SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA (Policies)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

PRINCIPLES OF CONSOLIDATION

Sempra Energy

Sempra Energy’s Consolidated Financial Statements include the accounts of Sempra Energy, a California-based energy-services holding company, and its consolidated subsidiaries and VIEs. Sempra Global is the holding company for most of our subsidiaries that are not subject to California or Texas utility regulation. Sempra Energy’s businesses were managed within six separate reportable segments until April 2019 and five separate reportable segments thereafter, which we discuss in Note 17. In the first quarter of 2019, our Sempra LNG & Midstream segment was renamed “Sempra LNG.” This segment name change had no impact on our historical position, results of operations, cash flow or segment level results previously reported. All references in these Notes to our reportable segments are not intended to refer to any legal entity with the same or similar name.

SDG&E

SDG&E’s Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E was the primary beneficiary until August 23, 2019, at which time SDG&E deconsolidated the VIE, as we discuss below in “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova, which is a wholly owned subsidiary of Sempra Energy.

SoCalGas

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

In this report, we refer to SDG&E and SoCalGas collectively as the California Utilities.

Basis of Presentation

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 Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively:


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


▪	the Consolidated Financial Statements and related Notes of SDG&E and its VIE (until deconsolidation of the VIE in August 2019); and

▪

the Financial Statements and related Notes of SoCalGas.

Use of Estimates in the Preparation of the Financial Statements

We have prepared our Consolidated Financial Statements in conformity with U.S. GAAP. This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates.

Subsequent Events

We evaluated events and transactions that occurred after December 31, 2019 through the date the financial statements were issued, and in the opinion of management, the accompanying statements reflect all adjustments and disclosures necessary for a fair presentation.

Discontinued Operations

In January 2019, our board of directors approved a plan to sell our South American businesses based on our strategic focus on North America. We determined that these businesses, which previously constituted the Sempra South American Utilities segment, and certain activities associated with these businesses, met the held-for-sale criteria. These businesses are presented as discontinued operations, as the planned sales represent a strategic shift that will have a major effect on our operations and financial results. Throughout this report, the financial information for all periods presented has been adjusted to reflect the

presentation of these businesses as discontinued operations, which we discuss further in Note 5. Our discussions in the Notes below relate only to our continuing operations unless otherwise noted.

Effects of Regulation

EFFECTS OF REGULATION

The California Utilities’ accounting policies and financial statements reflect the application of U.S. GAAP provisions governing rate-regulated operations and the policies of the CPUC and the FERC. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from ratepayers, the excess would be refunded to customers, generally by reducing future rates. Regulatory liabilities may also arise from other transactions such as unrealized gains on fixed price contracts and other derivatives or certain deferred income tax benefits that are passed through to customers in future rates. In addition, the California Utilities record regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods.

Determining probability of recovery of regulatory assets requires significant judgment by management and may include, but is not limited to, consideration of:


▪	the nature of the event giving rise to the assessment


▪	existing statutes and regulatory code


▪	legal precedents


▪	regulatory principles and analogous regulatory actions


▪	testimony presented in regulatory hearings


▪	regulatory orders


▪	a commission-authorized mechanism established for the accumulation of costs


▪	status of applications for rehearings or state court appeals


▪	specific approval from a commission


▪	historical experience

Sempra Mexico’s natural gas distribution utility, Ecogas, also applies U.S. GAAP for rate-regulated utilities to its operations, including the same evaluation of probability of recovery of regulatory assets described above.

We provide information concerning regulatory assets and liabilities in Note 4.

Our Sempra Texas Utilities segment is comprised of our equity method investments in Oncor Holdings, which, at December 31, 2019, owns an 80.25% interest in Oncor, and Sharyland Holdings, which owns 100% of Sharyland Utilities. Oncor and Sharyland Utilities are regulated electric transmission and distribution utilities in Texas and their rates are regulated by the PUCT and certain cities and are subject to regulatory rate-setting processes and annual earnings oversight. Oncor and Sharyland Utilities prepare their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations.

Our Sempra Mexico segment includes the operating companies of our subsidiary, IEnova, as well as certain holding companies and risk management activity. Certain business activities at IEnova are regulated by the CRE and meet the regulatory accounting requirements of U.S. GAAP. Pipeline projects currently under construction at IEnova that meet the regulatory accounting requirements of U.S. GAAP record the impact of AFUDC related to equity. We discuss AFUDC below in “Property, Plant and Equipment.”

