including risks in timely obtaining or maintaining permits and other authorizations, risks in completing construction projects on schedule and on budget, and risks in obtaining the consent and participation of partners and counterparties;

▪	the resolution of civil and criminal litigation and regulatory investigations;

▪

deviations from regulatory precedent or practice that result in a reallocation of benefits or burdens among shareholders and ratepayers; denial of approvals of proposed settlements or modifications of settlements; and delays in, or disallowance or denial of, regulatory agency authorizations to recover costs in rates from customers or regulatory agency approval for projects required to enhance safety and reliability, any of which may raise our cost of capital and materially impair our ability to finance our operations;

▪	the greater degree and prevalence of wildfires in California in recent years and risk that we may be found liable for damages regardless of fault, such as in cases where the inverse condemnation doctrine applies, and risk that we may not be able to recover any such costs in rates from customers in California;

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▪	the availability of electric power, natural gas and liquefied natural gas, and natural gas pipeline and storage capacity, including disruptions caused by failures in the transmission grid, moratoriums or limitations on the withdrawal or injection of natural gas from or into storage facilities, and equipment failures;

▪	changes in energy markets, volatility in commodity prices and moves to reduce or eliminate reliance on natural gas;

▪	risks posed by actions of third parties who control the operations of our investments, and risks that our partners or counterparties will be unable or unwilling to fulfill their contractual commitments;

▪

weather conditions, natural disasters, accidents, equipment failures, computer system outages, explosions, terrorist attacks and other events that disrupt our operations, damage our facilities and systems, cause the release of GHG, radioactive materials and harmful emissions, cause wildfires and subject us to third-party liability for property damage or personal injuries, fines and penalties, some of which may not be covered by insurance (including costs in excess of applicable policy limits), may be disputed by insurers or may otherwise not be recoverable through regulatory mechanisms or may impact our ability to obtain satisfactory levels of insurance, to the extent that such insurance is available or not prohibitively expensive;

▪	cybersecurity threats to the energy grid, storage and pipeline infrastructure, the information and systems used to operate our businesses and the confidentiality of our proprietary information and the personal information of our customers and employees;

▪	our ability to successfully execute our plan to divest certain non-utility assets within the anticipated timeframe, if at all, or that such plan may not yield the anticipated benefits;

▪	actions of activist shareholders, which could impact the market price of our common stock, preferred stock and other securities and disrupt our operations as a result of, among other things, requiring significant time and attention by management and our board of directors;

▪	capital markets and economic conditions, including the availability of credit and the liquidity of our investments; and fluctuations in inflation, interest and currency exchange rates and our ability to effectively hedge the risk of such fluctuations;

▪	the impact of recent federal tax reform and uncertainty as to how it may be applied, and our ability to mitigate adverse impacts;

▪	actions by credit rating agencies to downgrade our credit ratings or those of our subsidiaries or to place those ratings on negative outlook and our ability to borrow at favorable interest rates;

▪	changes in foreign and domestic trade policies and laws, including border tariffs, and revisions to international trade agreements, such as NAFTA, that make us less competitive or impair our ability to resolve trade disputes;

▪	the ability to win competitively bid infrastructure projects against a number of strong and aggressive competitors;

▪	expropriation of assets by foreign governments and title and other property disputes;

▪	the impact on reliability of SDG&E’s electric transmission and distribution system due to increased amount and variability of power supply from renewable energy sources;

▪

the impact on competitive customer rates due to the growth in distributed and local power generation and the corresponding decrease in demand for power delivered through SDG&E’s electric transmission and distribution system and from possible departing retail load resulting from customers transferring to DA and CCA or other forms of distributed and local power generation and the potential risk of nonrecovery for stranded assets and contractual obligations;

▪	the ability to realize the anticipated benefits from our investment in Oncor Holdings;

▪	Oncor’s ability to eliminate or reduce its quarterly dividends due to regulatory capital requirements, certain reductions in its senior secured credit rating, or the determination by Oncor’s independent directors or a minority member director to retain such amounts to meet future requirements; and

▪	other uncertainties, some of which may be difficult to predict and are beyond our control.

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(1)	As adjusted for the retrospective adoption of ASU 2017-07, which we discuss in Note 2, and a reclassification to conform to current year presentation, which we discuss in Note 1.

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(1)	Derived from audited financial statements.

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(1)	Derived from audited financial statements.

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(1)	As adjusted for the retrospective adoption of ASU 2016-18, which we discuss in Note 2.

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(1)	As adjusted for the retrospective adoption of ASU 2016-18, which we discuss in Note 2.

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(1)	As adjusted for the retrospective adoption of ASU 2017-07, which we discuss in Note 2.

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(1)	Derived from audited financial statements.

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(1)	Derived from audited financial statements.

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(1)	As adjusted for the retrospective adoption of ASU 2016-18, which we discuss in Note 2.

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(1)	As adjusted for the retrospective adoption of ASU 2017-07, which we discuss in Note 2.

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(1)	Derived from audited financial statements.

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(1)	Derived from audited financial statements.

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PRINCIPLES OF CONSOLIDATION

Sempra Energy

Sempra Energy’s Condensed Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 energy-services holding company, and its consolidated subsidiaries and VIEs. Sempra Energy’s operating units are:

▪	Sempra Utilities, which includes our SDG&E, SoCalGas, Sempra South American Utilities and our newly formed Sempra Texas Utility reportable segments. We discuss our new Sempra Texas Utility reportable segment in Notes 5 and 6; and

▪	Sempra Infrastructure, which includes our Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream reportable segments.

We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include our Texas utility investment, South American utilities or the utility in our Sempra Infrastructure operating unit. Sempra Global is the holding company for most of our subsidiaries that are not subject to California or Texas utility regulation. All references in these Notes to “Sempra Utilities,” “Sempra Infrastructure” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name.

SDG&E

SDG&E’s Condensed Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E is the primary beneficiary, as we discuss below in “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy.

SoCalGas

SoCalGas’ common stock is wholly owned by Pacific Enterprises, which is a wholly owned subsidiary of Sempra Energy.

BASIS OF PRESENTATION

This is a combined report of Sempra Energy, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. References in this report to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, unless otherwise indicated by the context. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity.

Throughout this report, we refer to the following as Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements when discussed together or collectively:

▪	the Condensed Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs;

▪	the Condensed Consolidated Financial Statements and related Notes of SDG&E and its VIE; and

▪	the Condensed Financial Statements and related Notes of SoCalGas.

We have prepared the Condensed Consolidated Financial Statements in conformity with U.S. GAAP and in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. We evaluated events and transactions that occurred after June 30, 2018 through the date the financial statements were issued and, in the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation. These adjustments are only of a normal, recurring nature.

All December 31, 2017 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2017 Consolidated Financial Statements in the Annual Report. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of U.S. GAAP and the SEC.

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We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report and the impact of the adoption of new accounting standards on those policies in Note 2 below. We follow the same accounting policies for interim reporting purposes.

You should read the information in this Quarterly Report in conjunction with the Annual Report.

Reclassification on the Condensed Consolidated Statement of Operations

We have made a reclassification on the Condensed Consolidated Statement of Operations for the three months and six months ended June 30, 2017 to conform to current year presentation. Line item captions for equity earnings (losses) before income tax and net of income tax have been combined into one line and presented after income tax expense (benefit). This reclassification is intended to treat the presentation of earnings from all equity method investees consistently and simplify the presentation on the statement of operations, while continuing to provide additional detail in the notes to the financial statements. We discuss this presentation further in Note 6. The following table summarizes the financial statement line items that were affected by this reclassification:

SEMPRA ENERGY – RECLASSIFICATION
(Dollars in millions)
		Three months ended June 30, 2017								Six months ended June 30, 2017
		As previously presented				As currently presented				As previously presented				As currently presented
Condensed Consolidated Statement of Operations:
Equity earnings, before income tax		$	18			$	—			$	21			$	—
Income before income taxes and equity losses of certain
unconsolidated subsidiaries		415				—				1,170				—
Income before income taxes and equity earnings of
unconsolidated subsidiaries		—				397				—				1,149
Equity losses, net of income tax		—				—				( 8		)		—
Equity earnings		—				18				—				13

Regulated Operations

The California Utilities and Sempra Mexico’s natural gas distribution utility, Ecogas, prepare their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations. We discuss the effects of regulation in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report and revenue recognition at our utilities in Note 3 below.

Our Sempra Texas Utility segment is comprised of our equity method investment in Oncor Holdings, which owns 80.25 percent of Oncor, as we discuss in Notes 5 and 6. Oncor is a regulated electric transmission and distribution utility in the state of Texas. Oncor’s rates are regulated by the PUCT and certain cities, and are subject to regulatory rate-setting processes and annual earnings oversight. Oncor prepares its financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations.

Sempra South American Utilities has controlling interests in two electric distribution utilities in South America, Chilquinta Energía in Chile and Luz del Sur in Peru. Revenues are based on tariffs that are set by government agencies in their respective countries based on an efficient model distribution company defined by those agencies. Because the tariffs are based on a model and are intended to cover the costs of the model company, but are not based on the costs of the specific utility and may not result in full cost recovery, these utilities do not meet the requirements necessary for, and therefore do not apply, regulatory accounting treatment under U.S. GAAP.

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The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported on the Condensed Consolidated Balance Sheets to the sum of such amounts reported on the Condensed Consolidated Statements of Cash Flows. We provide information about the nature of restricted cash in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

The components of inventories by segment are as follows:

INVENTORY BALANCES
(Dollars in millions)
	Natural gas									LNG									Materials and supplies									Total
	June 30, 2018				December 31, 2017					June 30, 2018				December 31, 2017					June 30, 2018				December 31, 2017					June 30, 2018				December 31, 2017
SDG&E	$	—			$	4				$	—			$	—				$	105			$	101				$	105			$	105
SoCalGas	41				75					—				—					39				49					80				124
Sempra South American Utilities	—				—					—				—					34				30					34				30
Sempra Mexico	—				—					10				7					13				2					23				9
Sempra Renewables	—				—					—				—					—				5					—				5
Sempra LNG & Midstream	46				30					—				4					—				—					46				34
Sempra Energy Consolidated	$	87			$	109				$	10			$	11				$	191			$	187				$	288			$	307

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Other Intangible Assets included on the Sempra Energy Condensed Consolidated Balance Sheets are as follows:

	OTHER INTANGIBLE ASSETS
	(Dollars in millions)
		Amortization period (years)		June 30, 2018				December 31, 2017
	Development rights	50		$	—			$	322
	Renewable energy transmission and consumption permit	19		154				154
	Storage rights	46		—				138
	O&M agreement	23		66				66
	Other	10 years to indefinite		22				18
				242				698
	Less accumulated amortization:
	Development rights			—				( 60		)
	Renewable energy transmission and consumption permit			( 12		)		( 8		)
	Storage rights			—				( 28		)
	O&M agreement			( 2		)		—
	Other			( 7		)		( 6		)
				( 21		)		( 102		)
				$	221			$	596

In June 2018, we recognized an impairment of $ 369 million for the net carrying value of Other Intangible Assets at Sempra LNG & Midstream, representing development and storage rights related to the natural gas storage facilities of Mississippi Hub and Bay Gas. This impairment is included in Sempra LNG & Midstream’s total impairment of $ 1.3 billion , which is included in Impairment Losses on Sempra Energy’s Condensed Consolidated Statements of Operations in the three months and six months ended June 30, 2018, as we discuss in Notes 5 and 9.

Capitalized financing costs include capitalized interest costs and AFUDC related to both debt and equity financing of construction projects. We capitalize interest costs incurred to finance capital projects and interest on equity method investments that have not commenced planned principal operations.

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We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based upon qualitative and quantitative analyses, which assess:

▪	the purpose and design of the VIE;

▪	the nature of the VIE’s risks and the risks we absorb;

▪	the power to direct activities that most significantly impact the economic performance of the VIE; and

▪	the obligation to absorb losses or the right to receive benefits that could be significant to the VIE.

We will continue to evaluate our VIEs for any changes that may impact our determination of the primary beneficiary.

SDG&E

SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various PPAs that include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and thereby Sempra Energy, is the primary beneficiary.

Tolling Agreements

SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based on our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on a qualitative approach in which we consider the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If we determine that SDG&E is the primary beneficiary, SDG&E and Sempra Energy consolidate the entity that owns the facility as a VIE.

Otay Mesa VIE

SDG&E has a tolling agreement to purchase power generated at OMEC, a 605 -MW generating facility. A related agreement provides SDG&E with the option to purchase OMEC at the end of the contract term in October 2019, or upon earlier termination of the PPA, at a predetermined price subject to adjustments. If SDG&E does not exercise its option (referred to as the call option), under the terms of the agreement, the counterparty can require SDG&E to purchase the power plant for $ 280 million , subject to adjustments, on or before October 3, 2019 (referred to as the put option), or upon earlier termination of the PPA. SDG&E does not expect to exercise its call option to purchase OMEC.

The facility owner, OMEC LLC, is a VIE, which we refer to as Otay Mesa VIE, of which SDG&E is the primary beneficiary. SDG&E has no OMEC LLC voting rights, holds no equity in OMEC LLC and does not operate OMEC. In addition to the risks absorbed under the tolling agreement, SDG&E absorbs separately through the put option a significant portion of the risk that the value of Otay Mesa VIE could decline. Accordingly, SDG&E and Sempra Energy consolidate Otay Mesa VIE. Otay Mesa VIE’s equity of $ 29 million at June 30, 2018 and $ 28 million at December 31, 2017 is included on the Condensed Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.

OMEC LLC has a loan outstanding of $ 290 million at June 30, 2018 , the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is collateralized by OMEC’s assets. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC, nor would SDG&E be required to assume OMEC’s loan under the call or put option purchase scenarios. The loan fully matures in April 2019, prior to the put option, and bears interest at rates varying with market rates. In addition, OMEC LLC has entered into interest rate swap agreements to moderate its exposure to interest rate changes. We provide additional information concerning the interest rate swaps in Note 8.

The Condensed Consolidated Statements of Operations of Sempra Energy and SDG&E include the following amounts associated with Otay Mesa VIE. The amounts are net of eliminations of transactions between SDG&E and Otay Mesa VIE. The captions in the table below correspond to SDG&E’s Condensed Consolidated Statements of Operations.

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AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	Three months ended June 30,								Six months ended June 30,
	2018				2017				2018				2017
Operating expenses
Cost of electric fuel and purchased power	$	( 16	)		$	( 21	)		$	( 32	)		$	( 39	)
Operation and maintenance	4				5				8				9
Depreciation and amortization	7				7				15				14
Total operating expenses	( 5		)		( 9		)		( 9		)		( 16		)
Operating income	5				9				9				16
Interest expense	( 5		)		( 5		)		( 10		)		( 10		)
Income (loss) before income taxes/Net income (loss)	—				4				( 1		)		6
(Earnings) losses attributable to noncontrolling interest	—				( 4		)		1				( 6		)
Earnings attributable to common shares	$	—			$	—			$	—			$	—

SDG&E has determined that no contracts, other than the one relating to Otay Mesa VIE mentioned above, result in SDG&E being the primary beneficiary of a VIE at June 30, 2018 . In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, and other components of cash flows expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities that most significantly impact the economic performance of the other VIEs. In addition, SDG&E is not exposed to losses or gains as a result of these other VIEs, because all such variability would be recovered in rates. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects could be significant to the financial position and liquidity of SDG&E and Sempra Energy. We provide additional information about PPAs with power plant facilities that are VIEs of which SDG&E is not the primary beneficiary in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

We provide additional information regarding Otay Mesa VIE in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra Texas Utility

On March 9, 2018, we completed the acquisition of an indirect, 100 -percent interest in Oncor Holdings, a VIE that owns an 80.25 -percent interest in Oncor. Sempra Energy is not the primary beneficiary of the VIE because of the structural and operational ring-fencing measures in place that prevent us from having the power to direct the significant activities of Oncor Holdings. As a result, we do not consolidate Oncor Holdings and instead account for our ownership interest as an equity method investment. See Notes 5 and 6 for additional information about our equity method investment in Oncor Holdings and restrictions in our ability to influence its activities. Our current maximum exposure to loss from our interest in Oncor Holdings does not exceed the carrying value of our investment, which is $ 9,407 million at June 30, 2018 . Our maximum exposure will fluctuate over time.

Sempra Renewables

Certain of Sempra Renewables’ wind and solar power generation projects are held by limited liability companies whose members are Sempra Renewables and financial institutions. The financial institutions are noncontrolling tax equity investors to which earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. These entities are VIEs and Sempra Energy is the primary beneficiary, generally due to Sempra Energy’s power as the operator of the renewable energy projects to direct the activities that most significantly impact the economic performance of these VIEs. As the primary beneficiary of these tax equity limited liability companies, we consolidate them.

Sempra Energy’s Condensed Consolidated Balance Sheets include $ 1,412 million of property, plant and equipment, net, at December 31, 2017 and equity of $ 669 million and $ 631 million of Other Noncontrolling Interests at June 30, 2018 and December 31, 2017 , respectively, associated with these entities. In June 2018, we reclassified $ 1,423 million of property, plant and equipment, net, plus other assets and liabilities associated with these entities, to held for sale, as we discuss in Note 5.

Sempra Energy’s Condensed Consolidated Statements of Operations for the three months and six months ended June 30, 2018 and 2017 include the following amounts associated with the tax equity limited liability companies. The amounts are net of eliminations of transactions between Sempra Energy and these entities.

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AMOUNTS ASSOCIATED WITH TAX EQUITY ARRANGEMENTS
(Dollars in millions)
		Three months ended June 30,							Six months ended June 30,
		2018			2017				2018			2017
REVENUES
Energy-related businesses		$	32		$	18			$	49		$	31
EXPENSES
Operation and maintenance		( 4		)	( 7		)		( 8		)	( 9		)
Depreciation and amortization		( 12		)	( 8		)		( 23		)	( 16		)
Income before income taxes		16			3				18			6
Income tax expense		( 7		)	( 4		)		( 12		)	( 6		)
Net income (loss)		9			( 1		)		6			—
Losses attributable to noncontrolling interests (1)		20			7				41			10
Earnings		$	29		$	6			$	47		$	10

(1)	Net income or loss attributable to NCI is computed using the HLBV method and is not based on ownership percentages.

We provide additional information regarding the tax equity limited liability companies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra LNG & Midstream

Sempra Energy’s equity method investment in Cameron LNG JV is considered to be a VIE principally due to contractual provisions that transfer certain risks to customers. Sempra Energy is not the primary beneficiary of the VIE because we do not have the power to direct the most significant activities of Cameron LNG JV. The carrying value of our investment in Cameron LNG JV, including amounts recognized in AOCI related to interest-rate cash flow hedges at Cameron LNG JV, was $ 1,182 million at June 30, 2018 and $ 997 million at December 31, 2017 . Our current maximum exposure to loss, which fluctuates over time, includes the carrying value of our investment and the guarantees that we discuss in Note 6 below and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Variable Interest Entities

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We discuss asset retirement obligations in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. The changes in asset retirement obligations are as follows:

CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
		Sempra Energy
		Consolidated							SDG&E							SoCalGas
		2018			2017				2018			2017				2018			2017
Balance at January 1 (1)		$	2,877		$	2,553			$	839		$	830			$	1,953		$	1,659
Accretion expense		60			54				19			19				38			33
Liabilities incurred		7			20				—			17				—			—
Reclassifications (2)		( 60		)	—				—			—				—			—
Payments		( 23		)	( 26		)		( 21		)	( 25		)		( 2		)	( 1		)
Revisions		28			( 6		)		29			—				( 1		)	( 6		)
Balance at June 30 (1)		$	2,889		$	2,595			$	866		$	841			$	1,988		$	1,685

(1)	Current portions of the obligations for Sempra Energy Consolidated and SoCalGas are included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.

(2)	In June 2018, we reclassified $ 57 million at Sempra Renewables and $ 8 million at Sempra LNG & Midstream to Liabilities Held for Sale, and $ 5 million related to TdM from Liabilities Held for Sale, as we discuss in Note 5.

Sale of Qualified Pension Plan Annuity Contracts

In March 2018, an insurance company purchased certain annuities for current annuitants in the SDG&E and SoCalGas qualified pension plans and assumed the obligation for payment of these annuities. At SDG&E in the first quarter of 2018 and at SoCalGas in the second quarter of 2018, the liability transferred for these annuities, plus the total year-to-date lump-sum payments, exceeded the settlement threshold, which triggered settlement accounting. This resulted in a reduction of the recorded pension liability and pension plan assets of $ 274 million at Sempra Energy Consolidated, including $ 97 million at SDG&E and $ 177 million at SoCalGas. This also resulted in settlement charges in net periodic benefit cost of $ 25 million and $ 39 million at Sempra Energy Consolidated, including $ 2 million and $ 16 million at SDG&E in the three months and six months ended June 30, 2018, respectively, and $ 23 million at SoCalGas in both the three months and six months ended June 30, 2018. The settlement charges were recorded as regulatory assets on the Condensed Consolidated Balance Sheets.

Acquisition

On March 9, 2018, Sempra Energy completed the Merger, as we discuss in Note 5, and assumed other postretirement employee benefits obligations for health care and life insurance benefits, resulting in an increase of $ 21 million in the other postretirement benefit plan liability at Sempra Energy Consolidated.

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Net Periodic Benefit Cost

The following three tables provide the components of net periodic benefit cost:

NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension benefits								Other postretirement benefits
	Three months ended June 30,
	2018				2017				2018				2017
Service cost	$	33			$	29			$	5			$	5
Interest cost	34				37				9				11
Expected return on assets	( 39		)		( 40		)		( 17		)		( 17		)
Amortization of:
Prior service cost	2				2				—				—
Actuarial loss (gain)	10				8				( 1		)		—
Settlements	25				—				—				—
Net periodic benefit cost (credit)	65				36				( 4		)		( 1		)
Regulatory adjustment	( 35		)		( 29		)		5				2
Total expense recognized	$	30			$	7			$	1			$	1
	Six months ended June 30,
	2018				2017				2018				2017
Service cost	$	66			$	57			$	11			$	11
Interest cost	69				74				18				20
Expected return on assets	( 81		)		( 80		)		( 35		)		( 33		)
Amortization of:
Prior service cost	5				5				—				—
Actuarial loss (gain)	19				16				( 2		)		( 1		)
Settlements	39				—				—				—
Net periodic benefit cost (credit)	117				72				( 8		)		( 3		)
Regulatory adjustment	( 80		)		( 41		)		9				4
Total expense recognized	$	37			$	31			$	1			$	1

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NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension benefits								Other postretirement benefits
	Three months ended June 30,
	2018				2017				2018				2017
Service cost	$	8			$	7			$	1			$	2
Interest cost	8				10				1				2
Expected return on assets	( 12		)		( 13		)		( 4		)		( 4		)
Amortization of:
Prior service cost	1				1				1				1
Actuarial loss	2				2				—				—
Settlements	2				—				—				—
Net periodic benefit cost (credit)	9				7				( 1		)		1
Regulatory adjustment	( 8		)		( 7		)		1				( 1		)
Total expense recognized	$	1			$	—			$	—			$	—
	Six months ended June 30,
	2018				2017				2018				2017
Service cost	$	16			$	15			$	2			$	3
Interest cost	17				19				3				4
Expected return on assets	( 25		)		( 24		)		( 7		)		( 7		)
Amortization of:
Prior service cost	1				1				2				2
Actuarial loss (gain)	3				4				( 1		)		—
Settlements	16				—				—				—
Net periodic benefit cost (credit)	28				15				( 1		)		2
Regulatory adjustment	( 27		)		( 14		)		1				( 2		)
Total expense recognized	$	1			$	1			$	—			$	—

NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension benefits								Other postretirement benefits
	Three months ended June 30,
	2018				2017				2018				2017
Service cost	$	21			$	18			$	4			$	3
Interest cost	22				24				7				8
Expected return on assets	( 25		)		( 25		)		( 14		)		( 13		)
Amortization of:
Prior service cost	2				2				—				—
Actuarial loss (gain)	6				4				( 1		)		( 1		)
Settlements	23				—				—				—
Net periodic benefit cost (credit)	49				23				( 4		)		( 3		)
Regulatory adjustment	( 27		)		( 22		)		4				3
Total expense recognized	$	22			$	1			$	—			$	—
	Six months ended June 30,
	2018				2017				2018				2017
Service cost	$	43			$	36			$	8			$	7
Interest cost	45				48				14				15
Expected return on assets	( 51		)		( 51		)		( 28		)		( 26		)
Amortization of:
Prior service cost (credit)	4				4				( 1		)		( 1		)
Actuarial loss (gain)	12				8				( 1		)		( 1		)
Settlements	23				—				—				—
Net periodic benefit cost (credit)	76				45				( 8		)		( 6		)
Regulatory adjustment	( 53		)		( 27		)		8				6
Total expense recognized	$	23			$	18			$	—			$	—

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Benefit Plan Contributions

The following table shows our year-to-date contributions to pension and other postretirement benefit plans and the amounts we expect to contribute in 2018 :

The following table provides EPS computations for the three months and six months ended June 30, 2018 and 2017 . Basic EPS is calculated by dividing (losses) earnings attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

(LOSSES) EARNINGS PER COMMON SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Three months ended June 30,								Six months ended June 30,
	2018				2017				2018				2017
Numerator:
(Losses) earnings attributable to common shares	$	( 561	)		$	259			$	( 214	)		$	700
Denominator:
Weighted-average common shares outstanding for basic EPS (1)	265,837				251,447				261,906				251,290
Dilutive effect of stock options, RSAs and RSUs (2)(3)	—				1,375				—				1,319
Dilutive effect of common stock shares sold forward (2)	—				—				—				—
Weighted-average common shares outstanding for diluted EPS (2)	265,837				252,822				261,906				252,609
EPS:
Basic	$	( 2.11	)		$	1.03			$	( 0.82	)		$	2.79
Diluted	$	( 2.11	)		$	1.03			$	( 0.82	)		$	2.77

(1)

Includes 640 and 608 average fully vested RSUs held in our Deferred Compensation Plan for the three months ended June 30, 2018 and 2017 , respectively, and 634 and 604 of such RSUs for the six months ended June 30, 2018 and 2017 , respectively. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.

(2)

In the three months and six months ended June 30, 2018, the total weighted-average number of potentially dilutive stock options, RSAs and RSUs was 986 and 931 , respectively, and the total weighted-average number of potentially dilutive common stock shares sold forward was 714 and 746 , respectively. However, these securities were not included in the computation of EPS since to do so would have decreased the loss per share.

(3)	Due to market fluctuations of both Sempra Energy common stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report, dilutive RSUs may vary widely from period-to-period.

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The potentially dilutive impact from stock options, RSAs and RSUs is calculated under the treasury stock method. Under this method, proceeds based on the exercise price and unearned compensation are assumed to be used to repurchase shares on the open market at the average market price for the period, reducing the number of potential new shares to be issued and sometimes causing an antidilutive effect. The computation of diluted EPS for both the three months and six months ended June 30, 2018 and 2017 excludes 1,816 and 3,010 potentially dilutive shares, respectively, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future.

The potentially dilutive impact from the forward sale of our common stock pursuant to the forward sale agreements that we discuss below in “Shareholders’ Equity and Noncontrolling Interests – Sempra Energy Common Stock Offerings,” is reflected in our diluted EPS calculation using the treasury stock method. We anticipate there will be a dilutive effect on our EPS when the average market price of shares of our common stock is above the applicable adjusted forward sale price, subject to increase or decrease based on the overnight bank funding rate, less a spread, and subject to decrease by amounts related to expected dividends on shares of our common stock during the term of the forward sale agreements. Additionally, if we decide to physically settle or net share settle the forward sale agreements, delivery of our shares to the forward purchasers on any such physical settlement or net share settlement of the forward sale agreements would result in dilution to our EPS.

The potentially dilutive impact from our 6% mandatory convertible preferred stock, series A (series A preferred stock) issued in January 2018 is calculated under the if-converted method. The computation of diluted EPS for both the three months and six months ended June 30, 2018 excludes 15,296,567 potentially dilutive shares, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future. We discuss the issuance of the series A preferred stock in “Shareholders’ Equity and Noncontrolling Interests – Sempra Energy 6% Mandatory Convertible Preferred Stock, Series A” below.