Fair Value Measurements

FAIR VALUE MEASUREMENTS

We measure certain assets and liabilities at fair value on a recurring basis, primarily nuclear decommissioning and benefit plan trust assets and derivatives. We also measure certain assets at fair value on a non-recurring basis in certain circumstances.

A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value.

We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 – Pricing inputs are unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities and U.S. government treasury securities, primarily in the NDT and benefit plan trusts, and exchange-traded derivatives.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including:


▪	quoted forward prices for commodities


▪	time value


▪	current market and contractual prices for the underlying instruments


▪	volatility factors


▪	other relevant economic measures

Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as interest rate instruments and over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs and fixed-price electricity positions at SDG&E.

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.

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 December 31, 2019 and 2018. 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-valued assets and liabilities, and their placement within the fair value hierarchy.

The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 11 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 in the tables below include the following (other than a $5 million and $10 million investment at December 31, 2019 and 2018, respectively, measured at NAV):

▪

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 or income 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 December 31, 2019 and 2018.

Cash and Cash Equivalents and Restricted Cash

CASH, CASH EQUIVALENTS AND RESTRICTED CASH

Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase.

Collection Allowances

COLLECTION ALLOWANCES

We record allowances for the collection of trade and other accounts and notes receivable, which include allowances for doubtful customer accounts and for other receivables.

We evaluate accounts receivable collectability using a combination of factors, including past due status based on contractual terms, trends in write-offs, the age of the receivable, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies. Adjustments to collection allowances are made when necessary based on the results of analysis, the aging of receivables, and historical and industry trends.

We write off accounts receivable in the period in which we deem the receivable to be uncollectible. We record recoveries of accounts receivable previously written off when it is known that they will be received.

Inventories

INVENTORIES

The California Utilities value natural gas inventory using the LIFO method. As inventories are sold, differences between the LIFO valuation and the estimated replacement cost are reflected in customer rates. These differences are generally temporary, but may become permanent if the natural gas inventory withdrawn from storage during the year is not replaced by year end. The California Utilities generally value materials and supplies at the lower of average cost or net realizable value.

Sempra Mexico and Sempra LNG value natural gas inventory and materials and supplies at the lower of average cost or net realizable value. Sempra Mexico and Sempra LNG value LNG inventory using the first-in first-out method.

Income Taxes

INCOME TAXES

Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. ITCs from prior years are amortized to income by the California Utilities over the estimated service lives of the properties as required by the CPUC.

Under the regulatory accounting treatment required for flow-through temporary differences, the California Utilities and Sempra Mexico recognize:


▪	regulatory assets to offset deferred income tax liabilities if it is probable that the amounts will be recovered from customers; and


▪	regulatory liabilities to offset deferred income tax assets if it is probable that the amounts will be returned to customers.

When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to have at least a more-likely-than-not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more-likely-than-not” means a likelihood of more than 50%. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the more-likely-than-not criterion at the largest amount of tax benefit that is greater than 50% likely of being realized upon its effective resolution.

Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR.

In December 2017, the TCJA was signed into law. As a result, all cumulative undistributed earnings from non-U.S. subsidiaries were deemed repatriated and subjected to a one-time U.S. federal deemed repatriation tax. To the extent we intend to repatriate cash to the U.S. from our continuing international operations, we accrue incremental income tax. We currently do not record deferred income taxes for other basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries to the extent the related cumulative undistributed earnings are indefinitely reinvested. We recognize income tax expense for basis differences related to global intangible low-taxed income as a period cost if and when incurred.

We provide additional information about income taxes in Note 8.

Related to operations in Mexico.

In December 2017, the TCJA was signed into law. This legislation significantly changed the IRC. The TCJA reduced the U.S. statutory corporate income tax rate from 35% to 21%, effective January 1, 2018. Deferred income tax assets and liabilities, including NOLs, were remeasured at the income tax rate expected to apply when those temporary differences reverse. The effects of the change to the income tax rate were recognized in the period when the change was enacted. This remeasurement resulted in significant reductions in deferred income tax balances at Sempra Energy Consolidated, SDG&E and SoCalGas in 2017.