Pursuant to our Sempra Energy share-based compensation plans, Sempra Energy’s Board of Directors granted 358,363 performance-based RSUs and 266,569 service-based RSUs during the six months ended June 30, 2018 , primarily in January. During the six months ended June 30, 2018 , IEnova granted 966,747 RSUs from the IEnova 2013 Long-Term Incentive Plan, under which awards are cash settled at vesting based on the price of IEnova common stock.

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The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to NCI:

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT (1)
(Dollars in millions)
	Foreign currency translation adjustments				Financial instruments				Pension and other postretirement benefits				Total accumulated other comprehensive income (loss)
	Three months ended June 30, 2018 and 2017
Sempra Energy Consolidated:
Balance as of March 31, 2018	$	( 396	)		$	( 67	)		$	( 82	)		$	( 545	)
OCI before reclassifications	( 86		)		19				1				( 66		)
Amounts reclassified from AOCI	—				8				2				10
Net OCI	( 86		)		27				3				( 56		)
Balance as of June 30, 2018	$	( 482	)		$	( 40	)		$	( 79	)		$	( 601	)
									.
Balance as of March 31, 2017	$	( 481	)		$	( 121	)		$	( 94	)		$	( 696	)
OCI before reclassifications	3				( 26		)		—				( 23		)
Amounts reclassified from AOCI	—				—				1				1
Net OCI	3				( 26		)		1				( 22		)
Balance as of June 30, 2017	$	( 478	)		$	( 147	)		$	( 93	)		$	( 718	)
SDG&E:
Balance as of March 31, 2018 and June 30, 2018									$	( 8	)		$	( 8	)
Balance as of March 31, 2017 and June 30, 2017									$	( 8	)		$	( 8	)
SoCalGas:
Balance as of March 31, 2018					$	( 13	)		$	( 8	)		$	( 21	)
Amounts reclassified from AOCI					—				1				1
Net OCI					—				1				1
Balance as of June 30, 2018					$	( 13	)		$	( 7	)		$	( 20	)
Balance as of March 31, 2017					$	( 13	)		$	( 9	)		$	( 22	)
Amounts reclassified from AOCI					—				1				1
Net OCI					—				1				1
Balance as of June 30, 2017					$	( 13	)		$	( 8	)		$	( 21	)

(1)	All amounts are net of income tax, if subject to tax, and exclude NCI.

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CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT (1)
(Dollars in millions)
	Foreign currency translation adjustments				Financial instruments				Pension and other postretirement benefits				Total accumulated other comprehensive income (loss)
	Six months ended June 30, 2018 and 2017
Sempra Energy Consolidated:
Balance as of December 31, 2017	$	( 420	)		$	( 122	)		$	( 84	)		$	( 626	)
Cumulative-effect adjustment from change in accounting principle	—				( 3		)		—				( 3		)
OCI before reclassifications	( 62		)		85				1				24
Amounts reclassified from AOCI	—				—				4				4
Net OCI	( 62		)		85				5				28
Balance as of June 30, 2018	$	( 482	)		$	( 40	)		$	( 79	)		$	( 601	)
Balance as of December 31, 2016	$	( 527	)		$	( 125	)		$	( 96	)		$	( 748	)
OCI before reclassifications	49				( 28		)		—				21
Amounts reclassified from AOCI	—				6				3				9
Net OCI	49				( 22		)		3				30
Balance as of June 30, 2017	$	( 478	)		$	( 147	)		$	( 93	)		$	( 718	)
SDG&E:
Balance as of December 31, 2017 and June 30, 2018									$	( 8	)		$	( 8	)
Balance as of December 31, 2016 and June 30, 2017									$	( 8	)		$	( 8	)
SoCalGas:
Balance as of December 31, 2017					$	( 13	)		$	( 8	)		$	( 21	)
Amounts reclassified from AOCI					—				1				1
Net OCI					—				1				1
Balance as of June 30, 2018					$	( 13	)		$	( 7	)		$	( 20	)
Balance as of December 31, 2016					$	( 13	)		$	( 9	)		$	( 22	)
Amounts reclassified from AOCI					—				1				1
Net OCI					—				1				1
Balance as of June 30, 2017					$	( 13	)		$	( 8	)		$	( 21	)

(1)	All amounts are net of income tax, if subject to tax, and exclude NCI.

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RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)								Affected line item on Condensed Consolidated Statements of Operations
	Three months ended June 30,
	2018				2017
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments (1)	$	1			$	( 1	)		Interest Expense
Interest rate and foreign exchange instruments	18				—				Other (Expense) Income, Net
Interest rate and foreign exchange instruments	1				5				Equity (Losses) Earnings
Foreign exchange instruments	( 1		)		( 1		)		Revenues: Energy-Related Businesses
Total before income tax	19				3
	( 4		)		( 1		)		Income Tax Benefit (Expense)
Net of income tax	15				2
	( 7		)		( 2		)		(Earnings) Losses Attributable to Noncontrolling Interests
	$	8			$	—
Pension and other postretirement benefits:
Amortization of actuarial loss (2)	$	3			$	2			Other (Expense) Income, Net
	( 1		)		( 1		)		Income Tax Benefit (Expense)
Net of income tax	$	2			$	1
Total reclassifications for the period, net of tax	$	10			$	1
SDG&E:
Financial instruments:
Interest rate instruments (1)	$	1			$	3			Interest Expense
	( 1		)		( 3		)		(Earnings) Losses Attributable to Noncontrolling Interest
Total reclassifications for the period, net of tax	$	—			$	—
SoCalGas:
Pension and other postretirement benefits:
Amortization of actuarial loss (2)	$	1			$	1			Other Income, Net
Total reclassifications for the period, net of tax	$	1			$	1

(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.

(2)	Amounts are included in the computation of net periodic benefit cost (see “Pension and Other Postretirement Benefits” above).

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RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)								Affected line item on Condensed Consolidated Statements of Operations
	Six months ended June 30,
	2018				2017
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments (1)	$	( 1	)		$	( 4	)		Interest Expense
Interest rate and foreign exchange instruments	5				9				Equity (Losses) Earnings
Foreign exchange instruments	( 1		)		1				Revenues: Energy-Related Businesses
Commodity contracts not subject to rate recovery	—				9				Revenues: Energy-Related Businesses
Total before income tax	3				15
	( 1		)		( 5		)		Income Tax Benefit (Expense)
Net of income tax	2				10
	( 2		)		( 4		)		(Earnings) Losses Attributable to Noncontrolling Interests
	$	—			$	6
Pension and other postretirement benefits:
Amortization of actuarial loss (2)	$	6			$	5			Other (Expense) Income, Net
	( 2		)		( 2		)		Income Tax Benefit (Expense)
Net of income tax	$	4			$	3
Total reclassifications for the period, net of tax	$	4			$	9
SDG&E:
Financial instruments:
Interest rate instruments (1)	$	4			$	6			Interest Expense
	( 4		)		( 6		)		(Earnings) Losses Attributable to Noncontrolling Interest
Total reclassifications for the period, net of tax	$	—			$	—
SoCalGas:
Pension and other postretirement benefits:
Amortization of actuarial loss (2)	$	1			$	1			Other Income, Net
Total reclassifications for the period, net of tax	$	1			$	1

(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.

(2)	Amounts are included in the computation of net periodic benefit cost (see “Pension and Other Postretirement Benefits” above).

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The following tables provide reconciliations of changes in Sempra Energy’s, SDG&E’s and SoCalGas’ shareholders’ equity and NCI for the six months ended June 30, 2018 and 2017 .

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Sempra Energy shareholders ’ equity				Non- controlling interests (1)				Total equity
Balance at December 31, 2017	$	12,670			$	2,470			$	15,140
Cumulative-effect adjustment from change in accounting principle (2)	( 1		)		—				( 1		)
Comprehensive (loss) income	( 132		)		1				( 131		)
Share-based compensation expense	33				—				33
Mandatory convertible preferred stock dividends declared	( 53		)		—				( 53		)
Preferred dividends of subsidiary	( 1		)		—				( 1		)
Common stock dividends declared	( 480		)		—				( 480		)
Issuances of mandatory convertible preferred stock	1,693				—				1,693
Issuances of common stock	2,117				—				2,117
Repurchases of common stock	( 20		)		—				( 20		)
Equity contributed by noncontrolling interest	—				1				1
Distributions to noncontrolling interests	—				( 18		)		( 18		)
Purchase of noncontrolling interests	—				( 1		)		( 1		)
Sale of noncontrolling interests, net of offering costs	—				85				85
Balance at June 30, 2018	$	15,826			$	2,538			$	18,364
Balance at December 31, 2016	$	12,951			$	2,290			$	15,241
Comprehensive income	731				8				739
Share-based compensation expense	23				—				23
Preferred dividends of subsidiary	( 1		)		—				( 1		)
Common stock dividends declared	( 413		)		—				( 413		)
Issuances of common stock	55				—				55
Repurchases of common stock	( 14		)		—				( 14		)
Equity contributed by noncontrolling interests	—				1				1
Distributions to noncontrolling interests	—				( 26		)		( 26		)
Balance at June 30, 2017	$	13,332			$	2,273			$	15,605

(1)	NCI includes the preferred stock of SoCalGas and other NCI as listed in the table below under “Other Noncontrolling Interests.”

(2)	Represents impact from adoption of ASU 2016-01, which we discuss in Note 2.

SHAREHOLDER’S EQUITY AND NONCONTROLLING INTEREST – SDG&E
(Dollars in millions)
	SDG&E shareholder ’ s equity				Non- controlling interest				Total equity
Balance at December 31, 2017	$	5,598			$	28			$	5,626
Comprehensive income	316				4				320
Equity contributed by noncontrolling interest	—				1				1
Distributions to noncontrolling interest	—				( 4		)		( 4		)
Balance at June 30, 2018	$	5,914			$	29			$	5,943
Balance at December 31, 2016	$	5,641			$	37			$	5,678
Comprehensive income	304				10				314
Common stock dividends declared	( 175		)		—				( 175		)
Equity contributed by noncontrolling interest	—				1				1
Distributions to noncontrolling interest	—				( 14		)		( 14		)
Balance at June 30, 2017	$	5,770			$	34			$	5,804

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SHAREHOLDERS’ EQUITY – SOCALGAS
(Dollars in millions)
	Total equity
Balance at December 31, 2017	$	3,907
Comprehensive income	260
Preferred stock dividends declared	( 1		)
Balance at June 30, 2018	$	4,166
Balance at December 31, 2016	$	3,510
Comprehensive income	263
Preferred stock dividends declared	( 1		)
Balance at June 30, 2017	$	3,772

Ownership interests that are held by owners other than Sempra Energy and SDG&E in subsidiaries or entities consolidated by them are accounted for and reported as NCI. As a result, NCI is reported as a separate component of equity on the Condensed Consolidated Balance Sheets. Earnings or losses attributable to NCI are separately identified on the Condensed Consolidated Statements of Operations, and comprehensive income or loss attributable to NCI is separately identified on the Condensed Consolidated Statements of Comprehensive Income (Loss).

Sempra Energy 6% Mandatory Convertible Preferred Stock, Series A

On January 9, 2018, we issued 17,250,000 shares of our series A preferred stock in a registered public offering at $ 100.00 per share (or $ 98.20 per share after deducting underwriting discounts), including 2,250,000 shares purchased by the underwriters directly from us as a result of fully exercising their option to purchase such shares from us solely to cover overallotments. Each share of series A preferred stock has a liquidation value of $ 100.00 . We used the net proceeds of approximately $ 1.69 billion (net of underwriting discounts and equity issuance costs of $ 32 million ) to fund a portion of the Merger Consideration, as we discuss in Note 5. We discuss the terms of the series A preferred stock in Note 18 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra Energy 6.75% Mandatory Convertible Preferred Stock, Series B

On July 13, 2018, Sempra Energy issued 5,750,000 shares of our series B preferred stock and received proceeds of approximately $ 565.5 million (net of underwriting discounts, but before deducting equity issuance costs), which we discuss in Note 13.

Sempra Energy Common Stock Offerings

On January 9, 2018, we completed the offering of 23,364,486 shares of our common stock, no par value, in a registered public offering at $ 107.00 per share (approximately $ 105.07 per share after deducting the underwriting discount), pursuant to forward sale agreements with each of Morgan Stanley & Co. LLC, an affiliate of RBC Capital Markets, LLC and an affiliate of Barclays Capital Inc. (the forward purchasers). The shares offered pursuant to the forward sale agreements were borrowed by the underwriters and therefore are not newly issued shares. The underwriters of the offering fully exercised the option we granted them to purchase an additional 3,504,672 shares of common stock directly from us solely to cover overallotments. After the offering, including the issuance of shares pursuant to the exercise of the overallotment option, the aggregate shares of common stock sold in the offering totaled 26,869,158 . We received net proceeds of $ 367 million (net of underwriting discounts and equity issuance costs of $ 8 million ) from the sale of shares to cover overallotments. The initial forward sale price under the forward sale agreements is approximately $ 105.07 per share, which was the public offering price in the common stock offering less the underwriting discount. However, the forward sale price is subject to adjustment pursuant to the forward sale agreements. We did not initially receive any proceeds from the sale of our common stock sold by the forward sellers to the underwriters.

In the three months and six months ended June 30, 2018, we settled approximately $ 800 million (net of underwriting discounts of $ 14 million ) and $ 1.7 billion (net of underwriting discounts of $ 30 million ), respectively, of forward sales under the forward sale agreements by delivering 7,651,671 shares and 16,208,301 shares, respectively, of newly issued Sempra Energy common stock at forward sale prices ranging from approximately $ 104.53 to approximately $ 105.18 per share.

We used the net proceeds from the sale of shares in the January 2018 offering and from the settlement of forward sales in the first quarter of 2018 under the forward sale agreements to fund a portion of the Merger Consideration, as we discuss in Note 5. We used the net proceeds from the settlement of forward sales in the second quarter of 2018 to repay long-term debt maturing in June 2018 and to repay commercial paper used to fund a portion of the Merger Consideration.

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On July 13, 2018, we completed the offering of 9,750,000 shares of our common stock in a registered public offering, pursuant to forward sale agreements. In connection with the overallotment option granted to the underwriters, on July 13, 2018, we issued 1,462,500 shares of our common stock and received net proceeds of $ 163.6 million (net of underwriting discounts, but before deducting equity issuance costs) for such shares, which we discuss in Note 13.

As of August 6, 2018, a total of 16,906,185 shares of Sempra Energy common stock from our January and July 2018 offerings remain subject to future settlement under these forward sale agreements, which may be settled on one or more dates specified by us occurring no later than December 15, 2019. Although we expect to settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may, subject to certain conditions, elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements. The forward sale agreements are also subject to acceleration by the forward purchasers upon the occurrence of certain events.

SoCalGas Preferred Stock

The preferred stock at SoCalGas is presented at Sempra Energy as a noncontrolling interest. Sempra Energy records charges against income related to NCI for preferred stock dividends declared by SoCalGas. We provide additional information regarding preferred stock in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Noncontrolling Interests

At June 30, 2018 and December 31, 2017 , we reported the following noncontrolling ownership interests held by others (not including preferred shareholders) in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Condensed Consolidated Balance Sheets:

OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
	Percent ownership held by noncontrolling interests				Equity (deficit) held by noncontrolling interests
	June 30, 2018		December 31, 2017		June 30, 2018				December 31, 2017
SDG&E:
Otay Mesa VIE	100	%	100	%	$	29			$	28
Sempra South American Utilities:
Chilquinta Energía subsidiaries (1)	19.8 – 43.4		22.9 – 43.4		23				24
Luz del Sur	16.4		16.4		192				189
Tecsur	9.8		9.8		4				4
Sempra Mexico:
IEnova (2)	33.6		33.6		1,605				1,532
Sempra Renewables:
Tax equity arrangements – wind (3)	NA		NA		160				181
Tax equity arrangements – solar (3)	NA		NA		509				450
Sempra LNG & Midstream:
Bay Gas	9.1		9.1		8				28
Liberty Gas Storage, LLC	24.6		24.6		( 12		)		14
Total Sempra Energy					$	2,518			$	2,450

(1)	Chilquinta Energía has four subsidiaries with NCI held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.

(2)	IEnova has a subsidiary with a 10 -percent NCI held by others. The equity held by NCI is negligible at both June 30, 2018 and December 31, 2017.

(3)	Net income or loss attributable to NCI is computed using the HLBV method and is not based on ownership percentages.

Sempra Renewables

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Amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas are as follows:

AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	June 30, 2018				December 31, 2017
Sempra Energy Consolidated:
Total due from various unconsolidated affiliates – current	$	40			$	37
Sempra South American Utilities (1) :
Eletrans – 4% Note (2)	$	38			$	103
Other related party receivables	1				1
Sempra Mexico (1) :
IMG – Note due March 15, 2022 (3)	589				487
Energía Sierra Juárez – Note (4)	6				7
Total due from unconsolidated affiliates – noncurrent	$	634			$	598
Total due to various unconsolidated affiliates – current	$	( 10	)		$	( 7	)
Sempra Mexico (1) :
Total due to unconsolidated affiliates – noncurrent – TAG – Note due December 20, 2021 (5)	$	( 36	)		$	( 35	)
SDG&E:
Total due from various unconsolidated affiliates – current	$	1			$	—
Sempra Energy	$	( 38	)		$	( 30	)
SoCalGas	—				( 4		)
Various affiliates	( 11		)		( 6		)
Total due to unconsolidated affiliates – current	$	( 49	)		$	( 40	)
Income taxes due from Sempra Energy (6)	$	47			$	27
SoCalGas:
Total due from unconsolidated affiliates – current – SDG&E	$	—			$	4
Total due to unconsolidated affiliates – current – Sempra Energy	$	( 48	)		$	( 35	)
Income taxes due from Sempra Energy (6)	$	5			$	10

(1)	Amounts include principal balances plus accumulated interest outstanding.

(2)	U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans, comprising joint ventures of Chilquinta Energía.

(3)	Mexican peso-denominated revolving line of credit for up to $ 14.2 billion Mexican pesos or approximately $ 711 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 bps ( 10.34 percent at June 30, 2018 ), to finance construction of the natural gas marine pipeline.

(4)	U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 637.5 bps ( 8.47 percent at June 30, 2018 ) with no stated maturity date, to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova.

(5)	U.S. dollar-denominated loan, at a variable interest rate based on the 6-month LIBOR plus 290 bps ( 5.40 percent at June 30, 2018 ).

(6)	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from each company having always filed a separate return.

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Revenues and cost of sales from unconsolidated affiliates are as follows:

REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	Three months ended June 30,								Six months ended June 30,
	2018				2017				2018				2017
Revenues:
Sempra Energy Consolidated	$	16			$	8			$	32			$	15
SDG&E	1				2				3				4
SoCalGas	15				17				32				35
Cost of Sales:
Sempra Energy Consolidated	$	15			$	14			$	27			$	28
SDG&E	16				19				35				39

Guarantees

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Other Income (Expense), Net on the Condensed Consolidated Statements of Operations consists of the following:

OTHER INCOME (EXPENSE), NET
(Dollars in millions)
	Three months ended June 30,								Six months ended June 30,
	2018				2017 (1)				2018				2017 (1)
Sempra Energy Consolidated:
Allowance for equity funds used during construction	$	29			$	40			$	56			$	112
Investment gains (2)	6				14				5				30
(Losses) gains on interest rate and foreign exchange instruments, net	( 55		)		31				7				94
Foreign currency transaction (losses) gains, net (3)	( 41		)		7				( 11		)		17
Non-service component of net periodic benefit credit	7				17				39				22
Interest on regulatory balancing accounts, net	1				—				1				2
Sundry, net	( 1		)		( 1		)		2				5
Total	$	( 54	)		$	108			$	99			$	282
SDG&E:
Allowance for equity funds used during construction	$	16			$	16			$	34			$	31
Non-service component of net periodic benefit credit	8				4				17				8
Interest on regulatory balancing accounts, net	2				—				2				2
Sundry, net	( 1		)		( 1		)		—				—
Total	$	25			$	19			$	53			$	41
SoCalGas:
Allowance for equity funds used during construction	$	13			$	11			$	22			$	22
Non-service component of net periodic benefit credit	3				15				28				18
Interest on regulatory balancing accounts, net	( 1		)		—				( 1		)		—
Sundry, net	( 2		)		( 2		)		( 3		)		( 2		)
Total	$	13			$	24			$	46			$	38

(1)	As adjusted for the retrospective adoption of ASU 2017-07, which we discuss in Note 2.

(2)	Represents investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans, recorded in Operation and Maintenance on the Condensed Consolidated Statements of Operations.

(3)

Includes losses of $ 47 million and $ 8 million in the three months and six months ended June 30, 2018, respectively, and gains of $ 6 million in both the three months and six months ended June 30, 2017 from translation to U.S. dollars of a Mexican peso-denominated loan to the IMG joint venture, which are offset by corresponding amounts included in Equity (Losses) Earnings on the Condensed Consolidated Statements of Operations.

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INCOME TAX (BENEFIT) EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Three months ended June 30,								Six months ended June 30,
	2018				2017				2018				2017
Sempra Energy Consolidated:
Income tax (benefit) expense	$	( 583	)		$	167			$	( 294	)		$	462
(Loss) income before income taxes and equity (losses) earnings
of unconsolidated subsidiaries	$	( 1,109	)		$	397			$	( 442	)		$	1,149
Equity (losses) earnings, before income tax (1)	( 189		)		18				( 184		)		21
Pretax (loss) income	$	( 1,298	)		$	415			$	( 626	)		$	1,170
Effective income tax rate	45		%		40		%		47		%		39		%
SDG&E:
Income tax expense	$	42			$	54			$	98			$	144
Income before income taxes	$	188			$	207			$	413			$	454
Effective income tax rate	22		%		26		%		24		%		32		%
SoCalGas:
Income tax expense	$	23			$	19			$	82			$	117
Income before income taxes	$	57			$	78			$	341			$	379
Effective income tax rate	40		%		24		%		24		%		31		%

(1)	We discuss how we recognize equity (losses) earnings in Note 6.

Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted ETR anticipated for the full year, in accordance with U.S. GAAP. Unusual and infrequent items and items that cannot be reliably estimated are recorded in the interim period in which they actually occur, which can result in variability in the ETR.

For SDG&E and SoCalGas, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the ETR. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the ETR. The following items are subject to flow-through treatment:

▪	repairs expenditures related to a certain portion of utility plant assets

▪	the equity portion of AFUDC

▪	a portion of the cost of removal of utility plant assets

▪	utility self-developed software expenditures

▪	depreciation on a certain portion of utility plant assets

▪	state income taxes

The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico has similar flow-through treatment.

We record income tax (expense) benefit from the transactional effects of foreign currency and inflation. Such effects are partially mitigated by net gains (losses) from foreign currency derivatives that are hedging Sempra Mexico parent’s exposure to movements in the Mexico peso from its controlling interest in IEnova.

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On December 22, 2017, the TCJA was signed into law. The TCJA reduced the U.S. statutory corporate federal income tax rate from 35 percent to 21 percent , effective January 1, 2018. In the fourth quarter of 2017, we recorded $ 870 million of income tax expense related to the effects of the TCJA. This expense was provisional, using our best estimates and the information available to us through the date those financial statements were issued. As permitted by and in accordance with the guidance issued by the SEC and codified in ASU 2018-05, we may adjust our provisional estimates in reporting periods throughout 2018 as we complete our analysis and as more information becomes available, and these adjustments may affect earnings. Events and information that may still result in adjustments to our provisional estimates include interpretations of rulings by the U.S. Department of the Treasury or states, the filing of our 2017 income tax return and the finalization of our calculation of foreign undistributed earnings. In the six months ended June 30, 2018, Sempra Energy recorded $ 25 million of additional income tax expense to adjust the provisional estimates recorded in 2017. Additionally, SDG&E and SoCalGas adjusted their provisional estimates relating to the remeasurement of deferred income taxes. In the six months ended June 30, 2018, SDG&E’s deferred tax liabilities decreased by $ 38 million and SoCalGas’ deferred tax liabilities increased by $ 5 million , with each amount offset by a change in their respective regulatory liabilities.

We describe below recent accounting pronouncements that have had or may have a significant effect on our financial condition, results of operations, cash flows or disclosures.

ASU 2014-09, “Revenue from Contracts with Customers,” ASU 2015-14, “Deferral of the Effective Date,” ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” ASU 2016-10, “Identifying Performance Obligations and Licensing” and ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients”: ASU 2014-09 adds ASC 606 to provide accounting guidance for the recognition of revenue from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. Amending ASU 2014-09, ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations, ASU 2016-10 clarifies the determination of whether a good or service is separately identifiable from other promises and revenue recognition related to licenses of intellectual property, and ASU 2016-12 provides guidance on transition, collectability, noncash consideration, and the presentation of sales and other similar taxes. The ASUs are codified in ASC 606.

We adopted ASC 606 on January 1, 2018, applying the modified retrospective transition method to all contracts as of January 1, 2018 and elected to use certain practical expedients available under the transition guidance. The impact from adoption was not material to our financial statements, and the timing of our revenue recognition has remained materially consistent before and after the adoption of ASC 606. The new revenue standard provides specific guidance for combining contracts, which resulted in a prospective reclassification between cost of sales and revenues within our Sempra LNG & Midstream segment. This reclassification had no impact on Sempra Energy’s consolidated revenues or cost of sales. Our additional disclosures about the nature, amount, timing and uncertainty of revenues arising from contracts with customers are included in Note 3.

ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities” and ASU 2018-03, “Technical Corrections and Improvements to Financial Instruments – Overall”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments, other than those accounted for under the equity method, at fair value and recognize changes in fair value in net income. Entities will no longer be able to use the cost method of accounting for equity securities. However, for equity investments without readily determinable fair values that do not qualify for the practical expedient to estimate fair value using net asset value per share, entities may elect a measurement alternative that will allow those investments to be recorded at cost, less impairment, and adjusted for subsequent observable price changes. ASU 2018-03 clarifies that the prospective transition approach for equity investments without readily determinable fair values is meant only for instances in which the measurement alternative is elected. Entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted, except for equity investments without readily determinable fair values, for which the guidance will be applied prospectively.

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We adopted ASU 2016-01 and ASU 2018-03 on January 1, 2018. Sempra Energy recognized a cumulative-effect adjustment to decrease Retained Earnings and Other Investments as of January 1, 2018 by $ 1 million .

ASU 2016-02, “Leases,” ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” ASU 2018-10, “Codification Improvements to Topic 842, Leases” and ASU 2018-11, “Leases (Topic 842): Targeted Improvements”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting and ASC 606. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-10 makes technical corrections and clarifications to the accounting guidance in Topic 842.

For public entities, these ASUs are effective for fiscal years beginning after December 15, 2018, including interim periods therein, with early adoption permitted. ASU 2016-02 requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. ASU 2018-11 provides entities an optional transition method to apply the new guidance as of the adoption date, rather than as of the earliest period presented. In transition, entities may elect certain practical expedients when applying ASU 2016-02. These include a package of practical expedients that must be applied in its entirety to all leases commencing before the effective date, unless the lease is modified, to not reassess (a) the existence of a lease, (b) lease classification or (c) determination of initial direct costs, which effectively allows entities to carryforward accounting conclusions under previous U.S. GAAP. ASU 2016-02 also includes a practical expedient to use hindsight in making judgments when determining the lease term and any long-lived asset impairment. ASU 2018-01 allows entities to elect a practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP. ASU 2018-11 provides a lessor practical expedient for separating lease and non-lease components.

We are currently evaluating the effect of the standards on our ongoing financial reporting and plan to adopt the standards on January 1, 2019, using the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. As part of our evaluation, we formed a steering committee comprised of members from Sempra Energy’s business units, are compiling our population of contracts and are preparing our lease accounting assessments. Based on our assessment to date, we have determined that we will elect the package of practical expedients and the land easement practical expedient available under the transition guidance described above, but will not elect to use the hindsight practical expedient.

ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13 changes how entities will measure credit losses for most financial assets and certain other instruments. The standard introduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for estimating the credit losses.

For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods therein, with early adoption permitted for fiscal years beginning after December 15, 2018. The amendments are to be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings at the beginning of the first reporting period in the year of adoption. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard.

ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments” and ASU 2016-18, “Restricted Cash”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows to reduce diversity in practice.

ASU 2016-18 requires amounts classified as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. A reconciliation between the balance sheet and the statement of cash flows must be disclosed when the balance sheet includes more than one line item for cash, cash equivalents, restricted cash and restricted cash equivalents.

We early adopted ASU 2016-15 and ASU 2016-18 on a retrospective basis in the fourth quarter of 2017. Neither ASU impacted SoCalGas’ Condensed Statements of Cash Flows. The adoption of ASU 2016-15 did not impact the Sempra Energy or SDG&E Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2017, based on the timing of cash receipts and cash payments affected by the ASU.

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Upon adoption of ASU 2016-18, Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2017 were impacted as follows:

IMPACT FROM ADOPTION OF ASU 2016-18
(Dollars in millions)
	Six months ended June 30, 2017
	As previously reported				Effect of adoption				As adjusted
Sempra Energy Condensed Consolidated Statement of Cash Flows:
Cash flows from investing activities:
Increases in restricted cash	$	( 194	)		$	194			$	—
Decreases in restricted cash	185				( 185		)		—
Net cash used in investing activities	( 2,067		)		9				( 2,058		)
Effect of exchange rate changes on cash and cash equivalents	8				( 8		)		—
Effect of exchange rate changes on cash, cash equivalents and restricted cash	—				10				10
Decrease in cash and cash equivalents	( 126		)		126				—
Decrease in cash, cash equivalents, and restricted cash	—				( 115		)		( 115		)
Cash and cash equivalents, January 1	349				( 349		)		—
Cash, cash equivalents and restricted cash, January 1	—				425				425
Cash and cash equivalents, June 30	223				( 223		)		—
Cash, cash equivalents and restricted cash, June 30	—				310				310
SDG&E Condensed Consolidated Statement of Cash Flows:
Cash flows from investing activities:
Increases in restricted cash	$	( 20	)		$	20			$	—
Decreases in restricted cash	18				( 18		)		—
Net cash used in investing activities	( 734		)		2				( 732		)
Increase in cash and cash equivalents	4				( 4		)		—
Increase in cash, cash equivalents, and restricted cash	—				6				6
Cash and cash equivalents, January 1	8				( 8		)		—
Cash, cash equivalents and restricted cash, January 1	—				20				20
Cash and cash equivalents, June 30	12				( 12		)		—
Cash, cash equivalents and restricted cash, June 30	—				26				26

ASU 2017-04, “Simplifying the Test for Goodwill Impairment”: ASU 2017-04 removes the second step of the goodwill impairment test, which requires a hypothetical purchase price allocation. An entity will be required to apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill. For public entities, ASU 2017-04 is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. The amendments are to be applied on a prospective basis. We have not yet selected the year in which we will adopt the standard.

ASU 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”: ASU 2017-05 clarifies the scope of accounting for the derecognition or partial sale of nonfinancial assets to exclude all businesses and nonprofit activities. ASU 2017-05 also provides a definition for in-substance nonfinancial assets and additional guidance on partial sales of nonfinancial assets. We adopted the standard in conjunction with our adoption of ASC 606 on January 1, 2018 using the modified retrospective transition method and it did not materially affect our financial condition, results of operations or cash flows.

ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. The guidance allows a practical expedient that permits use of previously disclosed service costs and other costs from the pension and other postretirement benefit plan disclosure in the comparative periods as appropriate

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estimates when retrospectively changing the presentation of these costs in the statements of operations. We adopted the standard on January 1, 2018 and elected the practical expedient available under the transition guidance.

Upon adoption of ASU 2017-07, our Condensed Consolidated Statements of Operations were impacted as follows:

IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Three months ended June 30, 2017												Six months ended June 30, 2017
	As previously reported				Effect of adoption				As adjusted				As previously reported				Effect of adoption				As adjusted
Sempra Energy:
Operation and maintenance	$	731			$	17			$	748			$	1,445			$	22			$	1,467
Other (expense) income, net	91				17				108				260				22				282
SDG&E:
Operation and maintenance	$	237			$	4			$	241			$	464			$	8			$	472
Total operating expenses	817				4				821				1,596				8				1,604
Operating income	241				( 4		)		237				519				( 8		)		511
Other income, net	15				4				19				33				8				41
SoCalGas:
Operation and maintenance	$	336			$	15			$	351			$	689			$	18			$	707
Total operating expenses	675				15				690				1,601				18				1,619
Operating income	95				( 15		)		80				410				( 18		)		392
Other income, net	9				15				24				20				18				38

ASU 2017-12, “Targeted Improvements to Accounting for Hedging Activities”: ASU 2017-12 changes the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge accounting results. More specifically, the guidance expands the exposures that can be hedged to align with an entity’s risk management strategies, alleviates documentation requirements, eliminates the concept of recognizing periodic hedge ineffectiveness for cash flow and net investment hedges and requires entities to present the entire change in the fair value of a hedging instrument in the same income statement line item as the earnings effect of the hedged item. Transition elections are available for all hedges that exist at the date of adoption. We early adopted ASU 2017-12 on January 1, 2018 by applying the modified retrospective approach to the accounting for existing hedging relationships. Sempra Energy recognized a cumulative-effect adjustment to increase Retained Earnings and Accumulated Other Comprehensive Loss as of January 1, 2018 by $ 3 million .

ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: ASU 2018-02 contains amendments that allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the TCJA. Under ASU 2018-02, an entity will be required to provide certain disclosures regarding stranded tax effects, including its accounting policy related to releasing the income tax effects from AOCI. The amendments in this update can be applied either as of the beginning of the period of adoption or retrospectively as of the date of enactment of the TCJA and to each period in which the effect of the TCJA is recognized. For public entities, ASU 2018-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods therein, with early adoption permitted. We plan to adopt ASU 2018-02 on a prospective basis on January 1, 2019. We are currently evaluating the effect of the standard on our financial reporting.

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The following table disaggregates our revenues from contracts with customers by major service line, market and timing of recognition and provides a reconciliation to total revenues by segment for the three months and six months ended June 30, 2018.

DISAGGREGATED REVENUES
(Dollars in millions)
	Three months ended June 30, 2018
	SDG&E				SoCalGas				Sempra South American Utilities				Sempra Mexico				Sempra Renewables				Sempra LNG & Midstream				Consolidating adjustments				Sempra Energy Consolidated
By major service line:
Utilities	$	999			$	729			$	370			$	13			$	—			$	—			$	( 16	)		$	2,095
Midstream	—				—				—				147				—				35				( 13		)		169
Renewables	—				—				—				31				12				—				1				44
Other	—				—				17				30				—				2				( 1		)		48
Revenues from contracts with customers	$	999			$	729			$	387			$	221			$	12			$	37			$	( 29	)		$	2,356
By market:
Electric	$	886			$	—			$	387			$	62			$	12			$	3			$	( 1	)		$	1,349
Gas	113				729				—				159				—				34				( 28		)		1,007
Revenues from contracts with customers	$	999			$	729			$	387			$	221			$	12			$	37			$	( 29	)		$	2,356
By timing of recognition:
Over time	$	972			$	699			$	383			$	221			$	12			$	32			$	( 25	)		$	2,294
Point in time	27				30				4				—				—				5				( 4		)		62
Revenues from contracts with customers	$	999			$	729			$	387			$	221			$	12			$	37			$	( 29	)		$	2,356
Revenues from contracts with customers	$	999			$	729			$	387			$	221			$	12			$	37			$	( 29	)		$	2,356
Utilities regulatory revenues	52				43				—				—				—				—				—				95
Other revenues	—				—				2				89				28				42				( 48		)		113
Total revenues	$	1,051			$	772			$	389			$	310			$	40			$	79			$	( 77	)		$	2,564
	Six months ended June 30, 2018
By major service line:
Utilities	$	2,130			$	1,810			$	778			$	41			$	—			$	—			$	( 35	)		$	4,724
Midstream	—				—				—				290				—				89				( 34		)		345
Renewables	—				—				—				53				23				1				—				77
Other	—				—				34				71				—				4				( 3		)		106
Revenues from contracts with customers	$	2,130			$	1,810			$	812			$	455			$	23			$	94			$	( 72	)		$	5,252
By market:
Electric	$	1,849			$	—			$	812			$	124			$	23			$	5			$	( 5	)		$	2,808
Gas	281				1,810				—				331				—				89				( 67		)		2,444
Revenues from contracts with customers	$	2,130			$	1,810			$	812			$	455			$	23			$	94			$	( 72	)		$	5,252
By timing of recognition:
Over time	$	2,076			$	1,750			$	803			$	455			$	23			$	72			$	( 62	)		$	5,117
Point in time	54				60				9				—				—				22				( 10		)		135
Revenues from contracts with customers	$	2,130			$	1,810			$	812			$	455			$	23			$	94			$	( 72	)		$	5,252
Revenues from contracts with customers	$	2,130			$	1,810			$	812			$	455			$	23			$	94			$	( 72	)		$	5,252
Utilities regulatory revenues	( 24		)		88				—				—				—				—				—				64
Other revenues	—				—				3				163				42				89				( 87		)		210
Total revenues	$	2,106			$	1,898			$	815			$	618			$	65			$	183			$	( 159	)		$	5,526

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REVENUES FROM CONTRACTS WITH CUSTOMERS

Our revenues from contracts with customers are primarily related to the generation, transmission and distribution of electricity and transmission, distribution and storage of natural gas through our regulated utilities. We also provide other midstream and renewable energy-related services. We assess our revenues on a contract-by-contract as well as a portfolio basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized.

We generally recognize revenues when performance of the promised commodity service is provided to our customers and invoice our customers for an amount that reflects the consideration we are entitled to in exchange for those services. We consider the delivery and transmission of electricity and natural gas and providing of natural gas storage services as ongoing and integrated services. Generally, electricity or natural gas services are received and consumed by the customer simultaneously. Our performance obligations related to these services are satisfied over time and represent a series of distinct services that are substantially the same and that have the same pattern of transfer to the customers. We recognize revenue based on units delivered, as the satisfaction of our performance obligations can be directly measured by the amount of electricity or natural gas delivered to the customer. In most cases, the right to consideration from the customer directly corresponds to the value transferred to the customer and we recognize revenue in the amount that we have the right to invoice. We provide further details of our revenue streams below.

The payment terms in our customer contracts vary. Typically, we have an unconditional right to customer payments, which are due after the performance obligation to the customer is satisfied. The term between invoicing and when payment is due is typically between 10 and 90 days.

We have elected the practical expedient to exclude sales and usage-based taxes from revenues. In addition, the California Utilities pay franchise fees to operate in various municipalities. The California Utilities bill these franchise fees to their customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of the California Utilities’ ability to collect from the customer, are accounted for on a gross basis and reflected in utilities revenues from contracts with customers and operating expense.

Utilities Revenues

Utilities revenues represent the majority of our consolidated revenues from contracts with customers and include:

The generation, transmission and distribution of electricity at:

▪	SDG&E

▪	Sempra South American Utilities’ Chilquinta Energía and Luz del Sur

The distribution, transportation and storage of natural gas at:

▪	SDG&E

▪	SoCalGas

▪	Sempra Mexico’s Ecogas

Utilities revenues are derived from and recognized upon the delivery of electricity or natural gas services to customers. Amounts that we bill our customers are based on tariffs set by regulators within the respective state or country. For SDG&E and SoCalGas, which follow the provisions of U.S. GAAP governing rate-regulated operations as we discuss in Note 1, amounts that we bill to customers also include adjustments for previously recognized regulatory revenues.

The California Utilities and Ecogas recognize revenues based on regulator-approved revenue requirements, which allows the utilities to recover their reasonable cost of O&M and provides the opportunity to realize their authorized rates of return on their investments. While the California Utilities’ revenues are not affected by actual sales volumes, the pattern of their revenue recognition during the year is affected by seasonality. SoCalGas recognizes annual authorized revenue for core natural gas customers using seasonal factors established in the Triennial Cost Allocation Proceeding. Accordingly, a significant portion of SoCalGas’ annual earnings are recognized in the first and fourth quarters of each year. SDG&E’s authorized revenue recognition is also impacted by seasonal factors, resulting in higher earnings in the third quarter when electric loads are typically higher than in the other three quarters of the year.

SDG&E has an arrangement to provide the California ISO with the ability to control its high voltage transmission lines for prices approved by a regulator. Revenue is recognized over time as access is provided to the California ISO.

Chilquinta Energía and Luz del Sur, our electric distribution utilities in South America, recognize revenues based on tariffs designed to provide for a pass-through to customers of transmission and energy costs, recovery of reasonable O&M based on an

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efficient model distribution company, incentives to reduce costs and make needed capital investments and a regulated rate of return on the distributor’s regulated asset base.

Factors that can affect the amount, timing and uncertainty of revenues and cash flows include weather, seasonality and timing of customer billings, which may result in unbilled revenues that can vary significantly from month to month and generally approximate one-half month’s deliveries.

The California Utilities recognize revenues from the sale of allocated California GHG emissions allowances at quarterly auctions administered by CARB. GHG allowances are delivered to CARB in advance of the quarterly auctions, and the California Utilities have the right to payment when the GHG allowances are sold at auction. GHG revenue is recognized on a point in time basis within the quarter the auction is held. The California Utilities balance costs and revenues associated with the GHG program through regulatory balancing accounts.

Midstream Revenues

Midstream revenues at Sempra Mexico and Sempra LNG & Midstream typically represent revenues from long-term, U.S. dollar-based contracts with customers for the sale of natural gas and LNG, as well as storage and transportation of natural gas. Invoiced amounts are based on the volume of natural gas delivered and contracted prices.

Sempra Mexico’s marketing operations sell natural gas to the CFE and other customers under supply agreements. Sempra Mexico recognizes the revenue from the sale of natural gas upon transfer of the natural gas via pipelines to customers at the agreed upon delivery points, and in the case of the CFE, at its thermoelectric power plants.

Through its marketing operations, Sempra LNG & Midstream has contracts to sell natural gas and LNG to Sempra Mexico that allow Sempra Mexico to satisfy its obligations under supply agreements with the CFE and other customers, and to supply Sempra Mexico’s TdM power plant. Because Sempra Mexico either immediately delivers the natural gas to its customers or consumes the benefits simultaneously (by using the gas to supply TdM), revenues from Sempra LNG & Midstream’s sale of natural gas to Sempra Mexico are generally recognized over time as delivered. Revenues from LNG sales are recognized at the point when the cargo is delivered to Sempra Mexico.

Revenues from the sale of LNG and natural gas by Sempra LNG & Midstream to Sempra Mexico are adjusted for indemnity payments and profit sharing. We consider these adjustments to be forms of variable consideration that are associated with the sale of LNG and natural gas to Sempra Mexico, and therefore, the related costs have been recorded as an offset to revenues.

We recognize storage revenue from firm capacity reservation agreements, under which we collect a fee for reserving storage capacity for customers in our underground storage facilities. Under these firm agreements, customers pay a monthly fixed reservation fee based on the storage capacity reserved rather than the actual volumes stored. For the fixed-fee component, revenue is recognized on a straight-line basis over the term of the contract. We bill customers for any capacity used in excess of the contracted capacity and such revenues are recognized in the month of occurrence. We also recognize revenue for interruptible storage services. As we discuss in Note 5, on June 25, 2018, our board of directors approved a plan to sell certain of our non-utility natural gas storage assets.

We generate pipeline transportation revenues from firm agreements, under which customers pay a fee for reserving transportation capacity. Revenue is recognized when the volumes are delivered to the customers’ agreed upon delivery point. We recognize revenues for our stand-ready obligation to provide capacity and transportation services throughout the contractual delivery period, as the benefits are received and consumed simultaneously as customers utilize pipeline capacity for the transport and receipt of natural gas and LPG. Invoiced amounts are based on a variable usage fee and a fixed capacity charge, adjusted for the Consumer Price Index, the effects of any foreign currency translation and the actual quantity of commodity transported.

Renewables Revenues

Sempra Renewables and Sempra Mexico develop, invest in and operate solar and wind facilities that have long-term PPAs to sell the electricity and the related green energy attributes they generate to customers, generally load serving entities, and also for Sempra Mexico, industrial and other customers. Load serving entities will sell electric service to their end-users and wholesale customers immediately upon receipt of our power delivery, and industrial and other customers immediately consume the electricity to run their facilities, and thus, we recognize the revenue under the PPAs as the electricity is generated. We invoice customers based on the volume of energy delivered at rates pursuant to the PPAs. As we discuss in Note 5, on June 25, 2018, our board of directors approved a plan to sell our U.S. wind and U.S. solar assets.

Sempra LNG & Midstream has a contractual agreement to provide scheduling and marketing of renewable power for Sempra Renewables. Invoiced amounts are based on a fixed fee per MWh scheduled.

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Other Revenues from Contracts with Customers

Tecnored and Tecsur, our energy services companies in South America, generate revenues from the retail sale of electric materials and providing electric construction and infrastructure services to their customers.

TdM is a natural gas-fired power plant that generates revenues from selling electricity and/or resource adequacy to the California ISO and to governmental, public utility and wholesale power marketing entities, as the power is delivered at the interconnection point.

Remaining Performance Obligations

We do not disclose information about remaining performance obligations for (a) contracts with an original expected length of one year or less, (b) revenues recognized at the amount at which we have the right to invoice for services performed, or (c) variable consideration allocated to wholly unsatisfied performance obligations.

For contracts greater than one year, at June 30, 2018, we expect to recognize revenue related to the fixed fee component of the consideration as shown below. SoCalGas did not have any such remaining performance obligations at June 30, 2018.

REMAINING PERFORMANCE OBLIGATIONS (1)
(Dollars in millions)
	Sempra Energy Consolidated			SDG&E
2018	$	276		$	1
2019	549			3
2020	543			3
2021	537			3
2022	537			3
Thereafter	3,386			55
Total revenues to be recognized	$	5,828		$	68

(1)	Excludes intercompany transactions.

Contract Balances from Revenues from Contracts with Customers

From time to time, we receive payments in advance of satisfying the performance obligations associated with customer contracts. We defer such revenues as contract liabilities and recognize them in earnings as the performance obligations are satisfied.

Activities within Sempra Energy’s contract liabilities for the six months ended June 30, 2018 are presented below. There were no contract liabilities at SDG&E or SoCalGas at June 30, 2018.

CONTRACT LIABILITIES
(Dollars in millions)
Opening balance, January 1, 2018	$	—
Adoption of ASC 606 adjustment	( 68		)
Revenue from performance obligations satisfied during reporting period	17
Payments received in advance	( 20		)
Closing balance, June 30, 2018 (1)	$	( 71	)

(1)	I ncludes $ 8 million in Other Current Liabilities, a negligible amount in Liabilities Held for Sale and $ 63 million in Deferred Credits and Other on the Sempra Energy Condensed Consolidated Balance Sheet.

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Receivables from Revenues from Contracts with Customers

The table below shows receivable balances associated with revenues from contracts with customers on our Condensed Consolidated Balance Sheets.

RECEIVABLES FROM REVENUES FROM CONTRACTS WITH CUSTOMERS
(Dollars in millions)
	June 30, 2018				January 1, 2018
Sempra Energy Consolidated:
Accounts receivable – trade, net	$	1,007			$	1,194
Accounts receivable – other, net	9				10
Due from unconsolidated affiliates – current (1)	8				8
Assets held for sale	7				—
Total	$	1,031			$	1,212
SDG&E:
Accounts receivable – trade, net	$	355			$	362
Accounts receivable – other, net	5				3
Due from unconsolidated affiliates – current (1)	3				3
Total	$	363			$	368
SoCalGas:
Accounts receivable – trade, net	$	343			$	517
Accounts receivable – other, net	4				7
Total	$	347			$	524

(1)	A mount is presented net of amounts due to unconsolidated affiliates on the Condensed Consolidated Balance Sheets , when right of offset exists.

REVENUES FROM SOURCES OTHER THAN CONTRACTS WITH CUSTOMERS

Certain of our revenues are derived from sources other than contracts with customers and are accounted for under other accounting standards outside the scope of ASC 606.

Utilities Regulatory Revenues

Alternative Revenue Programs

We recognize revenues from alternative revenue programs when the regulator-specified conditions for recognition have been met and adjust these revenues as they are recovered or refunded through future utility service.

Decoupled revenues. As discussed earlier, the regulatory framework requires the California Utilities to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. However, actual demand for electricity and natural gas will generally vary from CPUC-approved forecasted demand due to the impacts from weather volatility, energy efficiency programs, rooftop solar and other factors affecting consumption. The CPUC regulatory framework provides for the California Utilities to use a “decoupling” mechanism, which allows the California Utilities to record revenue shortfalls or excess revenues resulting from any difference between actual and forecasted demand to be recovered or refunded in authorized revenue in a subsequent period based on the nature of the account.

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. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties.

Incentive awards are included in revenues when we receive required CPUC approval of the award, the timing of which may not be consistent from year to year. We would record penalties for results below the specified benchmarks against revenues when we believe it is probable that the CPUC would assess a penalty.

Other Cost-Based Regulatory Recovery

The CPUC authorizes the California Utilities to collect revenue requirements for costs that they have been authorized to recover from customers, including the costs to purchase electricity and natural gas, costs associated with administering public purpose, demand response, and customer energy efficiency programs and other programmatic activities authorized as part of the GRC or

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separately from the GRC. Actual costs are recovered as the commodity or service is delivered, or to the extent actual amounts vary from forecasts, generally recovered or refunded within a subsequent period based on the nature of the account through a balancing account mechanism. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred.

Because SDG&E’s and SoCalGas’ cost of electricity and/or natural gas is substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected in the changes in revenues, and therefore do not impact earnings.

The CPUC authorizes balancing accounts for certain programmatic activities. Amounts billed to customers, if any, are recorded in these accounts, as well as actual O&M and applicable capital-related costs (such as depreciation, taxes and ROE). Differences between actual and authorized expenditures are tracked and may be recovered or refunded within a GRC cycle or as part of the subsequent GRC request. Examples of these types of programs include, but are not limited to, gas distribution, gas transmission, and gas storage integrity management. The CPUC may impose various review procedures before authorizing recovery or refund for programs authorized separately from the GRC, including limitations on the total cost of the program, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in disallowances of recovery from ratepayers. Examples of programs with reasonableness review procedures include, but are not limited to, PSEP.

We discuss balancing accounts and their effects further in Note 4 below and in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Revenues

Sempra LNG & Midstream has an agreement to supply LNG to Sempra Mexico’s ECA LNG terminal. Although the LNG sale and purchase agreement specifies a number of cargoes to be delivered annually, actual cargoes delivered by the supplier have traditionally been significantly lower than the maximum specified under the agreement. As a result, Sempra LNG & Midstream is contractually required to make monthly indemnity payments to Sempra Mexico for failure to deliver the contracted LNG. The revenue from the indemnity payments, along with an amount for profit sharing, allows Sempra Mexico to recover the costs of operating the ECA terminal.

Sempra Mexico generates lease revenues from operating lease agreements with PEMEX for the use of natural gas and ethane pipelines and LPG storage facilities. Certain PPAs at Sempra Renewables are also accounted for as operating leases. The operating leases have terms ranging from 15 to 25 years.

Sempra LNG & Midstream recognizes other revenues from:

▪	fees related to contractual counterparty obligations for non-delivery of LNG cargoes, as described above.

▪	sales of electricity and natural gas under short-term and long-term contracts and into the spot market and other competitive markets. Revenues include the net realized gains and losses on physical and derivative settlements and net unrealized gains and losses from the change in fair values of the derivatives.

We discuss regulatory matters in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and information about new regulatory matters below.

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REGULATORY ASSETS AND LIABILITIES

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

REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	June 30, 2018				December 31, 2017
SDG&E:
Fixed-price contracts and other derivatives	$	94			$	96
Deferred income taxes refundable in rates	( 291		)		( 281		)
Pension and other postretirement benefit plan obligations	175				153
Removal obligations	( 1,849		)		( 1,846		)
Unamortized loss on reacquired debt	8				9
Environmental costs	28				29
Sunrise Powerlink fire mitigation	119				119
Regulatory balancing accounts (1)
Commodity – electric	173				82
Gas transportation	16				22
Safety and reliability	57				48
Public purpose programs	( 77		)		( 70		)
Other balancing accounts	159				233
Other regulatory liabilities	( 118		)		( 70		)
Total SDG&E	( 1,506		)		( 1,476		)
SoCalGas:
Pension and other postretirement benefit plan obligations	545				513
Employee benefit costs	45				45
Removal obligations	( 890		)		( 924		)
Deferred income taxes refundable in rates	( 377		)		( 437		)
Unamortized loss on reacquired debt	7				8
Environmental costs	25				22
Workers’ compensation	9				12
Regulatory balancing accounts (1)
Commodity – gas, including transportation	138				151
Safety and reliability	295				266
Public purpose programs	( 360		)		( 274		)
Other balancing accounts	( 155		)		( 114		)
Other regulatory liabilities	( 105		)		( 64		)
Total SoCalGas	( 823		)		( 796		)
Sempra Mexico:
Deferred income taxes recoverable in rates	83				83
Total Sempra Energy Consolidated	$	( 2,246	)		$	( 2,189	)

(1)	At June 30, 2018 and December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $ 66 million and $ 63 million , respectively. At June 30, 2018 and December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $ 188 million and $ 118 million , respectively.

CALIFORNIA UTILITIES MATTERS

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 requested revenue requirements for 2019 of $ 2.199 billion and $ 2.989 billion , respectively, which is an increase of $ 217 million and $ 533 million over their respective 2018 revenue requirements (the 2018 revenue requirements reflect the impact of updated testimony filed in

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January 2018). 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 2019 GRC applications filed in October 2017 did not reflect the impact of the TCJA, which we discuss in “2016 General Rate Case” below, in Note 1 above and in Note 6 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 to $ 2.931 billion .

In April 2018, ORA filed testimony in SDG&E’s and SoCalGas’ 2019 GRC recommending a 2019 revenue requirement of $ 1.918 billion and $ 2.695 billion , respectively, which is a net decrease of $ 64 million and an increase of $ 239 million compared to the respective 2018 revenue requirements. ORA’s proposal reduces the three-year annual attrition percentages to 4 percent for SDG&E and a range of 4 percent to 5 percent for SoCalGas. ORA recommends addressing SDG&E’s potential ownership of OMEC in a separate proceeding. As a result, ORA’s proposed 2019 revenue requirement does not include the estimated $ 68 million associated with owning and operating the generating facility. SDG&E’s 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 on or before October 3, 2019, as we discuss in Note 1. TURN and other intervenors filed testimony in May 2018, opposing various components of our revenue requirement requests in the 2019 GRC applications.

As part of the 2019 GRC, the CPUC will review 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. The stated purpose of the interim accountability reports is to provide data and metrics for key safety and risk mitigation areas that will be considered in the 2019 GRC.

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

We expect a final 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. The framework is intended to assist in assessing safety risks and the utilities’ plans to help ensure that such risks are adequately addressed. In advance of filing the California Utilities’ 2019 GRC applications discussed above, two proceedings occurred: the Safety Model Assessment Proceeding and the RAMP. In the Safety Model Assessment Proceeding, the California Utilities demonstrated the models used to prioritize and mitigate risks in order for the CPUC to establish guidelines and standards for these models.

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.

In March 2017, the CPUC’s Safety and Enforcement Division issued its evaluation report providing generally favorable feedback on the California Utilities’ RAMP report, but recommending more detailed analysis of the risks the California Utilities presented in the report. The new GRC framework does not require the CPUC to adopt the RAMP report. However, 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 have been completed.

Senate Bill 549. In September 2017, SB 549 was signed into law, requiring 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. This requirement is effective beginning January 1, 2018. The form of this reporting is not yet defined by the CPUC, though it could be incorporated into an ongoing proceeding or report otherwise required to be submitted to the CPUC.

2016 General Rate Case

As we discuss in Notes 6 and 14 of the Notes to Consolidated Financial Statements in the Annual Report, the 2016 GRC FD issued by the CPUC in June 2016 required SDG&E and SoCalGas to each establish a two-way income tax expense memorandum

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account to track 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 tracking accounts will remain open until the CPUC decides to close the accounts, which we expect will be reviewed in the 2019 GRC proceedings.

At June 30, 2018 , the recorded regulatory liability associated with these tracked amounts totaled $ 67 million and $ 85 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.

Impacts of the TCJA. As we discuss in Note 1, in the fourth quarter of 2017, we recorded the effect of the remeasurement of our deferred income tax balances at the new federal statutory income tax rate enacted by the TCJA. The remeasurement of deferred income tax balances at SDG&E and SoCalGas resulted in excess deferred income taxes from amounts previously collected from ratepayers at the higher rate. These excess deferred income taxes have been recorded as regulatory liabilities and will be refunded to ratepayers in accordance with the IRC’s normalization provisions and as determined by the CPUC and the FERC. The income tax effects from the TCJA that we recorded in 2017 were provisional. We may adjust our provisional estimates in future reporting periods throughout 2018, and these adjustments may affect regulatory liabilities, the tracking accounts and/or earnings.

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 2018 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 2018 revenue requirement. As of June 30, 2018 , SDG&E and SoCalGas recorded regulatory liabilities of $ 34 million and $ 31 million , respectively, in anticipation of amounts that will benefit customers in future rates. SDG&E also recorded a $ 31 million regulatory liability at June 30, 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 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

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We consolidate assets acquired and liabilities assumed as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.

ACQUISITIONS

Sempra Texas Utility

After satisfying all conditions precedent, including final approval from the PUCT, on March 9, 2018, Sempra Energy completed the acquisition of an indirect, 100 -percent interest in Oncor Holdings, which owned 80.03 percent of Oncor, and other EFH assets and liabilities unrelated to Oncor, pursuant to the Merger Agreement with EFH. Oncor is a regulated electric transmission and distribution business that operates the largest transmission and distribution system in Texas. This acquisition expands our regulated earnings base, while serving as a platform for future growth in the Texas energy market and U.S. Gulf Coast region.

Under the Merger Agreement, we paid Merger Consideration of $ 9.45 billion in cash and an additional $ 31 million representing an adjustment for dividends and payments pursuant to a tax sharing agreement with Oncor and Oncor Holdings. Also on March 9, 2018, in a separate transaction, Sempra Energy, through its interest in Oncor Holdings, acquired an additional 0.22 percent of the outstanding membership interests in Oncor from OMI for approximately $ 26 million in cash, bringing Sempra Energy’s indirect ownership in Oncor to 80.25 percent . TTI, an investment vehicle indirectly owned by third parties unaffiliated with Oncor Holdings or Sempra Energy, continues to own 19.75 percent of Oncor’s outstanding membership interests.

Pursuant to the Merger Agreement, the reorganized EFH (renamed Sempra Texas Holdings Corp.) merged with an indirect subsidiary of Sempra Energy, with Sempra Texas Holdings Corp. continuing as the surviving company and an indirect, wholly owned subsidiary of Sempra Energy. Sempra Texas Holdings Corp. wholly owns EFIH (renamed Sempra Texas Intermediate Holding Company LLC), which holds our 100 -percent interest in Oncor Holdings. Sempra Texas Intermediate Holding Company LLC is included in our newly formed Sempra Texas Utility reportable segment. Other assets and liabilities unrelated to Oncor that were acquired with Sempra Texas Holdings Corp. have been subsumed into our parent organization, Parent and other.

Due to ring-fencing measures, governance mechanisms, and commitments in effect following the Merger, we do not have the power to direct the significant activities of Oncor Holdings and Oncor. Consequently, we account for our 100 -percent ownership interest in Oncor Holdings as an equity method investment. See Note 6 for additional information about our equity method investment in Oncor Holdings and related ring-fencing measures.

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The Sempra Texas Utility reportable segment is comprised as follows:

The foregoing is a simplified ownership structure that does not show all the subsidiaries of, or other equity interests owned by, these entities.

In anticipation of the Merger, in January 2018, we completed registered public offerings of our common stock (including shares offered pursuant to forward sale agreements), series A preferred stock and long-term debt, as we discuss in Notes 1 and 7 herein and in Note 18 of the Notes to Consolidated Financial Statements in the Annual Report. These offerings provided total initial net proceeds of approximately $ 7.0 billion for partial funding of the Merger Consideration, of which approximately $ 800 million was used to temporarily pay down commercial paper, pending the closing of the Merger.

On March 8, 2018, to fund a portion of the Merger Consideration, we settled approximately $ 900 million (net of underwriting discounts of $ 16 million ) of forward sales under the forward sale agreements entered into in connection with the public offering of common stock in January 2018 by delivery of 8,556,630 shares of newly issued Sempra Energy common stock, as we discuss in Note 1. We raised the remaining portion of the Merger Consideration through issuances of approximately $ 2.6 billion in commercial paper with a weighted-average maturity of 47 days and a weighted-average interest rate of 2.2 percent per annum.

The total purchase price paid is comprised of the following:

▪	$ 9,450 million of Merger Consideration;

▪	$ 31 million adjustment for dividends and payments pursuant to a tax sharing agreement with Oncor and Oncor Holdings;

▪	$ 26 million paid in a separate transaction to acquire an additional 0.22 percent of the outstanding membership interests in Oncor from OMI; and

▪	$ 59 million of transaction costs included in the basis of our investment in Oncor Holdings.

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We accounted for the Merger as an asset acquisition, as the equity method investment in Oncor Holdings represents substantially all of the fair value of the gross assets acquired. The following table sets forth the allocation of the total purchase price paid to the identifiable assets acquired and liabilities assumed:

PURCHASE PRICE ALLOCATION
(Dollars in millions)
		At March 9, 2018
Assets acquired:
Accounts receivable – other, net		$	1
Due from unconsolidated affiliates		46
Investment in Oncor Holdings		9,161
Deferred income tax assets		353
Other noncurrent assets		109
Total assets acquired		9,670
Liabilities assumed:
Other current liabilities		23
Pension and other postretirement benefit plan obligations		21
Deferred credits and other		60
Total liabilities assumed		104
Net assets acquired		$	9,566
Total purchase price paid		$	9,566

The fair value of the equity method investment in Oncor Holdings is primarily attributable to Oncor’s business. Therefore, we considered the underlying assets and liabilities of Oncor when determining the fair value of our equity method investment. As a regulated entity, Oncor’s rates are set and approved by the PUCT, and are designed to recover the cost of providing service and the opportunity to earn a reasonable return on its investments. Accordingly, Oncor applies the guidance under the provisions of U.S. GAAP governing rate-regulated operations. Under U.S. GAAP, regulation is viewed as being a characteristic (restriction) of a regulated entity’s assets and liabilities, and the impact of regulation is considered a fundamental input to measuring the fair value of Oncor’s assets and liabilities. Under this premise, we concluded that the carrying values of all assets and liabilities recoverable through rates are representative of their fair values.

Deferred income tax assets acquired have been recognized based on the facts and circumstances that existed as of the acquisition date related to the resolution of claims in EFH’s emergence from bankruptcy. Should the final resolution of these claims result in a change in deferred income tax assets allocated to us, an adjustment will be made to the purchase price allocation.

Sempra Mexico

On February 28, 2018, Sempra Mexico completed the asset acquisition of Fisterra Midstream Mexico, S. de R.L. de C.V., for a purchase price of $ 5 million . Substantially all of the fair value of the gross assets acquired is attributable to a self-supply permit that allows generators to compete directly with CFE’s retail tariffs and, thus, have access to PPAs with a competitive pricing position. IEnova will invest $ 130 million to develop, construct and operate the Don Diego Solar Complex, a 125 -MW solar facility in Sonora, Mexico. IEnova entered into a 15 -year, U.S. dollar denominated PPA with various subsidiaries of El Puerto de Liverpool, S.A.B. de C.V., for a portion of the capacity. We expect operations to commence in the second half of 2019.

Sempra Renewables

On July 10, 2017, Sempra Renewables paid $ 124 million in cash for an asset acquisition of the Great Valley Solar Project, a portfolio of four solar projects located in Fresno County, California, that were under construction. We placed three of these projects into service in the fourth quarter of 2017 and placed the fourth project into service in April 2018. The portfolio of solar projects is capable of producing up to 200 MW of solar power. The solar projects are fully contracted under four long-term PPAs, with an average contract term of 18 years .

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PENDING ACQUISITION

Sempra South American Utilities

On June 29, 2018, Chilquinta Energía entered into a sales and purchase agreement with AES Gener S.A. and its subsidiary Sociedad Eléctrica Angamos S.A. to acquire a 100 -percent interest in Compañía Transmisora del Norte Grande S.A. (CTNG). CTNG owns regulated transmission assets in the Valparaiso, Metropolitana and Antofagasta regions of Chile. The fully operating transmission assets include a 114-mile, 110 -kV single-circuit transmission line, an 82-mile, 220 -kV double-circuit transmission line, other transmission assets and substations. CTNG’s regulated revenues are based on tariffs that are set by the CNE and are reviewed by the CNE every four years. This business acquisition is consistent with our long-term growth strategy of owning and operating regulated transmission and distribution assets. The transaction is subject to regulatory approval by the Fiscalía Nacional Económica, which we expect to receive in the second half of 2018. We expect to fund the purchase price of approximately $ 220 million , subject to customary adjustments at closing, with available cash on hand at Sempra South American Utilities.

ASSETS HELD FOR SALE

We classify assets as held for sale when management approves and commits to a formal plan to actively market an asset for sale and we expect the sale to close within the next 12 months . Upon classifying an asset as held for sale, we record the asset at the lower of its carrying value or its estimated fair value reduced for selling costs.

Sempra Mexico

Termoeléctrica de Mexicali

In February 2016, management approved a plan to market and sell Sempra Mexico’s TdM, a 625 -MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, we classified TdM as held for sale, stopped depreciating the plant, and have since recorded it each period at the lower of its carrying value or fair value less costs to sell.

On June 1, 2018, management terminated its sales process for TdM due to evolving strategic considerations for projects under development at IEnova. As a result, the assets and liabilities previously classified as held for sale were reclassified as held and used, and depreciation resumed. We reclassified the property, plant and equipment at its carrying value (which approximated fair value) at the date of the subsequent decision not to sell.

Sempra Renewables and Sempra LNG & Midstream

On June 25, 2018, our board of directors approved a plan to divest certain non-utility natural gas storage assets in the southeast U.S., and all our U.S. wind and U.S. solar assets (collectively, the Assets). The plan to sell the Assets resulted from the most recent comprehensive strategic portfolio review by the board of directors and management.

Included in the plan of sale are the follo wing non-utility natural gas storage assets at our Sempra LNG & Midstream reportable segment:

▪	Mississippi Hub, an underground salt dome with 22 Bcf of working natural gas storage capacity located near Jackson, Mississippi and related compression and pipeline facilities; and

▪	our 90.9 -percent ownership interest in Bay Gas, a facility located near Mobile, Alabama and related compression and pipeline facilities, that provides underground storage ( 20 Bcf of working natural gas storage capacity) and delivery of natural gas.

Also included in the plan of sale are all wind assets and investments and solar assets and investments, including our wholly owned facilities, joint venture and tax equity investments and projects in development, comprising our Sempra Renewables reportable segment. These assets include operating wind and solar facilities with a total generating capacity of 1,335 MW and 1,262 MW, respectively.

We are actively pursuing the sale of the Assets, which we expect to be completed within the next 12 months.

As a result of our plan to sell the Assets, we recorded impairment charges totaling $ 1.5 billion ( $ 900 million after tax and noncontrolling interests) in June 2018. These charges include $ 1.3 billion ( $ 755 million after tax and noncontrolling interests) at Sempra LNG & Midstream, which is included in Impairment Losses on Sempra Energy’s Condensed Consolidated Statement of Operations, and $ 200 million ( $ 145 million after tax) at Sempra Renewables, which is included in Equity (Losses) Earnings on Sempra Energy’s Condensed Consolidated Statement of Operations. These impairment charges primarily represent an adjustment of the related assets’ carrying values to estimated fair values, less costs to sell when applicable, which we discuss further in Notes 6 and 9.

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At June 30, 2018, the carrying amounts of the major classes of assets and related liabilities classified as held for sale associated with Sempra Renewables and Sempra LNG & Midstream are summarized in the following table.

ASSETS HELD FOR SALE AT JUNE 30, 2018
(Dollars in millions)
	Sempra Renewables				Sempra LNG & Midstream
	U.S. wind and solar assets				Non-utility natural gas storage assets
Cash and cash equivalents	$	29			$	—
Restricted cash	2				—
Accounts receivable – trade, net	16				4
Accounts receivable – other, net	5				—
Inventories	5				—
Fixed-price contracts and other derivatives, current	1				—
Other current assets	4				5
Property, plant and equipment, net	1,660				140
Fixed-price contracts and other derivatives, noncurrent	2				—
Other noncurrent assets	3				1
Total assets held for sale	$	1,727			$	150
Accounts payable – trade	$	12			$	—
Current portion of long-term debt	7				—
Fixed-price contracts and other derivatives, current (1)	1				—
Other current liabilities	5				4
Long-term debt	63				—
Asset retirement obligations	57				8
Fixed-price contracts and other derivatives, noncurrent (1)	1				—
Other noncurrent liabilities	2				—
Total liabilities held for sale	$	148			$	12

(1)	Intercompany activity is eliminated on the Sempra Energy Condensed Consolidated Balance Sheet.

Sempra Energy uses the equity method to account for investments in affiliated companies over which we have the ability to exercise significant influence, but not control. Equity (losses) earnings both before and net of income tax are combined and presented as Equity (Losses) Earnings on the Condensed Consolidated Statements of Operations. See Note 1 for information regarding the pretax (loss) income used to calculate our ETR.

Our equity method investments include various domestic and foreign entities. Our domestic equity method investees are typically partnerships that are pass-through entities for income tax purposes and therefore they do not record income tax. Sempra Energy’s income tax on earnings from these equity method investees, other than Oncor Holdings as we discuss below, is included in Income Tax Expense on the Condensed Consolidated Statements of Operations.

Oncor is a partnership for U.S. federal income tax purposes and is not included in the consolidated income tax return of Sempra Energy. Rather, only our equity earnings from our investment in Oncor Holdings (a disregarded entity for tax purposes) are included in our consolidated income tax return. A tax sharing agreement with TTI, Oncor Holdings and Oncor provides for the calculation of an income tax liability substantially as if Oncor Holdings and Oncor were taxed as corporations, and requires tax payments determined on that basis. While partnerships are not subject to income taxes, in consideration of the tax sharing agreement and Oncor being subject to the provisions of U.S. GAAP governing rate-regulated operations, Oncor recognizes amounts determined under cost-based regulatory rate-setting processes (with such costs including income taxes), as if it were

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taxed as a corporation. As a result, since Oncor Holdings consolidates Oncor, we recognize equity earnings from our investment in Oncor Holdings net of its recorded income tax.

Our foreign equity method investees are corporations whose operations are taxable on a stand-alone basis in the countries in which they operate, and we recognize our equity in such income or losses net of investee income tax. We may be subject to additional taxes related to these foreign investments, such as taxes on cash dividends or other cash distributions, which are recorded in Income Tax Expense on the Condensed Consolidated Statements of Operations.

We provide additional information concerning our equity method investments in Note 5 above and in Notes 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report.

SEMPRA TEXAS UTILITY

As we discuss in Note 5, on March 9, 2018, we completed the acquisition of an indirect, 100 -percent interest in Oncor Holdings, which owns an 80.25 -percent interest in Oncor. Due to ring-fencing measures, governance mechanisms, and commitments in effect following the Merger, we do not have the power to direct the significant activities of Oncor Holdings and Oncor, which we discuss in the following paragraph. Consequently, we account for our investment in Oncor Holdings under the equity method, which comprises our Sempra Texas Utility reportable segment.

As we discuss in Note 5, reorganized EFH (renamed Sempra Texas Holdings Corp.) was merged with an indirect subsidiary of Sempra Energy and its assets and liabilities relating to non-Oncor operations have been subsumed into our parent organization. Certain existing ring-fencing measures, governance mechanisms and restrictions remain in effect following the Merger, which are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, EFH or its other subsidiaries or the owners of EFH. Sempra Energy does not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and restrictions limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions. These limitations include limited representation on the Oncor Holdings and Oncor boards of directors, as Oncor Holdings and Oncor will continue to have a majority of independent directors. Thus, Oncor Holdings and Oncor will continue to be managed independently (i.e., ring-fenced).

As such, upon consummation of the acquisition, we account for our 100 -percent ownership interest in Oncor Holdings as an equity method investment. The initial fair value of our equity method investment was $ 9,161 million , which includes $ 2,672 million of equity method goodwill related to the excess of purchase price paid over the fair value of the assets and liabilities of Oncor Holdings.

We recognized equity earnings, net of income tax, of $ 114 million and $ 129 million for the three months ended June 30, 2018 and for the period since the acquisition date through June 30, 2018 , respectively. We contributed $ 117 million in cash, commensurate with our ownership interest, to Oncor on April 23, 2018 in accordance with the terms of the Merger Agreement to enable Oncor to achieve its required capital structure calculated for regulatory purposes.

Summarized income statement information for Oncor Holdings for the three months ended June 30, 2018 and for the period since the acquisition date through June 30, 2018 are as follows:

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SUMMARIZED FINANCIAL INFORMATION – ONCOR HOLDINGS
(Dollars in millions)
	Three months ended June 30, 2018			March 9 - June 30, 2018
Operating revenues	$	1,021		$	1,257
Operating expense	( 730		)	( 915		)
Income from operations	291			342
Interest expense	( 87		)	( 109		)
Income tax expense	( 45		)	( 52		)
Net income	141			160
Noncontrolling interest held by TTI	( 28		)	( 32		)
Earnings attributable to Sempra Energy (1)	113			128

(1)	Earnings at Oncor Holdings differ from earnings at the Sempra Texas Utility segment due to basis differences in AOCI.

SEMPRA SOUTH AMERICAN UTILITIES

In the first quarter of 2017, Sempra South American Utilities recorded the equitization of its $ 19 million note receivable due from Eletrans, resulting in an increase in its investment in this unconsolidated joint venture.

SEMPRA RENEWABLES

As we discuss in Note 5, on June 25, 2018, our board of directors approved a plan to sell all wind assets and investments and solar assets and investments, including our wholly owned facilities, joint venture and tax equity investments and projects in development, comprising our Sempra Renewables reportable segment. Because of our expectation of a shorter holding period as a result of this plan of sale, we evaluated the recoverability of the carrying amounts of our wind and solar equity method investments and concluded there is an other-than-temporary impairment on certain of our wind equity method investments totaling $ 200 million , which is included in Equity (Losses) Earnings on Sempra Energy’s Condensed Consolidated Statement of Operations for the three months and six months ended June 30, 2018. Our wind and solar investments totaling $ 612 million at June 30, 2018, which are also included in the plan of sale, continue to be classified as Other Investments on Sempra Energy’s Condensed Consolidated Balance Sheet, in conformity with U.S. GAAP. We discuss non-recurring fair value measures in Note 9.

SEMPRA MEXICO

Sempra Mexico invested cash of $ 25 million and $ 72 million in its unconsolidated joint ventures in the six months ended June 30, 2018 and 2017, respectively.

SEMPRA LNG & MIDSTREAM

Sempra LNG & Midstream capitalized $ 22 million and $ 24 million of interest in the six months ended June 30, 2018 and 2017 , respectively, related to its investment in Cameron LNG JV, which has not commenced planned principal operations. In the six months ended June 30, 2018 and 2017, Sempra LNG & Midstream invested cash of $ 102 million and $ 1 million , respectively, in this unconsolidated joint venture.

GUARANTEES

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LINES OF CREDIT

On January 17, 2018, pursuant to the terms of the Sempra Energy and Sempra Global credit facilities, the amounts available under the lines of credit were increased by $ 250 million , from $ 1.0 billion to $ 1.25 billion , for Sempra Energy and by $ 850 million , from $ 2.335 billion to $ 3.185 billion , for Sempra Global. At June 30, 2018 , Sempra Energy Consolidated had an aggregate of approximately $ 5.4 billion in three primary committed lines of credit for Sempra Energy, Sempra Global and the California Utilities to provide liquidity and to support commercial paper. The principal terms of these committed lines of credit, which expire in October 2020, are described below and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report. Available unused credit on these lines at June 30, 2018 was approximately $ 2.1 billion . Our foreign operations have additional general purpose credit facilities aggregating $ 1.8 billion , with $ 1.4 billion available unused credit at June 30, 2018 .

PRIMARY U.S. COMMITTED LINES OF CREDIT
(Dollars in millions)
			June 30, 2018
			Total facility				Commercial paper outstanding (1)				Adjustment for combined limit				Available unused credit
Sempra Energy (2)			$	1,250			$	—			$	—			$	1,250
Sempra Global (3)			3,185				( 2,917		)		—				268
California Utilities (4) :
SDG&E			750				( 81		)		( 76		)		593
SoCalGas			750				( 326		)		—				424
Less: combined limit of $1 billion for both utilities			( 500		)		—				76				( 424		)
			1,000				( 407		)		—				593
Total			$	5,435			$	( 3,324	)		$	—			$	2,111

(1)	Because the commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit.

(2)	The facility also provides for issuance of up to $ 400 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at June 30, 2018.

(3)	Sempra Energy guarantees Sempra Global’s obligations under the credit facility.

(4)	The facility also provides for the issuance of letters of credit on behalf of each utility, subject to a combined letter of credit commitment of $ 250 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at June 30, 2018.

Sempra Energy, SDG&E and SoCalGas must maintain a ratio of indebtedness to total capitalization (as defined in each of the applicable credit facilities) of no more than 65 percent at the end of each quarter. Each entity is in compliance with this and all other financial covenants under its respective credit facility at June 30, 2018 .

CREDIT FACILITIES IN SOUTH AMERICA AND MEXICO
(U.S. dollar-equivalent in millions)
				June 30, 2018
		Denominated in		Total facility				Amount outstanding				Available unused credit
Sempra South American Utilities (1) :
	Peru (2)	Peruvian sol		$	465			$	( 117	)	(3)	$	348
	Chile	Chilean peso		115				—				115
Sempra Mexico:
	IEnova (4)	U.S. dollar		1,170				( 272		)		898
Total				$	1,750			$	( 389	)		$	1,361

(1)	The credit facilities were entered into to finance working capital and for general corporate purposes and expire between 2018 and 2021.

(2)	The Peruvian facilities require a debt to equity ratio of no more than 170 percent , with which we were in compliance at June 30, 2018.

(3)	Includes bank guarantees of $ 21 million .

(4)	Five -year revolver expiring in August 2020 with a syndicate of eight lenders.

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Outside of these domestic and foreign committed credit facilities, we have bilateral unsecured letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements. At June 30, 2018, we had approximately $ 638 million in letters of credit outstanding under these agreements.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on total short-term debt at Sempra Energy Consolidated were 2.60 percent and 1.92 percent at June 30, 2018 and December 31, 2017 , respectively. The weighted average interest rates on total short-term debt at SDG&E were 2.01 percent and 1.65 percent at June 30, 2018 and December 31, 2017 , respectively. The weighted average interest rates on total short-term debt at SoCalGas were 2.03 percent and 1.64 percent at June 30, 2018 and December 31, 2017 , respectively.

LONG-TERM DEBT

Sempra Energy

On January 12, 2018, we issued the following debt securities and received net proceeds of $ 4.9 billion (after deducting discounts and debt issuance costs of $ 68 million ):

NOTES ISSUED IN LONG-TERM DEBT OFFERING
(Dollars in millions)
Title of each class of securities	Aggregate principal amount				Maturity		Interest payments
Floating Rate (1) Notes due 2019	$	500			July 15, 2019		Quarterly
Floating Rate (2) Notes due 2021	700				January 15, 2021		Quarterly
2.400% Senior Notes due 2020	500				February 1, 2020		Semi-annually
2.900% Senior Notes due 2023	500				February 1, 2023		Semi-annually
3.400% Senior Notes due 2028	1,000				February 1, 2028		Semi-annually
3.800% Senior Notes due 2038	1,000				February 1, 2038		Semi-annually
4.000% Senior Notes due 2048	800				February 1, 2048		Semi-annually

(1)	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 25 bps.

(2)	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 50 bps.

The Floating Rate Notes due 2019 are not subject to redemption at our option. At our option, we may redeem some or all of the Floating Rate Notes due 2021 at any time on or after January 14, 2019 at the applicable redemption price per the terms of the notes. At our option, we may redeem some or all of the fixed rate notes of each series at any time at the applicable redemption price for such series of fixed rate notes.

We used a substantial portion of the net proceeds from this offering to finance a portion of the Merger Consideration and associated transaction costs, as we discuss in Note 5, and approximately $ 800 million to pay down commercial paper.

Ranking

The notes are unsecured and unsubordinated obligations, ranking on a parity in right of payment with all of our other unsecured and unsubordinated indebtedness and guarantees. The notes rank senior to all our existing and future indebtedness, if any, that is subordinated to the notes. The notes are effectively subordinated to any secured indebtedness we have or may incur (to the extent of the collateral securing that indebtedness) and are also effectively subordinated to all indebtedness and other liabilities of our subsidiaries.

SDG&E

On May 17, 2018, SDG&E completed its public offer and sale of $ 400 million of 4.15 -percent, first mortgage bonds maturing in 2048. SDG&E used the proceeds from the offering to repay outstanding commercial paper.

SoCalGas

On May 15, 2018, SoCalGas completed its public offer and sale of $ 400 million of 4.125 -percent, first mortgage bonds maturing in 2048. SoCalGas used the proceeds from the offering to repay outstanding commercial paper.

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Sempra South American Utilities

In June 2018, Luz del Sur drew bank loans totaling $ 22 million at 4.32 -percent interest, maturing in 2021.

Sempra Renewables

At June 30, 2018, $ 63 million of long-term debt and $ 7 million of current portion of long-term debt at Sempra Renewables is classified as Liabilities Held for Sale on the Sempra Energy Condensed Consolidated Balance Sheet, as we discuss in Note 5.

INTEREST RATE SWAPS

We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk, benchmark interest rate risk and foreign exchange rate exposures. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that our asset values may fall or our liabilities increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below.

In certain cases, we apply the normal purchase or sale exception to derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.

In all other cases, we record derivatives at fair value on the Condensed Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in OCI (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the principal settlements of cross-currency swaps that hedge exposure related to Mexican peso-denominated debt as financing activities, and settlements of other derivative instruments as operating activities, on the Condensed Consolidated Statements of Cash Flows.

HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that the future cash flows of a given revenue or expense item may vary, and other criteria.

We may designate an interest rate derivative as a fair value hedging instrument if it effectively converts our own debt from a fixed interest rate to a variable rate. The combination of the derivative and debt instrument results in fixing that portion of the fair value of the debt that is related to benchmark interest rates. Designating fair value hedges is dependent on the instrument being used, the effectiveness of the instrument in offsetting changes in the fair value of our debt instruments, and other criteria.

ENERGY DERIVATIVES

Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows:

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▪

The California Utilities use natural gas and electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risks, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Condensed Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.

▪

SDG&E is allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations.

▪

Sempra Mexico, Sempra LNG & Midstream, and Sempra Renewables may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: LNG, natural gas transportation and storage, and power generation. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico may also use natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its distribution operations. These derivatives, which are recorded as commodity costs that are offset by regulatory account balances and recovered in rates, are recognized in Cost of Natural Gas on the Condensed Consolidated Statements of Operations.

▪	From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel and GHG allowances.

We summarize net energy derivative volumes at June 30, 2018 and December 31, 2017 as follows:

NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
Commodity	Unit of measure		June 30, 2018			December 31, 2017
California Utilities:
SDG&E:
Natural gas	MMBtu		41			39
Electricity	MWh		3			3
Congestion revenue rights	MWh		53			59
Energy-Related Businesses:
Sempra LNG & Midstream – natural gas	MMBtu		13			3
Sempra Mexico – natural gas	MMBtu		11			4

In addition to the amounts noted above, we frequently use commodity derivatives to manage risks associated with the physical locations of contractual obligations and assets, such as natural gas purchases and sales.

INTEREST RATE DERIVATIVES

We are exposed to interest rates primarily as a result of our current and expected use of financing. The California Utilities, as well as Sempra Energy and its other subsidiaries and joint ventures, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We may utilize interest rate swaps typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings. Separately, Otay Mesa VIE has entered into interest rate swap agreements, designated as cash flow hedges, to moderate its exposure to interest rate changes.