The remeasurement of deferred income tax balances at SDG&E and SoCalGas resulted in excess deferred income taxes that previously have been collected from ratepayers at the higher rate. As we discuss in Note 4, these excess deferred income taxes have been recorded as regulatory liabilities and will generally be refunded to ratepayers in accordance with the IRC’s normalization provisions and as determined by the CPUC and the FERC. In a January 2019 decision, the CPUC directed certain excess deferred income tax balances generated by activities outside of ratemaking be allocated to shareholders rather than ratepayers. As a result, SDG&E and SoCalGas recorded income tax benefits of $31 million and $38 million, respectively, from the release of a portion of the regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances.

The TCJA imposed a one-time tax for deemed repatriation of cumulative undistributed earnings of non-U.S. subsidiaries. In addition to the deemed repatriation tax, we accrued U.S. state and non-U.S. withholding tax on our expected future repatriati

Greenhouse Gas Allowances and Obligations and Emissions and Renewable Energy Certificates

GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS

The California Utilities, Sempra Mexico and Sempra LNG are required by AB 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas transportation. At the California Utilities, many GHG allowances are allocated to us on behalf of our customers at no cost. We record purchased and allocated GHG allowances at the lower of weighted-average cost or market. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. The California Utilities balance costs and revenues associated with the GHG program through regulatory balancing accounts. Sempra Mexico and Sempra LNG record the cost of GHG obligations in cost of sales. We remove the assets and liabilities from the balance sheets as the allowances are surrendered.

RENEWABLE ENERGY CERTIFICATES

RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.

Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market to comply with the RPS established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS. The cost of RECs at SDG&E, which is recoverable in rates, is recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations.

Property, Plant and Equipment (PP&E)

The California Utilities finance their construction projects with debt and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of PP&E. The California Utilities earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from their customers over the expected useful lives of the assets.

Pipeline projects currently under construction by Sempra Mexico that are both subject to certain regulation and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC.

We capitalize interest costs incurred to finance capital projects and interest at equity method investments that have not commenced planned principal operations.

PROPERTY, PLANT AND EQUIPMENT

PP&E is recorded at cost and primarily represents the buildings, equipment and other facilities used by the California Utilities to provide natural gas and electric utility services, and by the Sempra Global businesses in their operations, including construction work in progress. PP&E also includes lease improvements and other equipment at Parent and Other. Our plant costs include labor, materials and contract services and expenditures for replacement parts incurred during a major maintenance outage of a plant. In addition, the cost of utility plant at our rate-regulated businesses and PP&E under regulated projects that meet the regulatory accounting requirements of U.S. GAAP includes AFUDC. The cost of other PP&E includes capitalized interest. Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage value is charged to accumulated depreciation.

Depreciation expense is computed using the straight-line method over the asset’s estimated composite useful life, the CPUC-prescribed period for the California Utilities, or the remaining term of the site leases, whichever is shortest.

Goodwill and Other Intangible Assets

Other Intangible Assets at December 31, 2019 primarily includes:


▪	a renewable energy transmission and consumption permit previously granted by the CRE that was acquired in connection with the acquisition of the Ventika wind power generation facilities; and

▪

a favorable O&M agreement acquired in connection with the acquisition of DEN, which we discuss in Note 5

GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized, but we test it for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, and the book value of goodwill is greater than its fair value on the test date, we record a goodwill impairment loss.

For our annual goodwill impairment testing, under current U.S. GAAP guidance we have the option to first make a qualitative assessment of whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount before applying the two-step, quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors, changes in key personnel and the overall financial performance of the reporting unit. If, after assessing these

qualitative factors, we determine that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, then we perform the two-step goodwill impairment test. When we perform the two-step, quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and the corresponding goodwill. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include:


▪	consideration of market transactions


▪	future cash flows


▪	the appropriate risk-adjusted discount rate


▪	country risk

▪

entity risk

Long-lived Assets

LONG-LIVED ASSETS

We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated entities. Events or changes in circumstances that indicate that the carrying amount of a long-lived asset may not be recoverable may include:


▪	significant decreases in the market price of an asset;


▪	a significant adverse change in the extent or manner in which we use an asset or in its physical condition;


▪	a significant adverse change in legal or regulatory factors or in the business climate that could affect the value of an asset;


▪	a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection of continuing losses associated with the use of a long-lived asset; and


▪	a current expectation that, more-likely-than-not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

A long-lived asset may be impaired when the estimated future undiscounted cash flows are less than the carrying amount of the asset. If that comparison indicates that the asset’s carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the asset. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

Variable Interest Entities

VARIABLE INTEREST ENTITIES

We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based on 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 whether an entity is a VIE and if we are the primary beneficiary.