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At June 30, 2018 and December 31, 2017 , the net notional amounts of our interest rate derivatives, excluding joint ventures, were:

INTEREST RATE DERIVATIVES
(Dollars in millions)
	June 30, 2018						December 31, 2017
	Notional debt				Maturities		Notional debt				Maturities
Sempra Energy Consolidated:
Cash flow hedges (1)	$	827			2018-2032		$	861			2018-2032
SDG&E:
Cash flow hedge (1)	290				2018-2019		295				2018-2019

(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

FOREIGN CURRENCY DERIVATIVES

We utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and joint ventures. These cash flow hedges exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates. From time to time, Sempra Mexico and its joint ventures may use other foreign currency derivatives to hedge exposures related to cash flows associated with revenues from contracts denominated in Mexican pesos that are indexed to the U.S. dollar.

We are also exposed to exchange rate movements at our Mexican subsidiaries and joint ventures, which have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. We utilize foreign currency derivatives as a means to manage the risk of exposure to significant fluctuations in our income tax expense and equity earnings from these impacts, however we generally do not hedge our deferred income tax assets and liabilities or inflation.

In addition, Sempra South American Utilities and its joint ventures use foreign currency derivatives to manage foreign currency rate risk. We discuss these derivatives at Chilquinta Energía’s Eletrans joint venture investment in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

At June 30, 2018 and December 31, 2017 , the net notional amounts of our foreign currency derivatives, excluding joint ventures, were:

FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
	June 30, 2018						December 31, 2017
	Notional amount				Maturities		Notional amount				Maturities
Sempra Energy Consolidated:
Cross-currency swaps	$	306			2018-2023		$	408			2018-2023
Other foreign currency derivatives	1,055				2018-2019		345				2018-2019

FINANCIAL STATEMENT PRESENTATION

The Condensed Consolidated Balance Sheets reflect the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Condensed Consolidated Balance Sheets at June 30, 2018 and December 31, 2017 , including the amount of cash collateral receivables that were not offset, as the cash collateral was in excess of liability positions.

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DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	June 30, 2018
	Current assets: Fixed-price contracts and other derivatives (1)				Other assets: Sundry				Current liabilities: Fixed-price contracts and other derivatives (2)				Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments (3)(4)	$	7			$	2			$	( 8	)		$	( 138	)
Derivatives not designated as hedging instruments:
Foreign exchange instruments	9				—				—				—
Commodity contracts not subject to rate recovery	44				13				( 44		)		( 11		)
Associated offsetting commodity contracts	( 37		)		( 10		)		37				10
Commodity contracts subject to rate recovery	16				99				( 63		)		( 109		)
Associated offsetting commodity contracts	( 2		)		( 1		)		2				1
Associated offsetting cash collateral	—				—				9				4
Net amounts presented on the balance sheet	37				103				( 67		)		( 243		)
Additional cash collateral for commodity contracts not subject to rate recovery	14				—				—				—
Additional cash collateral for commodity contracts subject to rate recovery	19				—				—				—
Total (5)	$	70			$	103			$	( 67	)		$	( 243	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments (3)	$	—			$	—			$	( 7	)		$	—
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	14				98				( 60		)		( 109		)
Associated offsetting commodity contracts	( 2		)		( 1		)		2				1
Associated offsetting cash collateral	—				—				9				4
Net amounts presented on the balance sheet	12				97				( 56		)		( 104		)
Additional cash collateral for commodity contracts subject to rate recovery	18				—				—				—
Total (5)	$	30			$	97			$	( 56	)		$	( 104	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	2			$	1			$	( 3	)		$	—
Net amounts presented on the balance sheet	2				1				( 3		)		—
Additional cash collateral for commodity contracts subject to rate recovery	1				—				—				—
Total	$	3			$	1			$	( 3	)		$	—

(1)	Included in Current Assets: Other for SoCalGas.

(2)	Included in Current Liabilities: Other for SoCalGas.

(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

(4)	Includes $ 1 million of current assets and $ 2 million of noncurrent assets in Assets Held for Sale, as we discuss in Note 5.

(5)	Normal purchase contracts previously measured at fair value are excluded.

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DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2017
	Current assets: Fixed-price contracts and other derivatives (1)				Other assets: Sundry				Current liabilities: Fixed-price contracts and other derivatives (2)				Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments (3)	$	5			$	2			$	( 51	)		$	( 165	)
Derivatives not designated as hedging instruments:
Foreign exchange instruments	—				—				( 1		)		—
Commodity contracts not subject to rate recovery	81				8				( 72		)		( 6		)
Associated offsetting commodity contracts	( 67		)		( 5		)		67				5
Commodity contracts subject to rate recovery	28				101				( 65		)		( 120		)
Associated offsetting commodity contracts	—				( 1		)		—				1
Associated offsetting cash collateral	—				—				19				4
Net amounts presented on the balance sheet	47				105				( 103		)		( 281		)
Additional cash collateral for commodity contracts not subject to rate recovery	2				—				—				—
Additional cash collateral for commodity contracts subject to rate recovery	17				—				—				—
Total (4)	$	66			$	105			$	( 103	)		$	( 281	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments (3)	$	—			$	—			$	( 10	)		$	( 3	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	26				101				( 63		)		( 120		)
Associated offsetting commodity contracts	—				( 1		)		—				1
Associated offsetting cash collateral	—				—				19				4
Net amounts presented on the balance sheet	26				100				( 54		)		( 118		)
Additional cash collateral for commodity contracts subject to rate recovery	16				—				—				—
Total (4)	$	42			$	100			$	( 54	)		$	( 118	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	2			$	—			$	( 2	)		$	—
Net amounts presented on the balance sheet	2				—				( 2		)		—
Additional cash collateral for commodity contracts subject to rate recovery	1				—				—				—
Total	$	3			$	—			$	( 2	)		$	—

⁽¹⁾ Included in Current Assets: Other for SoCalGas.

⁽²⁾ Included in Current Liabilities: Other for SoCalGas.

⁽³⁾ Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

⁽⁴⁾ Normal purchase contracts previously measured at fair value are excluded.

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The table below includes the effects of derivative instruments designated as cash flow hedges on the Condensed Consolidated Statements of Operations and in OCI and AOCI for the three months and six months ended June 30 :

CASH FLOW HEDGE IMPACTS
(Dollars in millions)
	Pretax (loss) gain recognized in OCI										Pretax (loss) gain reclassified from AOCI into earnings
	Three months ended June 30,										Three months ended June 30,
	2018				2017				Location		2018				2017
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments (1)	$	( 13	)		$	( 8	)		Interest Expense (1)		$	( 1	)		$	1
									Other (Expense) Income, Net		( 18		)		—
Interest rate and foreign exchange instruments	33				( 41		)		Equity (Losses) Earnings		( 1		)		( 5		)
Foreign exchange instruments	5				( 1		)		Revenues: Energy- Related Businesses		1				1
Total	$	25			$	( 50	)				$	( 19	)		$	( 3	)
SDG&E:
Interest rate instruments (1)	$	—			$	( 2	)		Interest Expense (1)		$	( 1	)		$	( 3	)
	Six months ended June 30,										Six months ended June 30,
	2018				2017				Location		2018				2017
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments (1)	$	41			$	8			Interest Expense (1)		$	1			$	4
Interest rate and foreign exchange instruments	103				( 55		)		Equity (Losses) Earnings		( 5		)		( 9		)
Foreign exchange instruments	( 2		)		( 10		)		Revenues: Energy- Related Businesses		1				( 1		)
Commodity contracts not subject to rate recovery	—				3				Revenues: Energy- Related Businesses		—				( 9		)
Total	$	142			$	( 54	)				$	( 3	)		$	( 15	)
SDG&E:
Interest rate instruments (1)	$	1			$	( 2	)		Interest Expense (1)		$	( 4	)		$	( 6	)

(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.

For Sempra Energy Consolidated, we expect that net gains of $ 9 million , which are net of income tax, that are currently recorded in AOCI (including $ 6 million of losses in NCI related to Otay Mesa VIE at SDG&E) related to cash flow hedges will be reclassified into earnings during the next 12 months as the hedged items affect earnings. SoCalGas expects that $ 1 million of losses, net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next 12 months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts mature.

For all forecasted transactions, the maximum remaining term over which we are hedging exposure to the variability of cash flows at June 30, 2018 is approximately 14 years and 1 year for Sempra Energy Consolidated and SDG&E, respectively. The maximum remaining term for which we are hedging exposure to the variability of cash flows at our equity method investees is 17 years.

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The effects of derivative instruments not designated as hedging instruments on the Condensed Consolidated Statements of Operations for the three months and six months ended June 30 were:

UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Three months ended June 30,								Six months ended June 30,
	Location	2018				2017				2018			2017
Sempra Energy Consolidated:
Foreign exchange instruments	Other (Expense) Income, Net	$	( 37	)		$	32			$	7		$	97
Commodity contracts not subject to rate recovery	Revenues: Energy-Related Businesses	—				16				( 9		)	30
Commodity contracts not subject to rate recovery	Operation and Maintenance	—				—				—			( 1		)
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	6				6				8			( 23		)
Commodity contracts subject to rate recovery	Cost of Natural Gas	—				—				1			—
Total		$	( 31	)		$	54			$	7		$	103
SDG&E:
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	$	6			$	6			$	8		$	( 23	)
SoCalGas:
Commodity contracts not subject to rate recovery	Operation and Maintenance	$	—			$	—			$	—		$	( 1	)
Commodity contracts subject to rate recovery	Cost of Natural Gas	—				—				1			—
Total		$	—			$	—			$	1		$	( 1	)

CONTINGENT FEATURES

For Sempra Energy Consolidated and SDG&E, certain of our derivative instruments contain credit limits which vary depending on our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization.

For Sempra Energy Consolidated, the total fair value of this group of derivative instruments in a net liability position at June 30, 2018 and December 31, 2017 is $ 4 million and $ 6 million , respectively. At June 30, 2018 , if the credit ratings of Sempra Energy were reduced below investment grade, $ 5 million of additional assets could be required to be posted as collateral for these derivative contracts.

For SDG&E, the total fair value of this group of derivative instruments in a net liability position is $ 1 million at December 31, 2017 .

We discuss the valuation techniques and inputs we use to measure fair value and the definition of the three levels of the fair value hierarchy in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

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RECURRING FAIR VALUE MEASURES

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at June 30, 2018 and December 31, 2017 . We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities, and their placement within the fair value hierarchy. We have not changed the valuation techniques or types of inputs we use to measure recurring fair value during the six months ended June 30, 2018 .

The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 8 under “Financial Statement Presentation.”

The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).

Our financial assets and liabilities that were accounted for at fair value on a recurring basis at June 30, 2018 and December 31, 2017 in the tables below include, other than a $ 9 million investment at June 30, 2018 measured at net asset value, the following:

▪

Nuclear decommissioning trusts reflect the assets of SDG&E’s NDT, excluding cash balances. A third party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).

▪

For commodity contracts, interest rate derivatives and foreign exchange instruments, we primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below in “Level 3 Information.”

▪	Rabbi Trust investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1). These investments in marketable securities were negligible at both June 30, 2018 and December 31, 2017 .

There were no transfers into or out of Level 1, Level 2 or Level 3 for Sempra Energy Consolidated, SDG&E or SoCalGas during the periods presented.

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RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Fair value at June 30, 2018
	Level 1				Level 2				Level 3				Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	455			$	4			$	—			$	459
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	47				10				—				57
Municipal bonds	—				263				—				263
Other securities	—				229				—				229
Total debt securities	47				502				—				549
Total nuclear decommissioning trusts (1)	502				506				—				1,008
Interest rate and foreign exchange instruments (2)	—				18				—				18
Commodity contracts not subject to rate recovery	1				9				—				10
Effect of netting and allocation of collateral (3)	14				—				—				14
Commodity contracts subject to rate recovery	—				3				109				112
Effect of netting and allocation of collateral (3)	13				—				6				19
Total	$	530			$	536			$	115			$	1,181
Liabilities:
Interest rate and foreign exchange instruments	$	—			$	146			$	—			$	146
Commodity contracts not subject to rate recovery	1				7				—				8
Commodity contracts subject to rate recovery	13				16				140				169
Effect of netting and allocation of collateral (3)	( 13		)		—				—				( 13		)
Total	$	1			$	169			$	140			$	310
	Fair value at December 31, 2017
	Level 1				Level 2				Level 3				Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	491			$	5			$	—			$	496
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	45				9				—				54
Municipal bonds	—				250				—				250
Other securities	—				217				—				217
Total debt securities	45				476				—				521
Total nuclear decommissioning trusts (1)	536				481				—				1,017
Interest rate and foreign exchange instruments	—				7				—				7
Commodity contracts not subject to rate recovery	5				12				—				17
Effect of netting and allocation of collateral (3)	2				—				—				2
Commodity contracts subject to rate recovery	—				2				126				128
Effect of netting and allocation of collateral (3)	12				—				5				17
Total	$	555			$	502			$	131			$	1,188
Liabilities:
Interest rate and foreign exchange instruments	$	—			$	217			$	—			$	217
Commodity contracts not subject to rate recovery	—				6				—				6
Commodity contracts subject to rate recovery	23				7				154				184
Effect of netting and allocation of collateral (3)	( 23		)		—				—				( 23		)
Total	$	—			$	230			$	154			$	384

(1)	Excludes cash balances and cash equivalents.

(2)	Includes $ 3 million of interest rate instruments classified as Assets Held for Sale, as we discuss in Note 5.

(3)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

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RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
	Fair value at June 30, 2018
	Level 1				Level 2				Level 3				Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	455			$	4			$	—			$	459
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	47				10				—				57
Municipal bonds	—				263				—				263
Other securities	—				229				—				229
Total debt securities	47				502				—				549
Total nuclear decommissioning trusts (1)	502				506				—				1,008
Commodity contracts subject to rate recovery	—				—				109				109
Effect of netting and allocation of collateral (2)	12				—				6				18
Total	$	514			$	506			$	115			$	1,135
Liabilities:
Interest rate instruments	$	—			$	7			$	—			$	7
Commodity contracts subject to rate recovery	13				13				140				166
Effect of netting and allocation of collateral (2)	( 13		)		—				—				( 13		)
Total	$	—			$	20			$	140			$	160
	Fair value at December 31, 2017
	Level 1				Level 2				Level 3				Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	491			$	5			$	—			$	496
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	45				9				—				54
Municipal bonds	—				250				—				250
Other securities	—				217				—				217
Total debt securities	45				476				—				521
Total nuclear decommissioning trusts (1)	536				481				—				1,017
Commodity contracts subject to rate recovery	—				—				126				126
Effect of netting and allocation of collateral (2)	11				—				5				16
Total	$	547			$	481			$	131			$	1,159
Liabilities:
Interest rate instruments	$	—			$	13			$	—			$	13
Commodity contracts subject to rate recovery	23				5				154				182
Effect of netting and allocation of collateral (2)	( 23		)		—				—				( 23		)
Total	$	—			$	18			$	154			$	172

(1)	Excludes cash balances and cash equivalents.

(2)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

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RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
	Fair value at June 30, 2018
	Level 1				Level 2				Level 3				Total
Assets:
Commodity contracts subject to rate recovery	$	—			$	3			$	—			$	3
Effect of netting and allocation of collateral (1)	1				—				—				1
Total	$	1			$	3			$	—			$	4
Liabilities:
Commodity contracts subject to rate recovery	$	—			$	3			$	—			$	3
Total	$	—			$	3			$	—			$	3
	Fair value at December 31, 2017
	Level 1				Level 2				Level 3				Total
Assets:
Commodity contracts subject to rate recovery	$	—			$	2			$	—			$	2
Effect of netting and allocation of collateral (1)	1				—				—				1
Total	$	1			$	2			$	—			$	3
Liabilities:
Commodity contracts subject to rate recovery	$	—			$	2			$	—			$	2
Total	$	—			$	2			$	—			$	2

(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

Level 3 Information

The following table sets forth reconciliations of changes in the fair value of CRRs and long-term, fixed-price electricity positions classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E:

LEVEL 3 RECONCILIATIONS (1)
(Dollars in millions)
	Three months ended June 30,
	2018				2017
Balance at April 1	$	( 40	)		$	( 96	)
Realized and unrealized gains (losses)	11				( 3		)
Settlements	( 2		)		9
Balance at June 30	$	( 31	)		$	( 90	)
Change in unrealized gains (losses) relating to instruments still held at June 30	$	3			$	2
	Six months ended June 30,
	2018				2017
Balance at January 1	$	( 28	)		$	( 74	)
Realized and unrealized gains (losses)	15				( 16		)
Allocated transmission instruments	3				—
Settlements	( 21		)		—
Balance at June 30	$	( 31	)		$	( 90	)
Change in unrealized gains (losses) relating to instruments still held at June 30	$	( 4	)		$	( 14	)

⁽¹⁾ Excludes the effect of contractual ability to settle contracts under master netting agreements.

SDG&E’s Energy and Fuel Procurement department, in conjunction with SDG&E’s finance group, is responsible for determining the appropriate fair value methodologies used to value and classify CRRs and long-term, fixed-price electricity positions on an ongoing basis. Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments.

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CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California ISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and are the basis for valuing CRRs settling in the following year. For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, are in the following ranges for the years indicated below:

CONGESTION REVENUE RIGHTS AUCTION PRICE INPUTS
Settlement year		Price per MWh
2018		$	( 7.25	)	to	$	11.99
2017		( 11.88		)	to	6.93

The impact associated with discounting is negligible. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 8.

Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. These inputs range from $ 19.75 per MWh to $ 54.25 per MWh at June 30, 2018 , and $ 21.35 per MWh to $ 46.35 per MWh at June 30, 2017. A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively. We summarize long-term, fixed-price electricity position volumes in Note 8.

Realized gains and losses associated with CRRs and long-term electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities and therefore do not affect earnings.

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, accounts and notes receivable, short-term amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Condensed Consolidated Balance Sheets at June 30, 2018 and December 31, 2017 :

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FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	June 30, 2018
	Carrying amount				Fair value
					Level 1				Level 2				Level 3				Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates (1)	$	626			$	—			$	600			$	41			$	641
Long-term amounts due to unconsolidated affiliates (2)	35				—				32				—				32
Total long-term debt (3)(4)(5)	21,791				731				20,605				436				21,772
SDG&E:
Total long-term debt (5)(6)	$	5,245			$	—			$	5,194			$	290			$	5,484
SoCalGas:
Total long-term debt (7)	$	2,909			$	—			$	2,946			$	—			$	2,946
	December 31, 2017
	Carrying amount				Fair value
					Level 1				Level 2				Level 3				Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates (1)	$	604			$	—			$	528			$	96			$	624
Long-term amounts due to unconsolidated affiliates (2)	35				—				32				—				32
Total long-term debt (4)(5)	17,138				817				17,134				458				18,409
SDG&E:
Total long-term debt (5)(6)	$	4,868			$	—			$	5,073			$	295			$	5,368
SoCalGas:
Total long-term debt (7)	$	3,009			$	—			$	3,192			$	—			$	3,192

(1)	Excluding accumulated interest outstanding of $ 51 million and $ 29 million at June 30, 2018 and December 31, 2017 , respectively, and excluding foreign currency translation of $ 43 million and $ 35 million on a Mexican peso-denominated loan at June 30, 2018 and December 31, 2017 , respectively.

(2)	Excluding accumulated interest of $ 1 million outstanding at June 30, 2018 and negligible interest outstanding at December 31, 2017 .

(3)	Includes $ 70 million of long-term debt classified as Liabilities Held for Sale, as we discuss in Notes 5 and 7.

(4)

Before reductions for unamortized discount (net of premium) and debt issuance costs of $ 210 million and $ 143 million at June 30, 2018 and December 31, 2017 , respectively, and excluding build-to-suit and capital lease obligations of $ 875 million and $ 877 million at June 30, 2018 and December 31, 2017 , respectively. We discuss our long-term debt in Note 7 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.

(5)	Level 3 instruments include $ 290 million and $ 295 million at June 30, 2018 and December 31, 2017 , respectively, related to Otay Mesa VIE.

(6)	Before reductions for unamortized discount and debt issuance costs of $ 49 million and $ 45 million at June 30, 2018 and December 31, 2017 , respectively, and excluding capital lease obligations of $ 727 million and $ 732 million at June 30, 2018 and December 31, 2017 , respectively.

(7)	Before reductions for unamortized discount and debt issuance costs of $ 27 million and $ 24 million at June 30, 2018 and December 31, 2017 , respectively, and excluding capital lease obligations of $ 5 million and $ 1 million at June 30, 2018 and December 31, 2017 , respectively.

Sempra Renewables

U.S. wind investments. As we discuss in Notes 5 and 6, on June 25, 2018, our board of directors approved a plan to sell all our wind and solar equity method investments at Sempra Renewables. Because of our expectation of a shorter holding period as a result of this plan of sale, we evaluated the recoverability of the carrying amounts of each of these investments and concluded there is an other-than-temporary impairment on certain of our wind equity method investments totaling $ 200 million ( $ 145 million after tax), which we recorded in Equity (Losses) Earnings on Sempra Energy’s Condensed Consolidated Statement of Operations for the three months and six months ended June 30, 2018. We measured the estimated fair value of $ 145 million at June 25, 2018 using a discounted cash flow model including significant unobservable inputs, adjusted for our applicable ownership percentages, which is a Level 3 measurement in the fair value hierarchy. The key inputs to the methodology were contracted and merchant pricing, and the discount rate .

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Sempra LNG & Midstream

Non-utility natural gas storage assets. As we discuss in Note 5, on June 25, 2018, our board of directors approved a plan to sell Mississippi Hub and our 90.9 -percent ownership interest in Bay Gas (the non-utility natural gas storage assets). We also own other U.S. midstream assets that are not included in the plan of sale and primarily include our 75.4 -percent interest in LA Storage, a salt cavern development project in Cameron Parish, Louisiana. The LA Storage project also includes an existing 23.3-mile pipeline header system that is not currently contracted.

Because of the plan of sale, we considered a market participant’s view of the total value of the non-utility natural gas storage assets and determined that their fair value, less costs to sell, may be less than their carrying value. Additionally, our inability to secure customer contracts that would support further investment in LA Storage has led us to assess and conclude that the full carrying value of these other U.S. midstream assets may not be recoverable. As a result, we recorded an impairment of $ 1.3 billion ( $ 755 million after tax and noncontrolling interest) in Impairment Losses on Sempra Energy’s Condensed Consolidated Statement of Operations for the three months and six months ended June 30, 2018.

We measured the estimated fair value of $ 190 million at June 25, 2018 using a discounted cash flow approach. This approach included unobservable inputs, resulting in a Level 3 measurement in the fair value hierarchy. We considered a market participant’s view of the values of the non-utility natural gas storage assets based on an estimation of future net cash flows. To estimate future net cash flows, we considered the non-utility natural gas storage assets’ prospects for generating revenues and cash flows beyond their existing contracted capacity and tenors, including natural gas price volatility and seasonality factors, as well as discount rates commensurate with the risks inherent in the cash flows.

The following table summarizes significant inputs impacting our non-recurring fair value measures:

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
		Estimated fair value (in millions)					Valuation technique		Fair value hierarchy		% of fair value measurement		Inputs used to develop measurement		Range of inputs
Certain of our U.S. wind equity method investments	$	145			(1)		Discounted cash flows		Level 3		100 %		Contracted and observable merchant prices per MWh		$29 - $92	(2)
													Discount rate		8% - 10%	(3)
Non-utility natural gas storage assets	$	190			(4)		Discounted cash flows		Level 3		100 %		Storage rates per Dth/month		$0.06 - $0.22	(2)
													Discount rate		10%	(3)

(1)	At measurement date of June 25, 2018. At June 30, 2018, these U.S. wind equity method investments have a carrying value of $ 141 million , reflecting subsequent business activity.

(2)	Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.

(3)	An increase in the discount rate would result in a decrease in fair value.

(4)

At measurement date of June 25, 2018. At June 30, 2018, Mississippi Hub and Bay Gas are classified as held for sale and have a net carrying value of $ 138 million , reflecting subsequent business activity and estimated costs to sell, as we discuss in Note 5. Our other U.S. midstream assets that were measured at fair value, including LA Storage, continue to be classified as property, plant and equipment and have a carrying value of $ 37 million at June 30, 2018.

We provide below updates to ongoing matters related to SONGS, a nuclear generating facility near San Clemente, California that ceased operations in June 2013, and in which SDG&E has a 20 -percent ownership interest. We discuss SONGS further in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

SONGS STEAM GENERATOR REPLACEMENT PROJECT

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As part of the SGRP, the steam generators were replaced in SONGS Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units were shut down in early 2012 after a water leak occurred in the Unit 3 steam generator. Edison concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2’s steam generator. These issues with the steam generators ultimately resulted in Edison’s decision to permanently retire SONGS.

The replacement steam generators were designed and provided by MHI. In 2013, Edison instituted arbitration proceedings against MHI seeking recovery of damages. 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 the 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 was 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 the proceeds from the MHI arbitration by reducing Operation and Maintenance 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 November 2014, the CPUC issued a final decision approving an Amended Settlement Agreement in the SONGS OII proceeding. We describe the terms and provisions of the Amended Settlement Agreement in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

In May 2016, following the filing of petitions for modification by various parties, the CPUC issued a procedural ruling reopening the record of the OII to address the issue of whether the Amended Settlement Agreement is reasonable and in the public interest.

In December 2016, the CPUC issued another procedural ruling 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.

On January 30, 2018, SDG&E, Edison, ORA, TURN and other intervenors entered into a settlement agreement (the Revised Settlement Agreement). On the same date, a Joint Motion for Adoption of the Settlement Agreement was filed with the CPUC. The Revised Settlement Agreement resolves all issues under consideration in the SONGS OII and modifies the Amended Settlement Agreement. The Revised Settlement Agreement was the result of multiple mediation sessions in 2017 and January 2018 and was signed following a settlement conference in the SONGS OII, as required under CPUC rules. In February 2018, the parties filed a motion to stay the proceedings in the OII pending the CPUC’s consideration of the Revised Settlement Agreement. In February and March of 2018, the CPUC granted the parties’ request and established a procedural schedule for 2018 that includes additional testimony, a status conference and briefing, and public participation and evidentiary hearings in April through July.

On July 26, 2018, the CPUC issued a final decision approving the Revised Settlement Agreement with only one modification: removal of the GHG emissions reduction research program that was to be funded by utility shareholders over a five-year period in the amount of $ 12.5 million , of which $ 2.5 million was SDG&E’s share. On August 2, 2018, parties to the Revised Settlement Agreement submitted a notice that they accept 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, in which Edison has agreed to pay for the amounts that SDG&E would have received in rates under the Amended Settlement Agreement but will not receive upon implementation of the Revised Settlement Agreement.

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Disallowances, Refunds and Recoveries

Under the Revised Settlement Agreement, SDG&E and Edison will cease 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. SDG&E and Edison expect to refund to customers SONGS-related amounts recovered in rates after December 19, 2017.

Utility Shareholder Agreement

On January 10, 2018, SDG&E and Edison entered into the Utility Shareholder Agreement. Under the terms of the Utility Shareholder Agreement, 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 will mutually release each other from the “SONGS Issues,” a defined term that consists of 18 broad categories. The effect of the agreement is that the parties will release 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 commences 30 days after the first fiscal quarter in which the CPUC approved the Revised Settlement Agreement, and amounts are due to SDG&E quarterly thereafter until April 2022, which approximates the amounts and timing of amounts of what would have been SDG&E’s recoveries from ratepayers contemplated under the Amended Settlement Agreement.

Accounting and Financial Impacts

As a result of the Revised Settlement Agreement by the settling parties and the Utility Shareholder Agreement, at June 30, 2018, SDG&E has a receivable from Edison, including accrued interest, totaling $ 154 million , with $ 52 million classified as current and $ 102 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. Edison contracted with a joint venture 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 Condensed 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. We expect a ruling by the CPUC on the joint application in 2019. 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 $ 362 million for 2013 through 2018 (2018 forecasted) SONGS decommissioning costs. This includes up to $ 60 million authorized by the CPUC in January 2018 to be withdrawn from the NDT for forecasted 2018 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

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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.

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 9.

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost				Gross unrealized gains				Gross unrealized losses				Estimated fair value
At June 30, 2018:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies (1)	$	57			$	—			$	—			$	57
Municipal bonds (2)	262				3				( 2		)		263
Other securities (3)	233				1				( 5		)		229
Total debt securities	552				4				( 7		)		549
Equity securities	160				302				( 3		)		459
Cash and cash equivalents	14				—				—				14
Total	$	726			$	306			$	( 10	)		$	1,022
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 2018-2056.

(3)	Maturity dates are 2018-2064.

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)
	Three months ended June 30,								Six months ended June 30,
	2018				2017				2018				2017
Proceeds from sales	$	277			$	466			$	487			$	823
Gross realized gains	25				79				29				124
Gross realized losses	( 2		)		( 3		)		( 5		)		( 8		)

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 Condensed Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

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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 California Coastal Commission 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 by 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 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. 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.

In September 2016, Edison filed claims with the DOE for $ 56 million in spent fuel management costs incurred in 2014 and 2015 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. In February 2017, the DOE reduced the request to approximately $ 43 million primarily due to reductions to the claimed fuel canister costs. SDG&E received its $ 9 million respective share of the claim from Edison in May 2017 and recorded the proceeds in balancing accounts or as reductions to regulatory assets for the benefit of ratepayers.

In October 2017, Edison filed claims with the DOE for $ 58 million in spent fuel management costs incurred in 2016 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. SDG&E’s respective share of the claim is $ 12 million . In March 2018, the DOE issued its determination of allowable costs for the claim as $ 44 million , with SDG&E’s respective share as $ 9 million . In April 2018, Edison requested reconsideration from the DOE of $ 1 million of the DOE’s deductions from the claimed amount. In May 2018, the DOE issued a supplemental determination that the $ 1 million requested for reconsideration is allowable and should be reimbursed. In July 2018, SDG&E received its $ 9 million total share of the 2016 claim.

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, 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 is 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

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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.

LEGAL PROCEEDINGS

We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to reasonably estimate the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed applicable insurance coverage and could materially adversely affect our business, cash flows, results of operations, financial condition and prospects. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.

At June 30, 2018 , loss contingency accruals for legal matters, including associated legal fees, that are probable and estimable were $ 191 million for Sempra Energy Consolidated, including $ 2 million for SDG&E and $ 136 million for SoCalGas. Amounts for Sempra Energy and SoCalGas include $ 127 million for matters related to the Aliso Canyon natural gas storage facility gas leak, which we discuss below.

SDG&E

2007 Wildfire Litigation and Net Cost Recovery Status

SDG&E has resolved all litigation associated with three wildfires that occurred in October 2007, except one appeal that remains pending after judgment in the trial court. SDG&E does not expect additional plaintiffs to file lawsuits given the applicable statutes of limitation, but could receive additional settlement demands and damage estimates from the remaining plaintiff until the case is resolved. SDG&E maintains reserves for the wildfire litigation and adjusts these reserves as information becomes available and amounts are estimable.

As a result of a CPUC decision denying SDG&E’s request to recover wildfire costs, SDG&E wrote off the wildfire regulatory asset, resulting in a charge of $ 351 million ( $ 208 million after-tax) in the third quarter of 2017. SDG&E will continue to vigorously pursue recovery of these costs, which were incurred through settling claims brought under the doctrine of inverse condemnation. SDG&E applied to the CPUC for rehearing of its decision on January 2, 2018. On July 12, 2018, the CPUC adopted a decision denying the rehearing requests filed by SDG&E and other parties. On August 3, 2018, we filed an appeal with the California Courts of Appeal seeking to reverse the CPUC’s decision.

SoCalGas

Aliso Canyon Natural Gas Storage Facility Gas Leak

On October 23, 2015, SoCalGas discovered a leak at one of its injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility (the Leak), located in the northern part of the San Fernando Valley in Los Angeles County. The Aliso Canyon natural gas storage facility has been operated by SoCalGas since 1972. SS25 is one of more than 100 injection-and-withdrawal wells at the storage facility. SoCalGas worked closely with several of the world’s leading experts to stop the Leak, and on February 18, 2016, DOGGR confirmed that the well was permanently sealed. SoCalGas calculated that approximately 4.62 Bcf of natural gas was released from the Aliso Canyon natural gas storage facility as a result of the Leak.

Local Community Mitigation Efforts. Pursuant to a stipulation and order by the LA Superior Court, SoCalGas provided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed.

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Following the permanent sealing of the well, the DPH conducted testing in certain homes in the Porter Ranch community, and concluded that indoor conditions did not present a long-term health risk and that it was safe for residents to return home. In May 2016, the LA Superior Court ordered SoCalGas to offer to clean residents’ homes at SoCalGas’ expense as a condition to ending the relocation program. SoCalGas completed the residential cleaning program and the relocation program ended in July 2016.

In May 2016, the DPH also issued a directive that SoCalGas additionally professionally clean (in accordance with the proposed protocol prepared by the DPH) the homes of all residents located within the Porter Ranch Neighborhood Council boundary, or who participated in the relocation program, or who are located within a five-mile radius of the Aliso Canyon natural gas storage facility and experienced symptoms from the Leak (the Directive). SoCalGas disputes the Directive, contending that it is invalid and unenforceable, and has filed a petition for writ of mandate to set aside the Directive.

The costs incurred to remediate and stop the Leak and to mitigate local community impacts have been significant and may increase, and we may be subject to potentially significant damages, restitution, and civil, administrative and criminal fines, penalties and other costs. To the extent any of these costs are not covered by insurance (including any costs in excess of applicable policy limits), if there were to be significant delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes, such amounts could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Cost Estimates and Accounting Impact. At June 30, 2018 , SoCalGas estimates that its costs related to the Leak are $ 1,014 million , which includes $ 987 million of costs recovered or probable of recovery from insurance. Of the $ 1,014 million of estimated costs, approximately 55 percent is for the temporary relocation program (including cleaning costs and certain labor costs). The remaining portion of the $ 1,014 million includes legal costs incurred to defend litigation, the estimated costs to settle certain actions, the estimated cost of the root cause analysis being conducted by an independent third party, efforts to control the well, the costs to mitigate the actual natural gas released, the value of lost gas, and other costs. The value of lost gas reflects the replacement cost of all lost gas. SoCalGas adjusts its estimated total liability associated with the Leak as additional information becomes available. The $ 1,014 million represents management’s best estimate of these costs related to the Leak. Of these costs, a substantial portion has been paid and $ 160 million is accrued as Reserve for Aliso Canyon Costs as of June 30, 2018 on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets for amounts expected to be paid after June 30, 2018 .

As of June 30, 2018 , we recorded the expected recovery of the costs described in the immediately preceding paragraph related to the Leak of $ 502 million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets. This amount is net of insurance retentions and $ 485 million of insurance proceeds we received through June 30, 2018 related to portions of the costs described above, including temporary relocation costs, control-of-well expenses, legal costs and lost gas. If we were to conclude that this receivable or a portion of it is no longer probable of recovery from insurers, some or all of this receivable would be charged against earnings, which could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

As described in “Governmental Investigations and Civil and Criminal Litigation” below, the actions seek compensatory, statutory and punitive damages, restitution, and civil, administrative and criminal fines, penalties and other costs, which except for the amounts paid or estimated to settle certain actions, are not included in the above amounts as it is not possible at this time to predict the outcome of these actions or reasonably estimate the amount of damages, restitution or civil, administrative or criminal fines, penalties or other costs that may be imposed. The recorded amounts above also do not include the costs to clean additional homes pursuant to the Directive, future legal costs necessary to defend litigation, and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate. Furthermore, the cost estimate of $ 1,014 million does not include certain other costs expensed by Sempra Energy through June 30, 2018 associated with defending against shareholder derivative lawsuits.

In March 2016, the CPUC ordered SoCalGas to establish a memorandum account to prospectively track its authorized revenue requirement and all revenues that it receives for its normal, business-as-usual costs to own and operate the Aliso Canyon natural gas storage facility and, in September 2016, approved SoCalGas’ request to begin tracking these revenues as of March 17, 2016. The CPUC will determine at a later time whether, and to what extent, the authorized revenues tracked in the memorandum account will be refunded to ratepayers.

Insurance. Excluding directors’ and officers’ liability insurance, we have at least four kinds of insurance policies that together we estimate provide between $ 1.2 billion to $ 1.4 billion in insurance coverage, depending on the nature of the claims. We cannot predict all of the potential categories of costs or the total amount of costs that we may incur as a result of the Leak. Subject to various policy limits, exclusions and conditions, based on what we know as of the filing date of this report, we believe that our insurance policies collectively should cover the following categories of costs: costs incurred for temporary relocation (including cleaning costs and certain labor costs), costs to address the Leak and stop or reduce emissions, the root cause analysis being conducted to investigate the cause of the Leak, the value of lost gas, costs incurred to mitigate the actual natural gas released,

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costs associated with litigation and claims by nearby residents and businesses, any costs to clean additional homes pursuant to the Directive, and, in some circumstances depending on their nature and manner of assessment, fines and penalties. We have been communicating with our insurance carriers and, as discussed above, we have received insurance payments for portions of the costs described above, including temporary relocation costs, control-of-well expenses, legal costs and lost gas. We intend to pursue the full extent of our insurance coverage for the costs we have incurred or may incur. There can be no assurance that we will be successful in obtaining additional insurance recovery for these costs under the applicable policies, and to the extent we are not successful in obtaining coverage or these costs exceed the amount of our coverage, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

At June 30, 2018 , SoCalGas’ estimated costs related to the Leak of $ 1,014 million include $ 987 million of costs recovered or probable of recovery from insurance. This estimate may rise significantly as more information becomes available. Any costs not included in the $ 1,014 million cost estimate could be material. To the extent not covered by insurance (including any costs in excess of applicable policy limits), if there were to be significant delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes, such amounts could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Investigations and Civil and Criminal Litigation. Various governmental agencies, including DOGGR, DPH, SCAQMD, CARB, Los Angeles Regional Water Quality Control Board, California Division of Occupational Safety and Health, CPUC, PHMSA, EPA, Los Angeles County District Attorney’s Office and California Attorney General’s Office, have investigated or are investigating this incident. Other federal agencies (e.g., the DOE and the U.S. Department of the Interior) investigated the incident as part of a joint interagency task force. In January 2016, DOGGR and the CPUC selected Blade Energy Partners to conduct, under their supervision, an independent analysis of the technical root cause of the Leak, to be funded by SoCalGas. The timing of the root cause analysis is under the control of Blade Energy Partners, DOGGR and the CPUC.

As of August 1, 2018, 382 lawsuits, including approximately 48,000 plaintiffs, are pending against SoCalGas, some of which have also named Sempra Energy. All of these cases, other than a matter brought by the Los Angeles County District Attorney and the federal securities class action discussed below, are coordinated before a single court in the LA Superior Court for pretrial management (the Coordination Proceeding).

Pursuant to the Coordination Proceeding, in March 2017, the individuals and business entities asserting tort and Proposition 65 claims filed a Second Amended Consolidated Master Case Complaint for Individual Actions, through which their separate lawsuits will be managed for pretrial purposes. The consolidated complaint asserts causes of action for negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment, loss of consortium and violations of Proposition 65 against SoCalGas, with certain causes also naming Sempra Energy. The consolidated complaint seeks compensatory and punitive damages for personal injuries, lost wages and/or lost profits, property damage and diminution in property value, injunctive relief, costs of future medical monitoring, civil penalties (including penalties associated with Proposition 65 claims alleging violation of requirements for warning about certain chemical exposures), and attorneys’ fees.

In January 2017, pursuant to the Coordination Proceeding, two consolidated class action complaints were filed against SoCalGas and Sempra Energy, one on behalf of a putative class of persons and businesses who own or lease real property within a five -mile radius of the well (the Property Class Action), and a second on behalf of a putative class of all persons and entities conducting business within five miles of the facility (the Business Class Action). Both complaints assert claims for strict liability for ultra-hazardous activities, negligence and violation of California Unfair Competition Law. The Property Class Action also asserts claims for negligence per se, trespass, permanent and continuing public and private nuisance, and inverse condemnation. The Business Class Action also asserts a claim for negligent interference with prospective economic advantage. Both complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees. In December 2017, the California Court of Appeal, Second Appellate District ruled that the purely economic damages alleged in the Business Class Action are not recoverable under the law. In February 2018, the California Supreme Court granted a petition filed by the plaintiffs to review that ruling. In September and October of 2017, property developers filed two complaints, one of which was amended in July 2018, against SoCalGas and Sempra Energy alleging causes of action for strict liability, negligence per se, negligence, continuing nuisance, permanent nuisance and violation of the California Unfair Competition Law, as well as claims for negligence against certain directors of SoCalGas. The complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees. These claims are joined in the Coordination Proceeding.

In addition to the lawsuits described above, a federal securities class action alleging violation of the federal securities laws has been filed against Sempra Energy and certain of its officers and certain of its directors in the United States District Court for the Southern District of California. In March 2018, the District Court dismissed the action with prejudice, and in April 2018 the plaintiffs moved for reconsideration of the order.

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Five shareholder derivative actions are also pending in the Coordination Proceeding alleging breach of fiduciary duties against certain officers and certain directors of Sempra Energy and/or SoCalGas, four of which were joined in a Consolidated Shareholder Derivative Complaint in August 2017.

Three actions filed by public entities are pending in the Coordination Proceeding. First, in July 2016, the County of Los Angeles, on behalf of itself and the people of the State of California, filed a complaint against SoCalGas in the LA Superior Court for public nuisance, unfair competition, breach of franchise agreement, breach of lease, and damages. This suit alleges that the four natural gas storage fields operated by SoCalGas in Los Angeles County require safety upgrades, including the installation of a sub-surface safety shut-off valve on every well. It additionally alleges that SoCalGas failed to comply with the DPH Directive. It seeks preliminary and permanent injunctive relief, civil penalties, and damages for the County’s costs to respond to the Leak, as well as punitive damages and attorneys’ fees.

Second, in August 2016, the California Attorney General, acting in an independent capacity and on behalf of the people of the State of California and the CARB, together with the Los Angeles City Attorney, filed a third amended complaint on behalf of the people of the State of California against SoCalGas alleging public nuisance, violation of the California Unfair Competition Law, violations of California Health and Safety Code sections 41700 (prohibiting discharge of air contaminants that cause annoyance to the public) and 25510 (requiring reporting of the release of hazardous material), as well as California Government Code section 12607 for equitable relief for the protection of natural resources. The complaint seeks an order for injunctive relief, to abate the public nuisance, and to impose civil penalties.

Third, a petition for writ of mandate filed by the County of Los Angeles is pending against DOGGR and its State Oil and Gas Supervisor and the CPUC and its Executive Director, as to which SoCalGas is the real party in interest. The petition alleges that in issuing its July 2017 determination that the requirements for the resumption of injection operations were met (discussed under “Natural Gas Storage Operations and Reliability” below), DOGGR failed to comply with the provisions of SB 380, which requires a comprehensive safety review of the Aliso Canyon natural gas storage facility before injection of natural gas may resume. The County alleges, among other things, that DOGGR failed to comply with the provisions of SB 380 in declaring the safety review complete and authorizing the resumption of injection of natural gas into the facility before the root cause analysis was complete, failing to make its safety-review documents available to the public and failing to address seismic risks to the field as part of its safety review. The County further alleges that CEQA required DOGGR to prepare an EIR before the resumption of injection of natural gas at the facility may be approved. The petition seeks a writ of mandate requiring DOGGR and the State Oil and Gas Supervisor to comply with SB 380 and CEQA, and to produce records in response to the County’s Public Records Act request, as well as declaratory and injunctive relief against any authorization to inject natural gas and attorneys’ fees.

Separately, in February 2016, the Los Angeles County District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for alleged failure to provide timely notice of the Leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for allegedly violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public. Pursuant to a settlement agreement with the Los Angeles County District Attorney’s Office, SoCalGas agreed to plead no contest to the notice charge under Health and Safety Code section 25510(a) and agreed to pay the maximum fine of $ 75,000 , penalty assessments of approximately $ 233,500 , and operational commitments estimated to cost approximately $ 6 million , reimbursement and assessments in exchange for the Los Angeles County District Attorney’s Office moving to dismiss the remaining counts at sentencing and settling the complaint (the District Attorney Settlement). In November 2016, SoCalGas completed the commitments and obligations under the District Attorney Settlement, and on November 29, 2016, the LA Superior Court approved the settlement and entered judgment on the notice charge. Certain individuals who object to the settlement have filed an appeal of the judgment, contending they should be granted restitution.

The costs of defending against these civil and criminal lawsuits, cooperating with these investigations, and any damages, restitution, and civil, administrative and criminal fines, penalties and other costs, if awarded or imposed, as well as the costs of mitigating the actual natural gas released, could be significant and to the extent not covered by insurance (including any costs in excess of applicable policy limits), if there were to be significant delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes, such amounts could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Regulatory Proceedings. In February 2017, the CPUC opened a proceeding pursuant to SB 380 to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region. The CPUC indicated it intends to conduct the proceeding in two phases, with Phase 1 undertaking a comprehensive effort to develop the appropriate analyses and scenarios to evaluate the impact of reducing or eliminating the use of the Aliso Canyon natural gas storage facility and Phase 2 using those analyses and scenarios to evaluate the impacts of reducing or eliminating the use of the Aliso Canyon natural gas storage facility.

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The order establishing the scope of the proceeding expressly excludes issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Leak. The CPUC adopted an initial Phase 1 schedule contemplating public participation hearings and workshops beginning in April 2017, but no hearings until Phase 2. In May 2018, the CPUC updated the Phase 1 schedule, providing for Phase 1 to be concluded November 14, 2018 with issuance of a Ruling Adopting Scenarios, Assumptions and Models.

Section 455.5 of the California Public Utilities Code, among other things, directs regulated utilities to notify the CPUC if all or any portion of a major facility has been out of service for nine consecutive months. Although SoCalGas does not believe the Aliso Canyon natural gas storage facility or any portion of the facility was out of service (as that term is meant in section 455.5) for nine consecutive months, SoCalGas provided notification out of an abundance of caution to demonstrate its commitment to regulatory compliance and transparency, and because obtaining authorization to resume injection operations at the facility required more time than initially contemplated. In response, and as required by section 455.5, the CPUC issued an OII to address whether the Aliso Canyon natural gas storage facility or any portion of the facility was out of service for nine consecutive months under section 455.5, and if so, whether the CPUC should disallow costs for such period from SoCalGas’ rates. If the CPUC determines that all or any portion of the facility was out of service for nine consecutive months, the amount of any refund to ratepayers and the inability to earn a return on those assets could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Orders and Additional Regulation. In January 2016, the Governor of the State of California issued an order (the Governor’s Order) proclaiming a state of emergency in Los Angeles County due to the Leak. The Governor’s Order imposes various orders with respect to: stopping the Leak; protecting public health and safety; ensuring accountability; and strengthening oversight. Most of the directives in the Governor’s Order have been fulfilled, with the following remaining open items: (1) applicable agencies must convene an independent panel of scientific and medical experts to review public health concerns stemming from the natural gas leak and evaluate whether additional measures are needed to protect public health; (2) the CPUC must ensure that SoCalGas covers costs related to the natural gas leak and its response while protecting ratepayers; (3) CARB must develop a program to fully mitigate the leak’s emissions of methane by March 31, 2016, with such program to be funded by SoCalGas; and (4) DOGGR, CPUC, CARB and the CEC must submit to the Governor’s Office a report that assesses the long-term viability of natural gas storage facilities in California.

In December 2015, SoCalGas made a commitment to mitigate the actual natural gas released from the Leak and has been working on a plan to accomplish the mitigation. In March 2016, pursuant to the Governor’s Order, the CARB issued its Aliso Canyon Methane Leak Climate Impacts Mitigation Program , which set forth its recommended approach to achieve full mitigation of the emissions from the Leak. The CARB program requires that reductions in short-lived climate pollutants and other GHG be at least equivalent to the amount of the emissions from the Leak, and that the amount of reductions required be derived using the global warming potential based on a 20 -year term (rather than the 100 -year term the CARB and other state and federal agencies use in regulating emissions), resulting in a target of approximately 9,000,000 metric tons of carbon dioxide equivalent. CARB’s program also calls for all of the mitigation to occur in California over the next five to ten years without the use of allowances or offsets. In October 2016, CARB issued its final report concluding that the incident resulted in total emissions from 90,350 to 108,950 metric tons of methane, and asserting that SoCalGas should mitigate 109,000 metric tons of methane to fully mitigate the GHG impacts of the Leak. We have not agreed with CARB’s estimate of methane released and continue to work with CARB on developing a mitigation plan.

Natural Gas Storage Operations and Reliability. Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and heating needs in the winter. The Aliso Canyon natural gas storage facility, with a storage capacity of 86 Bcf (which represents 63 percent of SoCalGas’ natural gas storage inventory capacity), is the largest SoCalGas storage facility and an important element of SoCalGas’ delivery system. Beginning October 25, 2015, pursuant to orders by DOGGR and the Governor of the State of California, and in accordance with SB 380, SoCalGas suspended injection of natural gas into the Aliso Canyon natural gas storage facility. In April and June of 2017, SoCalGas advised the California ISO, CEC, CPUC and PHMSA of its concerns that the inability to inject natural gas into the Aliso Canyon natural gas storage facility posed a risk to energy reliability in Southern California. Limited withdrawals of natural gas from the Aliso Canyon natural gas storage facility have been made to augment natural gas supplies during critical demand periods.

On July 19, 2017, DOGGR issued its determination that SoCalGas had met the requirements of SB 380 for the resumption of injection operations, including all safety requirements. On the same date, the CPUC’s Executive Director issued his concurrence with that determination, and DOGGR issued its Order to: Test and Take Temporary Actions Upon Resuming Injection: Aliso Canyon Gas Storage Facility lifting the prohibition on injection at the Aliso Canyon natural gas storage facility, subject to certain requirements after injection resumed, including limitations on the rate at which SoCalGas may withdraw natural gas from the field. The County of Los Angeles filed a petition for writ of mandate seeking declaratory and injunctive relief and a stay of

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DOGGR’s order lifting the prohibition against injecting natural gas at the facility. We provide further detail regarding the County of Los Angeles’ suit above in “Governmental Investigations and Civil and Criminal Litigation.” Having completed the steps outlined by state agencies to safely begin injections at the Aliso Canyon natural gas storage facility, as of July 31, 2017, SoCalGas resumed limited injections. The CPUC has issued a series of directives to SoCalGas establishing the range of working gas to be maintained in the Aliso Canyon natural gas storage facility to help ensure safety and reliability for the region and just and reasonable rates in California, the most recent of which, issued July 2, 2018, directed SoCalGas to maintain up to 34 Bcf of working gas.

If the Aliso Canyon natural gas storage facility were determined to have been out of service for any meaningful period of time or permanently closed, or if future cash flows were otherwise insufficient to recover its carrying value, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At June 30, 2018 , the Aliso Canyon natural gas storage facility has a net book value of $ 678 million , including $ 286 million for the recently completed construction of a new compressor station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, and could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Sempra Mexico

Property Disputes and Permit Challenges

Energía Costa Azul. Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its ECA LNG terminal near Ensenada, Mexico. A claimant to the adjacent property filed complaints in the federal Agrarian Court challenging the refusal of SEDATU in 2006 to issue a title to him for the disputed property. In November 2013, the federal Agrarian Court ordered that SEDATU issue the requested title and cause it to be registered. Both SEDATU and Sempra Mexico challenged the ruling, due to lack of notification of the underlying process. Both challenges are pending to be resolved by a Federal Court in Mexico. Sempra Mexico expects additional proceedings regarding the claims.

Several administrative challenges are pending in Mexico before the Mexican environmental protection agency and the Federal Tax and Administrative Courts seeking revocation of the environmental impact authorization issued to ECA in 2003. These cases generally allege that the conditions and mitigation measures in the environmental impact authorization are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines.

Cases involving t wo parcels of real property have been filed against ECA. In one case, filed in the federal Agrarian Court in 2006, the plaintiffs seek to annul the recorded property title for a parcel on which the ECA LNG terminal is situated and to obtain possession of a different parcel that allegedly sits in the same place. Another civil complaint filed in the state court was served in April 2012 seeking to invalidate the contract by which ECA purchased another of the terminal parcels, on the grounds the purchase price was unfair; the plaintiff filed a second complaint in 2013 in the federal Agrarian Court seeking an order that SEDATU issue title to her. In January 2016, the federal Agrarian Court ruled against the plaintiff, and the plaintiff appealed the ruling. In May 2018, the state court dismissed the civil complaint, and the plaintiff has appealed. Sempra Mexico expects further proceedings on these two matters.

Guaymas-El Oro Segment of the Sonora Pipeline. IEnova’s Sonora natural gas pipeline consists of two segments, the Sasabe-Puerto Libertad-Guaymas segment, and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. In 2015, the Yaqui tribe, with the exception of some members living in the Bácum community, granted its consent and a right-of-way easement agreement for the construction of the Guaymas-El Oro segment of the Sonora natural gas pipeline that crosses its territory. Representatives of the Bácum community filed a legal challenge in Mexican Federal Court demanding the right to withhold consent for the project, the stoppage of work in the Yaqui territory and damages. In 2016, the judge granted a suspension order that prohibited the construction of such segment through the Bácum community territory. Because the pipeline does not pass through the Bácum community, IEnova did not believe the 2016 suspension order prohibited construction in the remainder of the Yaqui territory. Because of the dispute, however, IEnova was delayed in the construction of the approximately 14 kilometers of pipeline that pass through territory of the Yaqui tribe. IEnova declared a force majeure under its contract with the CFE as a result of such construction delays. The CFE agreed to extend the deadline for commercial operations of the Guaymas-El Oro segment until the second quarter of 2017 and to pay fixed charge payments pursuant to the service agreement during such extension. Construction of the Guaymas-El Oro segment was completed, and commercial operations began in May 2017.

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Following the start of commercial operations of the Guaymas-El Oro segment, an appellate court ruled that the scope of the 2016 suspension order encompassed the wider Yaqui territory. The legal challenge remains pending. IEnova has subsequently reported damage and declared a force majeure event for the Guaymas-El Oro segment of the Sonora pipeline in the Yaqui territory that has interrupted its operations since August 23, 2017. The Sasabe-Puerto Libertad-Guaymas segment of the Sonora pipeline remains in full operation.

Other Litigation

Sempra Energy holds a noncontrolling interest in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. NatWest Markets Plc, formerly RBS, our partner in the joint venture, paid an assessment of £ 86 million (approximately $ 138 million in U.S. dollars) in October 2014 to HMRC for denied VAT refund claims filed in connection with the purchase of carbon credit allowances by RBS SEE, a subsidiary of RBS Sempra Commodities. RBS SEE has since been sold to JP Morgan and later to Mercuria Energy Group, Ltd. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid on certain carbon credit purchases during 2009 because RBS knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. After paying the assessment, RBS filed a Notice of Appeal of the assessment with the First-Tier Tribunal. The First-Tier Tribunal held a preliminary hearing in September 2016 to determine whether HMRC’s assessment was time-barred. In January 2017, the First-Tier Tribunal ruled that HMRC’s assessment was timely. There will be a hearing on the substantive matter regarding whether RBS knew or should have known that certain vendors in the trading chain did not remit their VAT to HMRC.

During 2015, liquidators acting on behalf of ten companies (the Liquidating Companies) that engaged in carbon credit trading via chains that included a company that RBS SEE traded with directly filed a claim in the High Court of Justice asserting damages of £ 160 million (approximately $ 211 million in U.S. dollars at June 30, 2018) against RBS and Mercuria Energy Europe Trading Limited (the Defendants). The claim alleges that the Defendants’ participation in the purchase and sale of carbon credits resulted in the Companies’ carbon credit trading transactions creating a VAT liability they were unable to pay. The £ 160 million is comprised of a claim by the Liquidating Companies for £ 80 million (approximately $ 106 million in U.S. dollars at June 30, 2018) for equitable compensation due to dishonest assistance, and a claim by the liquidators for compensation in the same amount under the U.K. Insolvency Act of 1986. The parties have agreed that to the extent the Companies’ claims are successful, the liquidators cannot collect under the U.K. Insolvency Act of 1986; however, the award amount is ultimately determined by the court. The hearing for this matter began on June 14, 2018 and concluded on July 20, 2018. On the final day of the trial, the claimants withdrew a portion of their claim. The impact of this withdrawal on the total claim amount is unknown at this time. JP Morgan has notified us that Mercuria Energy Group, Ltd. has sought indemnity for the claim, and JP Morgan has in turn sought indemnity from Sempra Energy and RBS.