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

For tangible long-lived assets, we record AROs for the present value of liabilities of future costs expected to be incurred when assets are retired from service, if the retirement process is legally required and if a reasonable estimate of fair value can be made. We also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated, but performance is conditional upon a future event. We record the estimated retirement cost over the life of the related asset by depreciating the asset retirement cost (measured as the present value of the obligation at the time the asset is placed into service), and accreting the obligation until the liability is settled. Our rate-regulated entities, including the California Utilities, record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through the rate-making process.

Contingencies

CONTINGENCIES

We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and:


▪	information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and


▪	the amount of the loss can be reasonably estimated.

We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.

Legal Fees

LEGAL FEES

Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred and amounts are estimable.

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.

Comprehensive Income

COMPREHENSIVE INCOME

Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including:


▪	foreign currency translation adjustments


▪	certain hedging activities


▪	changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans


▪	unrealized gains or losses on available-for-sale securities

The Consolidated Statements of Comprehensive Income (Loss) show the changes in the components of OCI, including the amounts attributable to NCI.

Noncontrolling Interests

NONCONTROLLING INTERESTS

Ownership interests in a consolidated entity that are held by unconsolidated owners are accounted for and reported as NCI.

Operation and Maintenance Expenses

OPERATION AND MAINTENANCE EXPENSES

Operation and Maintenance includes O&M and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, litigation expense and rent.

Foreign Currency Translation

FOREIGN CURRENCY TRANSLATION AND TRANSACTIONS

The majority of our operations in South America as well as our natural gas distribution utility in Mexico, Ecogas, use their local currency as their functional currency. The assets and liabilities of their foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the year. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings, but are reflected in OCI and in AOCI.

Cash flows of these consolidated foreign subsidiaries are translated into U.S. dollars using average exchange rates for the period. We report the effect of exchange rate changes on cash balances held in foreign currencies in “Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash” on the Sempra Energy Consolidated Statements of Cash Flows.

New Accounting Standards

NEW ACCOUNTING STANDARDS

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 2016-02, “Leases,” ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” ASU 2018-10, “Codification Improvements to Topic 842, Leases,” ASU 2018-11, “Leases (Topic 842): Targeted Improvements,” ASU 2018-20, “Narrow-Scope Improvements for Lessors” and ASU 2019-01, “Leases (Topic 842): Codification Improvements” (collectively referred to as the “lease standard”): In 2016, the Financial Accounting Standards Board began issuing the first in a series of ASUs intended to increase transparency and comparability among organizations with leasing activities. The most significant provision of the lease standard is the requirement that lessees recognize operating lease ROU assets and lease liabilities on the balance sheet.

We adopted the lease standard on January 1, 2019 using the optional modified retrospective transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. We elected the package of practical expedients that permits us to not reassess (a) whether a contract is or contains a lease, (b) lease classification or (c) determination of initial direct costs, which allows us to carry forward accounting conclusions under previous U.S. GAAP on contracts that commenced prior to adoption of the lease standard. We also elected the land easement practical expedient, which allows us to continue to account for pre-existing land easements under our accounting policy that existed before adoption of the lease standard. We did not elect the practical expedient to use hindsight in making judgments when determining the lease term.

The adoption of the lease standard did not change our previously reported financial statements. However, in accordance with the lease standard, on a prospective basis, a significant portion of finance lease costs for PPAs that have historically been presented in

Cost of Electric Fuel and Purchased Power are now presented in Depreciation and Amortization Expense and Interest Expense on Sempra Energy’s and SDG&E’s statements of operations. Additionally, the adoption of the lease standard had a material impact on our balance sheets at January 1, 2019 due to the initial recognition of ROU assets and lease liabilities for operating leases. Our finance leases were already included on our balance sheets prior to adoption of the lease standard, consistent with previous U.S. GAAP for capital leases.

The following table shows the initial increases (decreases) on our balance sheets at January 1, 2019 from adoption of the lease standard.



IMPACT FROM ADOPTION OF THE LEASE STANDARD
(Dollars in millions)
	Sempra Energy Consolidated			SDG&E		SoCalGas
Assets held for sale	$	13		$	—	$	—
Other long-term assets	(71		)	—		—
Property, plant and equipment, net	(147		)	—		—
Right-of-use assets – operating leases	603			130		116
Deferred income tax assets	(3		)	—		—
Other current liabilities	80			20		23
Long-term debt and finance leases	(138		)	—		—
Deferred credits and other	436			110		93
Retained earnings	17			—		—

As a result of the adoption of the lease standard, we derecognized the asset and liability associated with our corporate headquarters building in accordance with the transition provisions for build-to-suit arrangements. On a prospective basis, we will account for the corporate headquarters building lease as an operating lease. The initial impact is included in the above table.