Our remaining investment in RBS Sempra Commodities of $ 65 million at June 30, 2018 is accounted for under the equity method and reflects remaining distributions expected to be received from the partnership as it is liquidated. The timing and amount of distributions may be impacted by these matters.

Certain EFH subsidiaries that we acquired as part of the Merger are defendants in approximately 115 personal injury lawsuits brought in state courts throughout the U.S. These cases allege illness or death as a result of exposure to asbestos in power plants designed and/or built by companies whose assets were purchased by predecessor entities to the EFH subsidiaries, and generally assert claims for product defects, negligence, strict liability and wrongful death. They seek compensatory and punitive damages. Additionally, in connection with the EFH bankruptcy proceeding, approximately 28,000 proofs of claim were filed on behalf of persons who allege exposure to asbestos under similar circumstances and assert the right to file such lawsuits in the future. We anticipate additional lawsuits will be filed. None of these claims or lawsuits were discharged in the EFH bankruptcy proceeding.

We discuss below significant changes in the first six months of 2018 to contractual commitments discussed in Notes 1 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

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Natural Gas Contracts

Sempra LNG & Midstream’s natural gas purchase and transportation commitments have decreased by $ 91 million since December 31, 2017 , primarily due to payments on existing contracts and changes in forward natural gas prices in the first six months of 2018 . Net future payments are expected to decrease by $ 104 million in 2018, and increase by $ 8 million in 2019, $ 3 million in 2020, and $ 2 million in 2021 compared to December 31, 2017 .

LNG Purchase Agreement

Sempra LNG & Midstream has a sale and purchase agreement for the supply of LNG to the ECA terminal. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2018 to 2029. At June 30, 2018 , the commitment amount is expected to decrease by $ 206 million in 2018, $ 34 million in 2019, $ 54 million in 2020, $ 63 million in 2021, $ 59 million in 2022 and $ 284 million thereafter (through contract termination in 2029) compared to December 31, 2017 , reflecting changes in estimated forward prices since December 31, 2017 and actual transactions for the first six months of 2018. These LNG commitment amounts are based on the assumption that all LNG cargoes, less those already confirmed to be diverted, under the agreement are delivered. Although this agreement specifies a number of cargoes to be delivered, under its terms, the customer may divert certain cargoes, which would reduce amounts paid under the agreement by Sempra LNG & Midstream. Actual LNG purchases in the current and prior years have been significantly lower than the maximum amount provided under the agreement due to the customer electing to divert cargoes as allowed by the agreement.

Construction and Development Projects

Sempra Mexico

We maintain credit policies and systems designed to manage our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. We grant credit to utility customers and counterparties, substantially all of whom are located in our service territory, which covers most of Southern California and a portion of central California for SoCalGas, and all of San Diego County and an adjacent portion of Orange County for SDG&E. We also grant credit to utility customers and counterparties of our other companies providing natural gas or electric services in Mexico, Chile and Peru.

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We have seven separately managed, reportable segments, as follows:

▪	SDG&E provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.

▪	SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California.

▪	Sempra Texas Utility holds our investment in Oncor Holdings, which owns an 80.25 -percent interest in Oncor, a regulated electric transmission and distribution utility serving customers in the north-central, eastern and western parts of Texas. As we discuss in Note 5, we completed our acquisition of the investment in March 2018.

▪	Sempra South American Utilities develops, owns and operates, or holds interests in, electric transmission, distribution and generation infrastructure in Chile and Peru.

▪	Sempra Mexico develops, owns and operates, or holds interests in, natural gas, electric, LNG, LPG, ethane and liquid fuels infrastructure, and has marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico.

▪	Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy generation facilities serving wholesale electricity markets in the U.S. In June 2018, our board of directors approved a plan to market and sell all wind assets and investments and solar assets and investments, as we discuss in Note 5.

▪

Sempra LNG & Midstream develops, owns and operates, or holds interests in, a terminal for the import and export of LNG and sale of natural gas, and natural gas pipelines, storage facilities and marketing operations, all within the U.S. In June 2018, our board of directors approved a plan to market and sell our natural gas storage assets at Mississippi Hub and our 90.9 -percent ownership interest in Bay Gas, as we discuss in Note 5.

We evaluate each segment’s performance based on its contribution to Sempra Energy’s reported earnings and cash flows. The California Utilities operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC. The California Utilities’ operations are based on rates set by the CPUC and the FERC. We describe the accounting policies of all of our segments in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

The cost of common services shared by the business segments is assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Interest income and expense is recorded on intercompany loans. The loan balances and related interest are eliminated in consolidation.

The following tables show selected information by segment from our Condensed Consolidated Statements of Operations and Condensed Consolidated Balance Sheets. Amounts labeled as “All other” in the following tables consist primarily of activities of parent organizations.

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SEGMENT INFORMATION
(Dollars in millions)
	Three months ended June 30,								Six months ended June 30,
	2018				2017				2018				2017
REVENUES
SDG&E	$	1,051			$	1,058			$	2,106			$	2,115
SoCalGas	772				770				1,898				2,011
Sempra South American Utilities	389				381				815				793
Sempra Mexico	310				273				618				537
Sempra Renewables	40				26				65				48
Sempra LNG & Midstream	79				122				183				254
Adjustments and eliminations	( 1		)		—				( 2		)		—
Intersegment revenues (1)	( 76		)		( 97		)		( 157		)		( 194		)
Total	$	2,564			$	2,533			$	5,526			$	5,564
INTEREST EXPENSE
SDG&E	$	53			$	49			$	105			$	98
SoCalGas	26				26				53				51
Sempra South American Utilities	10				11				20				20
Sempra Mexico	30				20				60				52
Sempra Renewables	5				4				10				8
Sempra LNG & Midstream	7				9				15				20
All other	137				67				249				135
Intercompany eliminations	( 31		)		( 27		)		( 59		)		( 56		)
Total	$	237			$	159			$	453			$	328
INTEREST INCOME
SDG&E	$	1			$	—			$	2			$	—
SoCalGas	1				—				1				—
Sempra South American Utilities	7				6				13				11
Sempra Mexico	16				3				31				5
Sempra Renewables	2				2				4				3
Sempra LNG & Midstream	13				12				26				29
All other	( 1		)		—				13				—
Intercompany eliminations	( 18		)		( 15		)		( 36		)		( 34		)
Total	$	21			$	8			$	54			$	14
DEPRECIATION AND AMORTIZATION
SDG&E	$	169			$	166			$	335			$	329
SoCalGas	138				126				273				252
Sempra South American Utilities	15				13				29				26
Sempra Mexico	43				37				86				73
Sempra Renewables	14				10				27				19
Sempra LNG & Midstream	11				11				22				21
All other	2				5				6				8
Total	$	392			$	368			$	778			$	728
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	42			$	54			$	98			$	144
SoCalGas	23				19				82				117
Sempra South American Utilities	21				20				41				39
Sempra Mexico	( 55		)		102				100				244
Sempra Renewables	( 58		)		( 5		)		( 65		)		( 16		)
Sempra LNG & Midstream	( 506		)		18				( 494		)		19
All other	( 50		)		( 41		)		( 56		)		( 85		)
Total	$	( 583	)		$	167			$	( 294	)		$	462

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SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
	Three months ended June 30,								Six months ended June 30,
	2018				2017				2018				2017
EQUITY (LOSSES) EARNINGS
Equity (losses) earnings before income tax:
Sempra Renewables	$	( 187	)		$	16			$	( 182	)		$	18
Sempra LNG & Midstream	1				2				1				3
All other	( 3		)		—				( 3		)		—
	( 189		)		18				( 184		)		21
Equity earnings (losses) net of income tax:
Sempra Texas Utility	114				—				129				—
Sempra South American Utilities	—				—				1				1
Sempra Mexico	71				—				30				( 9		)
	185				—				160				( 8		)
Total	$	( 4	)		$	18			$	( 24	)		$	13
EARNINGS (LOSSES) ATTRIBUTABLE TO COMMON SHARES
SDG&E	$	146			$	149			$	316			$	304
SoCalGas (2)	33				58				258				261
Sempra Texas Utility	114				—				129				—
Sempra South American Utilities	44				45				90				92
Sempra Mexico	97				( 9		)		117				39
Sempra Renewables	( 109		)		23				( 88		)		34
Sempra LNG & Midstream	( 764		)		27				( 780		)		28
All other (2)	( 122		)		( 34		)		( 256		)		( 58		)
Total	$	( 561	)		$	259			$	( 214	)		$	700
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E									$	851			$	763
SoCalGas									783				682
Sempra South American Utilities									107				77
Sempra Mexico									140				155
Sempra Renewables									37				100
Sempra LNG & Midstream									13				12
All other									10				13
Total									$	1,941			$	1,802
									June 30, 2018				December 31, 2017
ASSETS
SDG&E									$	18,372			$	17,844
SoCalGas									14,734				14,159
Sempra Texas Utility									9,407				—
Sempra South American Utilities									4,041				4,060
Sempra Mexico									8,935				8,554
Sempra Renewables									2,587				2,898
Sempra LNG & Midstream									3,686				4,872
All other									869				915
Intersegment receivables									( 2,724		)		( 2,848		)
Total									$	59,907			$	50,454
EQUITY METHOD AND OTHER INVESTMENTS
Sempra Texas Utility									$	9,407			$	—
Sempra South American Utilities									16				16
Sempra Mexico									691				624
Sempra Renewables									612				813
Sempra LNG & Midstream									1,182				997
All other									75				77
Total									$	11,983			$	2,527

(1)

Revenues for reportable segments include intersegment revenues of $ 1 million , $ 15 million , $ 28 million and $ 32 million for the three months ended June 30, 2018 ; $ 2 million , $ 32 million , $ 57 million and $ 66 million for the six months ended June 30, 2018 ; $ 3 million , $ 17 million , $ 26 million and $ 51 million for the three months ended June 30, 2017 ; and $ 4 million , $ 35 million , $ 51 million and $ 104 million for the six months ended June 30, 2017 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG & Midstream, respectively.

(2)	After preferred dividends.

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SEMPRA ENERGY

Common Stock Offering

On July 13, 2018, we completed the offering of 9,750,000 shares of our common stock, no par value, in a registered public offering at $ 113.75 per share (approximately $ 111.87 per share after deducting underwriting discounts), pursuant to forward sale agreements with an affiliate of Citigroup Global Markets Inc. and an affiliate of J.P. Morgan Securities LLC (the forward purchasers). The shares offered pursuant to the forward sale agreements were borrowed by the underwriters and therefore are not newly issued shares. The underwriters of the offering fully exercised the option we granted them to purchase an additional 1,462,500 shares of common stock directly from us solely to cover overallotments. After the offering, including the issuance of shares pursuant to the exercise of the overallotment option, the aggregate shares of common stock sold in the offering totaled 11,212,500 . We received net proceeds of $ 163.6 million (net of underwriting discounts, but before deducting equity issuance costs) from the sale of shares to cover overallotments.

The initial forward sale price under the forward sale agreements is approximately $ 111.87 per share, which is the public offering price in the common stock offering less the underwriting discount. However, the forward sale price is subject to adjustment pursuant to the forward sale agreements. We did not initially receive any proceeds from the offering of our common stock sold pursuant to the forward sale agreements. We expect that the forward sale agreements will settle in one or more settlements on or prior to December 15, 2019. At the initial forward sale price of approximately $ 111.87 per share, we expect that the net proceeds from full physical settlement of the forward sale agreements would be approximately $ 1.091 billion (or approximately $ 1.254 billion including the sale of shares to underwriters to cover overallotments) (net of underwriting discounts, but before deducting equity issuance costs, and subject to certain adjustments pursuant to the forward sale agreements). We used the net proceeds from the sale of the overallotment shares to the underwriters, and we expect to use the net proceeds from the sale of shares of our common stock pursuant to the forward sale agreements, to repay commercial paper, to fund working capital and for other general corporate purposes.

Although we expect to settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements. The forward sale agreements are also subject to acceleration by the forward purchasers upon the occurrence of certain events.

Before the issuance of shares of our common stock, if any, upon settlement of the forward sale agreements, we expect that the shares issuable upon settlement of the forward sale agreements will be reflected in our diluted EPS calculation under the treasury stock method. Under this method, the number of shares of our common stock used in calculating diluted EPS is deemed to be increased by the excess, if any, of the number of shares of common stock that would be issued upon full physical settlement of the forward sale agreements over the number of shares of common stock that could be purchased by us in the market (based on the average market price of our common stock during the applicable reporting period) using the proceeds receivable upon full physical settlement (based on the adjusted forward sale price at the end of the reporting period). Consequently, we anticipate there will be a dilutive effect on our EPS during periods when the average market price of shares of our common stock is above the applicable adjusted forward sale price, which is initially approximately $ 111.87 per share, subject to increase or decrease based on the overnight bank funding rate, less a spread, and subject to decrease by amounts related to expected dividends on shares of our common stock during the term of the forward sale agreements. Additionally, if we decide to physically settle or net share settle the forward sale agreements, delivery of our shares to the forward purchasers on any such physical settlement or net share settlement of the forward sale agreements would result in dilution to our EPS.

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6.75% Mandatory Convertible Preferred Stock Offering, Series B

On July 13, 2018, in a separate registered public offering, we sold 5,750,000 shares of our 6.75 % mandatory convertible preferred stock, series B (series B preferred stock) at $ 100.00 per share (or $ 98.35 per share after deducting underwriting discounts), including 750,000 shares purchased by the underwriters as a result of fully exercising their option to purchase such shares from us solely to cover overallotments. Each share of series B preferred stock has a liquidation value of $ 100 . We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock, no par value, or by delivery, at our election, of any combination of cash and shares of our common stock on January 15, April 15, July 15 and October 15 of each year, commencing on October 15, 2018, and to, and including, July 15, 2021. We used the net proceeds of approximately $ 565.5 million (net of underwriting discounts, but before deducting equity issuance costs) from this offering to repay commercial paper, to fund working capital and for other general corporate purposes.

Mandatory Conversion

Unless earlier converted, each share of the series B preferred stock will automatically convert on the mandatory conversion date, which is expected to be July 15, 2021, into not less than 0.7326 shares and not more than 0.8791 shares of our common stock, subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion of the series B preferred stock will be determined based on the volume-weighted average market value per share of our common stock over the 20 consecutive trading day period beginning on and including the 21st scheduled trading day immediately preceding July 15, 2021. The following table illustrates the conversion rate per share of the series B preferred stock, subject to certain anti-dilution adjustments:

CONVERSION RATES
Applicable market value per share of our common stock		Conversion rate (number of shares of our common stock to be received upon conversion of each share of series B preferred stock)
Greater than $136.50 (which is the threshold appreciation price)		0.7326 shares (approximately equal to $100.00 divided by the threshold appreciation price)
Equal to or less than $136.50 but greater than or equal to $113.75		Between 0.7326 and 0.8791 shares, determined by dividing $100.00 by the applicable market value of our common stock
Less than $113.75 (which is the initial price)		0.8791 shares (approximately equal to $100.00 divided by the initial price)

Dividends

Dividends on the series B preferred stock will be payable quarterly, beginning on October 15, 2018, on a cumulative basis when, as and if declared by our board of directors. We may pay quarterly declared dividends in cash or, subject to certain limitations, in shares of our common stock, no par value, or in any combination of cash and shares of our common stock. Shares of common stock used to pay dividends will be valued at 97 percent of the volume-weighted average price per share over the five consecutive trading day period beginning on, and including the sixth trading day prior to, the applicable dividend payment date. The holders of series B preferred stock will have no voting rights. However, under certain circumstances regarding nonpayment for six or more dividend periods, whether or not consecutive, the authorized number of directors on our board of directors will automatically be increased by two and the holders of the series B preferred stock, voting together as a single class with holders of any and all other outstanding preferred stock of equal rank having similar voting rights (which currently consists of the series A preferred stock), will be entitled to elect two directors to fill such newly created directorships. This right shall terminate when all accumulated dividends have been paid in full and the authorized number of directors shall automatically decrease by two, subject to the revesting of that right in the event of each subsequent nonpayment.

Conversion at the Option of the Holder

At any time prior to July 15, 2021, holders may elect to convert each share of the series B preferred stock into shares of our common stock at the minimum conversion rate of 0.7326 shares of our common stock per share of the series B preferred stock, subject to anti-dilution adjustments. However, if holders elect to convert any shares of the series B preferred stock during a specified period beginning on the effective date of a fundamental change, as defined in the certificate of determination of preferences of the series B preferred stock, such shares of the series B preferred stock will be converted into shares of our common stock at a fundamental change conversion rate, and the holders will also be entitled to receive a fundamental change dividend make-whole amount and accumulated dividend amount.

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The conversion of the series B preferred stock would have resulted in the issuance of approximately 4.9 million shares of our common stock, subject to possible adjustment pursuant to the terms of the series B preferred stock, based on the last reported sale price of our common stock on the New York Stock Exchange on July 10, 2018, which was $ 117.30 per share.

Ranking

The series B preferred stock will rank with respect to dividend rights and distribution rights upon our liquidation, winding-up or dissolution:

▪	senior to our common stock, including our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;

▪	on parity with our series A preferred stock, including our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;

▪	junior to our capital stock established in the future, if the terms provide that such class of series will rank senior to the series B preferred stock;

▪	junior to our existing and future indebtedness and other liabilities; and

▪	structurally subordinated to any existing and future indebtedness and other liabilities of our subsidiaries and capital stock of our subsidiaries held by third parties.

▪	Sempra Energy and its consolidated entities

▪	SDG&E and its consolidated VIE

▪	SoCalGas

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▪	the Condensed Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs;

▪	the Condensed Consolidated Financial Statements and related Notes of SDG&E and its VIE; and

▪	the Condensed Financial Statements and related Notes of SoCalGas.

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▪	Overall results of our operations

▪	Segment results

▪	Adjusted earnings and adjusted earnings per common share

▪	Significant changes in revenues, costs and earnings between periods

▪	Impact of foreign currency and inflation rates on our results of operations

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(1)	After preferred dividends.

(2)	Includes after-tax interest expense ($100 million and $40 million for the three months ended June 30, 2018 and 2017 , respectively, and $181 million and $81 million for the six months ended June 30, 2018 and 2017, respectively), intercompany eliminations recorded in consolidation and certain corporate costs.

▪	$9 million higher net interest expense, of which $6 million relates to the lower federal income tax rate in 2018; and

▪	$8 million favorable impact in 2017 from the resolution of prior years’ income tax items; offset by

▪	$11 million higher CPUC base operating margin authorized for 2018, of which $9 million relates to the lower federal income tax rate in 2018; and

▪	$5 million higher earnings from electric transmission operations.

▪	$23 million higher CPUC base operating margin authorized for 2018, of which $18 million relates to the lower federal income tax rate in 2018;

▪	$12 million increased margin as a result of revised electric distribution seasonality factors in 2018; and

▪	$11 million higher earnings from electric transmission operations; offset by

▪	$17 million higher net interest expense, of which $12 million relates to the lower federal income tax rate in 2018;

▪	$8 million favorable impact in 2017 from the resolution of prior years’ income tax items;

▪	$6 million reimbursement in 2017 of litigation costs associated with the arbitration ruling over the SONGS replacement steam generators, as we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements herein; and

▪	$5 million unfavorable impact due to lower cost of capital in 2018, of which $1 million relates to the lower federal income tax rate in 2018.

▪	$22 million from impacts associated with Aliso Canyon natural gas storage facility litigation; and

▪	$5 million unfavorable impact due to lower cost of capital in 2018, of which $1 million relates to the lower federal income tax rate in 2018; offset by

▪	$5 million higher PSEP earnings.

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▪	$22 million from impacts associated with Aliso Canyon natural gas storage facility litigation;

▪	$12 million unfavorable impact due to lower cost of capital in 2018, of which $2 million relates to the lower federal income tax rate in 2018; and

▪	$8 million higher net interest expense, of which $7 million relates to the lower federal income tax rate in 2018; offset by

▪	$32 million higher CPUC base operating margin authorized for 2018, net of expenses including depreciation. Of this increase, $26 million relates to the lower federal income tax rate in 2018; and

▪	$9 million higher PSEP earnings.

▪	$94 million favorable impact from foreign currency and inflation effects net of foreign currency derivatives effects, comprised of:

◦	in 2018, $91 million favorable foreign currency and inflation effects, offset by a $26 million loss from foreign currency derivatives, which we are using to hedge Sempra Mexico’s foreign currency exposure from its controlling interest in IEnova, and

◦	in 2017, $53 million unfavorable foreign currency and inflation effects, offset by a $24 million gain from foreign currency derivatives. We discuss these effects below in “Impact of Foreign Currency and Inflation Rates on Results of Operations;”

▪	$71 million impairment in 2017, net of a $12 million income tax benefit that has been fully reserved, of the TdM natural gas-fired power plant that was held for sale until June 1, 2018, which we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein;

▪	$13 million valuation allowance in 2017 against TdM’s deferred tax assets;

▪	$10 million higher pipeline operational earnings, primarily attributable to assets placed in service in the second quarter of 2017; and

▪	$9 million improved operating results at TdM, mainly due to higher operating expenses related to major maintenance in 2017; offset by

▪	$65 million earnings attributable to noncontrolling interests at IEnova in 2018 compared to $15 million losses in 2017;

▪	$11 million higher income tax expense in 2018 from the outside basis differences in joint venture investments; and

▪	$8 million lower earnings from equity-related AFUDC, primarily associated with assets placed in service at the end of the first half of 2017, net of higher equity earnings from AFUDC at the IMG joint venture.

▪	$89 million favorable impact from foreign currency and inflation effects net of foreign currency derivatives effects, comprised of:

◦	in 2018, $4 million unfavorable foreign currency and inflation effects, offset by a $6 million gain from foreign currency derivatives, and

◦	in 2017, $155 million unfavorable foreign currency and inflation effects, offset by a $68 million gain from foreign currency derivatives;

▪	$71 million impairment in 2017, net of a $12 million income tax benefit that has been fully reserved, of the TdM natural gas-fired power plant;

▪	$22 million higher pipeline operational earnings, primarily attributable to assets placed in service in the second quarter of 2017;

▪	$13 million valuation allowance in 2017 against TdM’s deferred tax assets; and

▪	$10 million improved operating results at TdM, mainly due to higher operating expenses related to major maintenance in the second quarter of 2017; offset by

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▪	$63 million earnings attributable to noncontrolling interests at IEnova in 2018 compared to $10 million losses in 2017;

▪	$38 million lower earnings from equity-related AFUDC, primarily associated with assets placed in service at the end of the first half of 2017, of which $18 million related to cumulative AFUDC recognized in the first quarter of 2017 when regulatory recovery became probable for the Ojinaga and San Isidro pipelines, net of higher equity earnings from AFUDC at the IMG joint venture; and

▪	$23 million higher income tax expense in 2018 from the outside basis differences in joint venture investments.

▪	$145 million other-than-temporary impairment of certain U.S. wind equity method investments, as we discuss in Notes 5, 6 and 9 of the Notes to Condensed Consolidated Financial Statements herein; offset by

▪	$13 million higher earnings from our wind and solar tax equity investments placed in service in 2017 and 2018, primarily driven by higher pretax losses attributed to tax equity investors reflected in NCI.

▪	$145 million other-than-temporary impairment of certain U.S. wind equity method investments; offset by

▪	$23 million higher earnings from our wind and solar tax equity investments placed in service in 2017 and 2018 , primarily driven by higher pretax losses attributed to tax equity investors reflected in NCI, including the impact of the TCJA on NCI allocations computed using the HLBV method.

▪	$801 million impairment of certain non-utility natural gas storage assets in the southeast U.S., some of which have been classified as held for sale, as we discuss in Notes 5 and 9 of the Notes to Condensed Consolidated Financial Statements herein; and

▪	$34 million settlement proceeds in 2017 from a breach of contract claim against a counterparty in bankruptcy court, of which $28 million related to the charge in 2016 from the permanent release of certain pipeline capacity; offset by

▪	$46 million losses attributable to noncontrolling interests in 2018 related to the impairment.

▪	$801 million impairment of certain non-utility natural gas storage assets in the southeast U.S., some of which have been classified as held for sale;

▪	$34 million settlement proceeds in 2017 from a breach of contract claim against a counterparty in bankruptcy court, of which $28 million related to the charge in 2016 from the permanent release of certain pipeline capacity;

▪	$14 million lower earnings from midstream activities, primarily driven by changes in natural gas prices, of which $1 million relates to the lower federal income tax rate in 2018; and

▪	$9 million unfavorable adjustment in 2018 to TCJA provisional amounts recorded in 2017 related to the remeasurement of deferred income taxes; offset by

▪	$46 million losses attributable to noncontrolling interests in 2018 related to the impairment.

▪	$56 million increase in net interest expense, of which $16 million relates to the lower tax rate in 2018;

▪	$25 million of mandatory convertible preferred stock dividends; and

▪	$9 million lower investment gains in 2018 on dedicated assets in support of our executive retirement and deferred compensation plans, including higher deferred compensation expense associated with these investments.

▪	$86 million increase in net interest expense, of which $28 million relates to the lower tax rate in 2018;

▪	$53 million of mandatory convertible preferred stock dividends;

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▪	$15 million income tax expense in 2018 compared to $15 million income tax benefit in 2017, which includes $16 million income tax expense in 2018 to adjust TCJA provisional amounts recorded in 2017 primarily related to withholding tax on our expected future repatriation of foreign undistributed earnings; and

▪	$23 million lower investment gains in 2018 on dedicated assets in support of our executive retirement and deferred compensation plans, net of lower deferred compensation expense associated with these investments.

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(1)

Except for adjustments that are solely income tax and tax related to outside basis differences, income taxes were primarily calculated based on applicable statutory tax rates. Income taxes associated with TdM were calculated based on the applicable statutory tax rate, including translation from historic to current exchange rates. An income tax benefit of $12 million associated with the 2017 TdM impairment has been fully reserved.

(2)	In both the three months and six months ended June 30, 2018, total weighted-average number of potentially dilutive securities of 1.7 million were not included in the computation of GAAP losses per common share since to do so would have decreased the loss per share.

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(1)	Income taxes were calculated based on applicable statutory tax rates, except for adjustments that are solely income tax.

▪	SDG&E

▪	Sempra South American Utilities’ Chilquinta Energía and Luz del Sur

▪	SDG&E

▪	SoCalGas

▪	Sempra Mexico’s Ecogas

▪	permits SDG&E to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered in subsequent periods through rates.

▪

permits the cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred. However, SoCalGas’ Gas Cost Incentive Mechanism provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Note 1 of the Notes to Consolidated Financial Statements and “Item 1. Business – Ratemaking Mechanisms” in the Annual Report.

▪	also permits the California Utilities to recover certain expenses for programs authorized by the CPUC, or “refundable programs.”

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(1)	Includes eliminations of intercompany activity.

▪	$8 million increase at Sempra South American Utilities, which included:

◦	$17 million higher rates at Luz del Sur, and

◦	$9 million due to foreign currency exchange rate effects, and

◦	$3 million higher volumes at Chilquinta Energía, offset by

◦	$17 million lower rates at Chilquinta Energía, and

◦	$7 million lower volumes at Luz del Sur, primarily driven by the migration of regulated and non-regulated customers to tolling customers, who pay only a tolling fee; offset by

▪	$8 million decrease at SDG&E, which included:

◦	$14 million revenue requirement deferral due to the effect of the TCJA,

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◦	$10 million revenue requirement deferral related to the SONGS settlement, which is offset by the discontinuation of amortization, as we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements herein,

◦	$3 million lower revenues from transmission operations, and

◦	$3 million lower cost of capital due to the CPUC decision to reduce ROE from 10.30 percent in 2017 to 10.20 in 2018, offset by

◦	$11 million decrease in charges in 2018 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD,

◦	$7 million higher cost of electric fuel and purchased power, which we discuss below, and

◦	$7 million increase in 2018 due to an increase in rates permitted under the attrition mechanism in the 2016 GRC FD.

▪	$9 million higher prices at Luz del Sur; and

▪	$7 million due to foreign currency exchange rate effects; offset by

▪	$14 million lower prices at Chilquinta Energía.

▪	$26 million increase at Sempra South American Utilities, which included:

◦	$32 million higher rates at Luz del Sur, and

◦	$26 million due to foreign currency exchange rate effects, offset by

◦	$25 million lower volumes at Luz del Sur, primarily driven by weather and the migration of regulated and non-regulated customers to tolling customers, who pay only a tolling fee, and

◦	$11 million lower rates at Chilquinta Energía; and

▪	$1 million increase at SDG&E, which included:

◦	$20 million higher cost of electric fuel and purchased power, which we discuss below,

◦	$17 million due to revised electric distribution seasonality factors in 2018,

◦	$15 million increase due to 2018 attrition,

◦	$7 million decrease in charges in 2018 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD, and

◦	$5 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M, offset by

◦	$29 million revenue requirement deferral due to the effect of the TCJA,

◦	$20 million revenue requirement deferral related to the SONGS settlement, which is offset by the discontinuation of amortization,

◦	$7 million higher non-service component of net periodic benefit credit in 2018, which is fully offset in Other Income, Net,

◦	$7 million lower revenues from transmission operations, and

◦	$6 million lower cost of capital.

▪	$20 million increase at SDG&E driven primarily by higher electricity market costs, offset by lower costs of purchased power from renewable sources due to decreased solar and wind production; and

▪	$9 million increase at Sempra South American Utilities, which included:

◦	$20 million higher prices at Luz del Sur, and

◦	$19 million due to foreign currency exchange rate effects, offset by

◦	$18 million lower volumes at Luz del Sur, and

◦	$13 million lower prices at Chilquinta Energía.

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▪

$12 million decrease at Sempra Mexico, primarily due to new regulations that went into effect on March 1, 2018 that no longer allow Ecogas to sell natural gas to high consumption end users (defined by the CRE as customers with annual consumption that exceeds 4,735 MMBtu) and require those end users to procure their natural gas needs from natural gas marketers, including Sempra Mexico’s marketing business; offset by

▪	$2 million increase at SoCalGas, which included:

◦	$27 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M,

◦	$14 million increase due to 2018 attrition, and

◦	$11 million lower non-service component of net periodic benefit credit in 2018, which is fully offset in Other Income, Net, offset by

◦	$29 million decrease in cost of natural gas sold, which we discuss below,

◦	$12 million revenue requirement deferral due to the effect of the TCJA,

◦	$6 million lower cost of capital in 2018 due to the CPUC decision reducing ROE from 10.10 percent in 2017 to 10.05 percent in 2018, and

◦	$3 million lower revenues from capital projects, including $16 million decrease for advanced metering infrastructure, offset by $5 million increase for PSEP and $8 million increase for other capital projects; and

▪	$1 million increase at SDG&E, which included:

◦	$6 million decrease in charges in 2018 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD, and

◦	$2 million increase due to 2018 attrition, offset by

◦	$8 million decrease in cost of natural gas sold, discussed below.

▪	$29 million decrease at SoCalGas due to $39 million from lower average gas prices, offset by $10 million from higher volumes driven by weather;

▪	$13 million decrease at Sempra Mexico primarily associated with the lower revenues at Ecogas; and

▪	$8 million decrease at SDG&E primarily due to lower average gas prices.

▪	$113 million decrease at SoCalGas, which included:

◦	$148 million decrease in cost of natural gas sold, which we discuss below,

◦	$31 million revenue requirement deferral due to the effect of the TCJA,

◦	$16 million lower cost of capital in 2018,

◦	$11 million higher non-service component of net periodic benefit credit in 2018, which is fully offset in Other Income, Net, and

◦	$6 million lower revenues from capital projects, including $31 million decrease for advanced metering infrastructure, offset by $10 million increase for PSEP and $15 million increase for other capital projects, offset by

◦	$60 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M, and

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◦	$38 million increase due to 2018 attrition;

▪	$14 million decrease at Sempra Mexico, primarily due to lower volumes at Ecogas primarily as a result of the new regulations that went into effect in 2018, which we discuss above; and

▪	$10 million decrease at SDG&E, which included:

◦	$23 million decrease in the cost of natural gas sold, discussed below, offset by

◦	$6 million decrease in charges in 2018 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD, and

◦	$5 million increase due to 2018 attrition.

▪	$148 million decrease at SoCalGas due to $121 million from lower average gas prices and $27 million from lower volumes driven by weather;

▪	$23 million decrease at SDG&E primarily due to lower average gas prices; and

▪	$19 million decrease at Sempra Mexico primarily associated with the lower revenues at Ecogas.

(1)	Includes eliminations of intercompany activity.

(2)	Excludes depreciation and amortization, which are presented separately on the Sempra Energy Condensed Consolidated Statements of Operations.

▪	$49 million increase at Sempra Mexico primarily due to:

◦	$15 million increase primarily due to pipeline assets placed in service in the second quarter of 2017,

◦	$14 million increase at TdM primarily due to a plant outage in 2017 as a result of scheduled major maintenance, and

◦	$10 million higher revenues from the marketing business, primarily due to new regulations that went into effect on March 1, 2018 that require high consumption end users (previously serviced by Ecogas and other natural gas utilities) to procure their

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▪	$18 million from lower intercompany eliminations associated with sales between Sempra LNG & Midstream and Sempra Mexico; and

▪	$14 million increase at Sempra Renewables primarily due to solar and wind assets placed in service during the fourth quarter of 2017 and the second quarter of 2018; offset by

▪	$43 million decrease at Sempra LNG & Midstream primarily due to:

◦	$27 million costs associated with indemnity payments to Sempra Mexico in 2018. Indemnity payments for 2017 were recorded in Cost of Natural Gas, Electric Fuel and Purchased Power prior to adoption of ASC 606, and

◦	$7 million from natural gas marketing activities primarily from changes in natural gas prices.

▪	$21 million primarily from lower intercompany eliminations of costs associated with 2017 indemnity payments from Sempra LNG & Midstream to Sempra Mexico; and

▪	$15 million increase at Sempra Mexico mainly associated with higher revenues from the marketing business as a result of natural gas sales in the distribution market driven by new regulations that went into effect in 2018, offset by lower natural gas prices. The increase at Sempra Mexico was also due to higher volumes in 2018 due to the TdM plant outage in 2017; offset by

▪	$30 million decrease at Sempra LNG & Midstream primarily due to indemnity payments to Sempra Mexico in 2017.

▪	$95 million increase at Sempra Mexico primarily due to:

◦	$40 million higher revenues primarily due to pipeline assets placed in service in the second quarter of 2017,

◦	$27 million increase at TdM primarily due to the plant outage in 2017 as a result of scheduled major maintenance, and

◦	$15 million higher revenues from the marketing business, primarily due to the new regulations that went into effect in 2018, which we discuss above, offset by lower natural gas prices;

▪	$32 million from lower intercompany eliminations associated with sales between Sempra LNG & Midstream and Sempra Mexico; and

▪	$17 million increase at Sempra Renewables primarily due to solar and wind assets placed in service during the fourth quarter of 2017 and the second quarter of 2018; offset by

▪	$71 million decrease at Sempra LNG & Midstream primarily due to:

◦	$51 million costs associated with indemnity payments to Sempra Mexico in 2018. Indemnity payments for 2017 were recorded in Cost of Natural Gas, Electric Fuel and Purchased Power prior to adoption of ASC 606, and

◦	$25 million from natural gas marketing activities primarily from changes in natural gas prices, offset by

◦	$12 million from LNG sales to Cameron LNG JV in January 2018.

▪	$38 million from lower intercompany eliminations of costs primarily associated with 2017 indemnity payments from Sempra LNG & Midstream to Sempra Mexico; and

▪	$22 million increase at Sempra Mexico primarily associated with higher revenues from the marketing business as a result of the new regulations that went into effect in 2018, offset by lower natural gas prices. The increase at Sempra Mexico was also due to higher volumes in 2018 due to the TdM plant outage in 2017; offset by

▪	$53 million decrease at Sempra LNG & Midstream primarily due to indemnity payments to Sempra Mexico in 2017.

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▪	$31 million increase at SoCalGas primarily from higher expenses associated with CPUC-authorized refundable programs for which costs incurred are recovered in revenue (refundable program expenses); and

▪	$10 million increase at SDG&E primarily from higher refundable program expenses; offset by

▪	$9 million decrease at Sempra Mexico, primarily from scheduled major maintenance at TdM in the second quarter of 2017.

▪	$59 million increase at SoCalGas primarily from higher refundable program expenses; and

▪	$27 million increase at SDG&E, which included:

◦	$12 million higher non-refundable operating costs, including labor, contract services and administrative and support costs,

◦	$11 million reimbursement of litigation costs in 2017 associated with the arbitration ruling over the SONGS replacement steam generators, as we discuss in Note 10 of the Notes to the Condensed Consolidated Financial Statements herein, and

◦	$8 million higher refundable program expenses.

▪	$96 million losses in 2018 from interest rate and foreign exchange instruments and foreign currency transactions compared to $38 million gains in 2017 primarily due to:

◦	$47 million foreign currency loss in 2018 compared to a $6 million foreign currency gain in 2017 on a Mexican peso-denominated loan to the IMG joint venture, which is offset in Equity (Losses) Earnings, and

◦	$37 million losses in 2018 on foreign currency derivatives compared to $32 million gains in 2017 as a result of fluctuation of the Mexican peso;

▪	$11 million decrease in equity-related AFUDC mainly from completion of pipeline projects at Sempra Mexico in 2017;

▪	$10 million lower non-service component of net periodic benefit credit in 2018, primarily at SoCalGas; and

▪	$8 million lower investment gains in 2018 on dedicated assets in support of our executive retirement and deferred compensation plans.

▪	$4 million losses in 2018 from interest rate and foreign exchange instruments and foreign currency transactions compared to $111 million gains in 2017 primarily due to:

◦	$90 million lower gains in 2018 on foreign currency derivatives as a result of fluctuation of the Mexican peso, and

◦	$11 million foreign currency loss in 2018 compared to $17 million foreign currency gain in 2017, which includes $8 million foreign currency loss in 2018 compared to a $6 million gain in 2017 on a Mexican peso-denominated loan to the IMG joint venture, which is offset in Equity (Losses) Earnings;

▪	$56 million decrease in equity-related AFUDC mainly from completion of pipeline projects at Sempra Mexico in 2017; and

▪	$25 million lower investment gains in 2018 on dedicated assets in support of our executive retirement and deferred compensation plans; offset by

▪	$17 million higher non-service component of net periodic benefit credit in 2018, including $9 million at SDG&E and $10 million at SoCalGas.

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(1)	We discuss how we recognize equity (losses) earnings in Note 6 of the Notes to Condensed Consolidated Financial Statements herein.

▪	$131 million income tax benefit in 2018 resulting from the reduced outside basis difference in Sempra LNG & Midstream as a result of the impairment of certain non-utility natural gas storage assets;

▪	$100 million income tax benefit in 2018 compared to a $52 million income tax expense in 2017 from foreign currency and inflation effects;

▪	$25 million valuation allowance in 2017 against deferred tax assets at TdM, including $12 million associated with the 2017 impairment; and

▪	$5 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018; offset by

▪	$21 million income tax expense in 2018 associated with Aliso Canyon natural gas storage facility litigation; and

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▪	$9 million favorable resolution in 2017 of prior years’ income tax items.

▪	$131 million income tax benefit in 2018 resulting from the reduced outside basis difference in Sempra LNG & Midstream as a result of the impairment of certain non-utility natural gas storage assets;

▪	$6 million income tax benefit in 2018 compared to a $149 million income tax expense in 2017 from foreign currency and inflation effects;

▪	$41 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018; and

▪	$25 million valuation allowance in 2017 against deferred tax assets at TdM, including $12 million associated with the 2017 impairment; offset by

▪	$25 million income tax expense in 2018 to adjust provisional estimates recorded in 2017 for the effects of TCJA;

▪	$21 million income tax expense in 2018 associated with Aliso Canyon natural gas storage facility litigation;

▪	$15 million higher income tax expense related to share-based compensation; and

▪	$9 million favorable resolution in 2017 of prior years’ income tax items.

▪	$200 million other-than-temporary impairment of certain wind equity method investments at Sempra Renewables that are included in our plan of sale, as we discuss in Notes 5, 6 and 9 of the Notes to Condensed Consolidated Financial Statements herein; offset by

▪	$114 million equity earnings, net of income tax, from our investment in Oncor Holdings, which we acquired in March 2018 and which owns an 80.25-percent interest in Oncor; and

▪	$71 million increase in equity earnings , net of income tax, at Sempra Mexico, which included:

◦	$47 million foreign currency gain in 2018 compared to a $6 million loss in 2017 at the IMG joint venture on its Mexican peso-denominated loans from its joint venture owners, which is fully offset in Other (Expense) Income, Net, and

◦	$18 million equity earnings in 2018 at the TAG joint venture mainly due to higher revenues and income tax benefits, offset by higher interest, operating and depreciation expenses.

▪	$200 million other-than-temporary impairment of certain wind equity method investments that are included in our plan of sale; offset by

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▪	$129 million equity earnings, net of income tax, from our investment in Oncor Holdings; and

▪	$30 million equity earnings , net of income tax, at Sempra Mexico in 2018 compared to $9 million equity losses, net of income tax, in 2017 , which included:

◦	$8 million foreign currency gain in 2018 compared to a $6 million loss in 2017 at the IMG joint venture on its Mexican peso-denominated loans from its joint venture owners, which is fully offset in Other (Expense) Income, Net,

◦	$11 million equity losses in 2017 from DEN, which included $8 million of equity losses in DEN’s share of the TAG joint venture, prior to IEnova’s acquisition of the remaining 50-percent interest in DEN in November 2017, and

◦	$7 million equity earnings in 2018 at the TAG joint venture mainly due to higher revenues, offset by higher tax, interest, operating and depreciation expenses.

▪	$64 million earnings attributable to NCI at Sempra Mexico in 2018 compared to losses of $15 million in 2 017; offset by

▪	$46 million losses attributable to NCI at Sempra LNG & Midstream in 2018 related to the i mpairment of certain non-utility natural gas storage assets in the southeast U.S.; and

▪	$13 million higher pretax losses attributed to tax equity investors at Sempra Renewables.

▪	$46 million losses attributable to NCI at Sempra LNG & Midstream in 2018 related to the i mpairment of certain non-utility natural gas storage assets;

▪	$31 million higher pretax losses attributed to tax equity investors at Sempra Renewables; and

▪	$1 million losses at Otay Mesa VIE in 2018 compared to earnings of $6 million in 2017; offset by

▪	$62 million earnings attributable to NCI at Sempra Mexico in 2018 compared to losses of $10 million in 2 017.

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(1)	Total reported amount for the three months and six months ended June 30, 2017 adjusted for the retrospective adoption of ASU 2017-07, which we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

(1)	Amounts at Sempra Energy Consolidated include $158 million held in non-U.S. jurisdictions. We discuss repatriation in “Item 7. MD&A – Changes in Revenues, Costs and Earnings – Income Taxes” in the Annual Report and below in “Impacts of the TCJA.”

(2)	Available unused credit is the total available on Sempra Energy’s, Sempra Global’s and the California Utilities’ credit facilities that we discuss in Note 7 of the Notes to Condensed Consolidated Financial Statements herein. Borrowings on the shared line of credit at SDG&E and SoCalGas are limited to $750 million for each utility and a combined total of $1 billion.

(3)	Because the commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit.

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▪	finance capital expenditures

▪	meet liquidity requirements

▪	fund dividends

▪	fund new business or asset acquisitions or start-ups

▪	fund capital contribution requirements

▪	repay maturing long-term debt

▪	fund expenditures related to the natural gas leak at SoCalGas’ Aliso Canyon natural gas storage facility

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▪	Energy Resource Recovery Balancing Account (ERRA) – tracks the difference between amounts billed to customers and the actual cost of electric fuel and purchased power. SDG&E’s ERRA balance was undercollected by $176 million and $51 million at June 30, 2018 and December 31, 2017 , respectively. The increase in the ERRA undercollected balance in 2018 is primarily

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▪

Electric Distribution Fixed Cost Account (EDFCA) – tracks the difference between the amounts billed to customers and the authorized margin and other costs allocated to electric distribution customers. SDG&E’s EDFCA balance was undercollected by $90 million and $112 million at June 30, 2018 and December 31, 2017 , respectively. The undercollection is driven by lower than forecasted electric volumes sold in 2018 and 2017.

▪

Core Fixed Cost Account (CFCA) – tracks the difference between amounts billed to customers and the authorized margin and other costs allocated to core customers. Because mild weather experienced in 2018 and 2017 resulted in lower natural gas consumption compared to authorized levels, SoCalGas’ CFCA balance was undercollected by $191 million and $164 million at June 30, 2018 and December 31, 2017 , respectively.

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▪	$84 million net increase in Insurance Receivable for Aliso Canyon Costs in 2018 compared to a $52 million net decrease in 2017. The $84 million net increase primarily includes $101 million of additional accruals, partially offset by $16 million in insurance proceeds received;

▪	$126 million in purchases of GHG allowances at the California Utilities in 2018 compared to $40 million in 2017;

▪	$176 million decrease in accounts receivable in 2018 compared to a $261 million decrease in 2017;

▪	$73 million lower net income, adjusted for noncash items included in earnings, in 2018 compared to 2017;

▪	$26 million cash outflow for net collateral posted for natural gas marketing activities at Sempra LNG & Midstream in 2018 compared to a $17 million cash inflow in 2017;

▪	$29 million increase in seasonal liability related to temporary LIFO liquidation at SoCalGas in 2017, primarily due to changes in natural gas inventory value;

▪	$26 million payment in 2018 for marine concession fees for liquid fuels terminals; and

▪	$23 million higher contributions to the Rabbi Trust in 2018; offset by

▪	$5 million decrease in income taxes receivable in 2018 compared to a $63 million increase in 2017;

▪	$65 million increase in deferred revenue requirement due to the TCJA at the California Utilities in 2018;

▪	$138 million increase in net overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) at SoCalGas in 2018 compared to a $79 million increase in 2017;

▪	$56 million net increase in Reserve for Aliso Canyon Costs in 2018 compared to a $10 million increase in 2017. The $56 million net increase in 2018 includes $101 million of additional accruals, offset by $45 million of cash paid; and

▪	$16 million increase in net undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) at SDG&E in 2018 compared to a $47 million increase in 2017.

▪	$20 million increase in income taxes receivable in 2018 compared to a $35 million decrease in 2017;

▪	$62 million in purchases of GHG allowances in 2018 compared to $8 million in 2017; and

▪	$46 million decrease in net income, adjusted for noncash items included in earnings, in 2018 compared to 2017; offset by

▪	$34 million increase in deferred revenue requirement due to the TCJA in 2018;

▪	$16 million increase in net undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2018 compared to a $47 million increase in 2017;

▪	$1 million increase in accounts receivable in 2018 compared to a $21 million increase in 2017; and

▪	$9 million increase in inventory in 2017.

▪	$ 84 million net increase in Insurance Receivable for Aliso Canyon Costs in 2018 compared to a $ 52 million net decrease in 2017. The $84 million net increase primarily includes $101 million of additional accruals, partially offset by $16 million in insurance proceeds received;

▪	$159 million decrease in accounts payable in 2018 compared to a $104 million decrease in 2017;

▪	$187 million decrease in accounts receivable in 2018 compared to a $234 million decrease in 2017;

▪	$64 million in purchases of GHG allowances in 2018 compared to $32 million in 2017; and

▪	$29 million increase in seasonal liability related to temporary LIFO liquidation in 2017, primarily due to changes in natural gas inventory value; offset by

▪	$138 million increase in net overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2018 compared to a $79 million increase in 2017;

▪	$56 million net increase in Reserve for Aliso Canyon Costs in 2018 compared to a $10 million increase in 2017. The $56 million net increase in 2018 includes $101 million of additional accruals, offset by $45 million of cash paid;

▪	$45 million decrease in inventory in 2018 compared to a $13 million decrease in 2017;

▪	$31 million increase in deferred revenue requirement due to the TCJA in 2018; and

▪	$16 million higher net income, adjusted for noncash items included in earnings, in 2018 compared to 2017.

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▪	$9.57 billion paid, including $9.45 billion of Merger Consideration, for the acquisition of our investment in Oncor Holdings in March 2018, as we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein;

▪	$ 139 million increase in capital expenditures; and

▪	$117 million cash contribution made to Oncor; offset by

▪	$99 million lower advances to unconsolidated affiliates; and

▪	$67 million higher repayments from advances to unconsolidated affiliates.

▪	$88 million increase in capital expenditures; and

▪	$31 million repayment received in 2017 from advances to Sempra Energy.

▪	$101 million increase in capital expenditures; offset by

▪	$84 million increase in net advances to Sempra Energy in 2017.

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▪	$5.5 billion higher issuances of debt with maturities greater than 90 days, primarily to fund the acquisition of our investment in

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◦	$4.6 billion for long-term debt ($5.8 billion in 2018 compared to $1.2 billion in 2017), and

◦	$882 million for commercial paper and other short-term debt ($1.6 billion in 2018 compared to $736 million in 2017);

▪	$2.1 billion proceeds, net of $38 million in offering costs, from issuances of common stock in 2018;

▪	$1.3 billion increase in short-term debt in 2018 compared to a $493 million decrease in 2017; and

▪	$1.7 billion proceeds, net of $32 million in offering costs, from the issuance of series A preferred stock in 2018; offset by

▪	$872 million higher payments of debt with maturities greater than 90 days, including:

◦	$518 million for commercial paper and other short-term debt ($717 million in 2018 compared to $199 million in 2017), and

◦	$354 million for long -term debt ($1.2 billion in 2018 compared to $807 million in 2017).

▪	$175 million common dividends paid in 2017; and

▪	$140 million lower payments of long-term debt in 2018; offset by

▪	$172 million decrease in short-term debt in 2018 compared to a $5 million increase in 2017.

▪	$400 million issuance of long-term debt in 2018; and

▪	$210 million increase in short-term debt in 2018, compared to a $62 million decrease in 2017; offset by

▪	$500 million payments of long-term debt in 2018.

(1)	We calculate expected interest payments using the stated interest rate for fixed-rate obligations. We calculate expected interest payments for variable-rate obligations based on forward rates in effect at June 30, 2018.

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▪	Electric Rate Reform – California Assembly Bill 327

▪	Potential Impacts of Community Choice Aggregation and Direct Access

▪	Renewable Energy Procurement

▪	Clean Energy and Pollution Reduction Act – California SB 350

▪	SONGS

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▪	Local Community Mitigation Efforts

▪	Insurance

▪	Governmental Investigations and Civil and Criminal Litigation

▪	Regulatory Proceedings

▪	Governmental Orders and Additional Regulation

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▪	SB 380

▪	SB 888

▪	Additional Safety Enhancements

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(1)	Excludes disallowed costs through June 30, 2018 of $7 million at SoCalGas and $4 million at SDG&E for pressure testing or replacing pipelines installed between January 1, 1956 and July 1, 1961. Also excludes $36 million of costs incurred for the PSRP.

(2)	Approved in December 2016; excludes $2 million of PSEP-specific insurance costs for which SoCalGas and SDG&E are authorized to request recovery in a future filing.

(3)	Reasonableness Review Application for completed projects totaling $195 million filed in September 2016. Also includes approximately $15 million of pre-engineering costs incurred to support projects under development and submitted as part of the Forecast Application filed in March 2017. Both decisions are expected in 2018.

(4)	Authorized to recover in rates 50 percent of the balances recorded in the PSEP Phase 1 balancing accounts each year, subject to refund.

(5)	Reasonableness Review Application to be filed in late 2018 and expected to include the majority of these costs. Remaining costs not the subject of prior applications are to be included for review in subsequent GRCs.

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▪	A majority of the independent directors of Oncor must approve any annual or multi-year budget if the aggregate amount of capital expenditures or O&M in such budget is more than a 10 percent increase or decrease from the corresponding amounts of such expenditures in the budget for the preceding fiscal year or multi-year period, as applicable;

▪	Oncor will make minimum aggregate capital expenditures equal to at least $7.5 billion over the period from January 1, 2018 through December 31, 2022 (subject to certain possible adjustments);

▪	Oncor may not pay any dividends or make any other distributions (except for contractual tax payments) if a majority of its independent directors or a minority member director determines that it is in the best interests of Oncor to retain such amounts to meet expected future requirements;

▪	At all times, Oncor will remain in compliance with the debt-to-equity ratio established by the PUCT from time to time for ratemaking purposes, and Oncor will not pay dividends or other distributions (except for contractual tax payments), if that payment would cause its debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT;

▪	If the credit rating on Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT;

▪

Without the prior approval of the PUCT, neither Sempra Energy nor any of its affiliates (excluding Oncor) will incur, guarantee or pledge assets in respect of any indebtedness that is dependent on the revenues of Oncor in more than a proportionate degree than the other revenues of Sempra Energy or on the stock of Oncor, and there will be no debt at Sempra Texas Holdings Corp. or Sempra Texas Intermediate Holding Company LLC at any time;

▪

Neither Oncor nor Oncor Holdings will lend money to or borrow money from Sempra Energy or any of its affiliates (other than Oncor subsidiaries), or any entity with a direct or indirect ownership interest in Oncor Holdings or Oncor, and neither Oncor Holdings nor Oncor will share credit facilities with Sempra Energy or any of its affiliates (other than Oncor subsidiaries), or any entity with a direct or indirect ownership interest in Oncor Holdings or Oncor;

▪

Oncor will not seek recovery in rates of any expenses or liabilities related to EFH’s bankruptcy, or (1) any tax liabilities resulting from EFH’s spinoff of its former subsidiary Texas Competitive Electric Holdings Company LLC, (2) any asbestos claims relating to non-Oncor operations of EFH or (3) any make-whole claims by holders of debt securities issued by EFH or EFIH, and Sempra Energy was required to and has filed with the PUCT a plan providing for the extinguishment of the liabilities described in items (1) through (3) above, which protects Oncor from any harm;

▪

There must be maintained certain “separateness measures” that reinforce the financial separation of Oncor from Sempra Energy, including a requirement that dealings between Oncor, Oncor Holdings and their subsidiaries and Sempra Energy, any of Sempra Energy’s other affiliates or any entity with a direct or indirect ownership interest in Oncor Holdings or Oncor, must be on an arm’s-length basis, limitations on affiliate transactions, separate recordkeeping requirements and a prohibition on pledging Oncor assets or stock for any entity other than Oncor;

▪	No transaction costs or transition costs related to the Merger (excluding Oncor employee time) will be borne by Oncor’s customers nor included in Oncor’s rates;

▪	Sempra Energy will continue to hold indirectly at least 51 percent of the ownership interests in Oncor Holdings and Oncor for at least five years following the closing of the Merger, unless otherwise specifically authorized by the PUCT; and

▪

Oncor will provide bill credits to customers in an amount equal to 90 percent of any interest rate savings achieved due to any improvement in its credit ratings or market spreads compared to those as of June 30, 2017 until final rates are set in the next Oncor base rate case filed after PUCT Docket No. 46957 (except that savings will not be included in credits if already realized in rates); and one year after the Merger, Oncor will provide bill credits to its customers equal to 90 percent of any synergy savings until final rates are set in the next Oncor base rate proceeding after PUCT Docket No. 46957, at which time any total synergy savings shall be reflected in Oncor’s rates.

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▪	two natural gas liquefaction trains with a nameplate capacity of 13.5 Mtpa of LNG and an expected export capability of approximately 11 Mtpa of LNG or 1.6 Bcf per day;

▪	up to three LNG storage tanks;

▪	natural gas liquids and refrigerant storage;

▪	feed gas pre-treatment facilities; and

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▪	two berths and associated marine and loading facilities.

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(1)	After the effects of interest rate swaps. Before the effects of acquisition-related fair value adjustments, reductions/increases for unamortized discount/premium and reduction for debt issuance costs, and excluding capital lease obligations and build-to-suit lease.

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