We include additional disclosures about our leases in Note 16.

ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13, as amended by subsequently issued ASUs, 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.

On a prospective basis, the new standard will primarily apply to our accounts receivable balances, amounts due from unconsolidated affiliates and off-balance sheet financial guarantees. We will adopt the standard on January 1, 2020.

We expect no impact to SDG&E’s or SoCalGas’ balance sheets from adoption. The following table shows the expected (decreases) increases on Sempra Energy’s balance sheet at January 1, 2020 from adoption of ASU 2016-13.



EXPECTED IMPACT FROM ADOPTION OF ASU 2016-13
(Dollars in millions)
	Sempra Energy Consolidated
Accounts receivable – trade, net	$	(1	)
Due from unconsolidated affiliates – noncurrent	(6		)
Deferred income tax assets	4
Other current liabilities	4
Deferred credits and other	2
Retained earnings	(7		)
Other noncontrolling interests	(2		)

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 will adopt the standard on January 1, 2020.

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 is 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. We adopted ASU 2018-02 on January 1, 2019 and reclassified the income tax effects of the TCJA from AOCI to retained earnings.

The impact from adoption of ASU 2018-02 on January 1, 2019 was as follows:


▪	Sempra Energy: increase of $40 million to beginning Retained Earnings, $2 million to noncurrent Regulatory Liabilities and $42 million to Accumulated Other Comprehensive Loss;


▪	SDG&E: increase of $2 million to beginning Retained Earnings and Accumulated Other Comprehensive Loss; and


▪	SoCalGas: increase of $2 million to beginning Retained Earnings, $2 million to noncurrent Regulatory Liabilities and $4 million to Accumulated Other Comprehensive Loss.

ASU 2019-12, “Simplifying the Accounting for Income Taxes”: ASU 2019-12 simplifies certain areas of accounting for income taxes. In addition to other changes, this standard amends ASC 740, “Income Taxes,” as follows:


▪	removes the exception to the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items, including discontinued operations or other comprehensive income;


▪	simplifies the recognition of deferred taxes related to basis differences as a result of ownership changes in investments;


▪	specifies an entity is not required to allocate the consolidated amount of current and deferred tax expense to a legal entity that is not subject to tax in its separate financial statements; and


▪	requires an entity to reflect the effect of an enacted change in tax laws or rates in the annual ETR computation in the interim period that includes the enactment date.

For public entities, ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, including interim periods therein, with early adoption permitted. The transition method related to the amendments made by ASU 2019-12 vary based on the nature of the change. We are currently evaluating our planned adoption date and the effect of the standard on our ongoing financial reporting.

NEW ACCOUNTING STANDARDS

We describe below and in Note 2 of the Notes to Consolidated Financial Statements recent pronouncements that have had a significant effect on Sempra Energy’s financial condition, results of operations, cash flows or disclosures.

ASU 2016-02, “Leases,” ASU 2018-10, “Codification Improvements to Topic 842, Leases” and ASU 2018-11, “Leases (Topic 842): Targeted Improvements” (collectively referred to as the “lease standard”): We adopted the lease standard on January 1, 2019 using the optional modified retrospective transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. The adoption of the lease standard had a material impact on our balance sheet at January 1, 2019 due to the initial recognition of ROU assets and lease liabilities for operating leases.

The following table shows the increases (decreases) on our balance sheet at January 1, 2019 from adoption of the lease standard.



IMPACT FROM ADOPTION OF THE LEASE STANDARD
(Dollars in millions)
Right-of-use assets – operating leases⁽¹⁾	$	191
Deferred income tax assets	(3		)
Property, plant and equipment, net⁽¹⁾	(147		)
Other current liabilities	3
Long-term debt	(138		)
Other long-term liabilities	159
Retained earnings⁽²⁾	17


⁽¹⁾	Included in Other Long-Term Assets.


⁽²⁾	Included in Shareholders’ Equity.

ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: We adopted ASU 2018-02 on January 1, 2019 and reclassified the income tax effects of the TCJA from AOCI to retained earnings. The impact from adoption of ASU 2018-02 on January 1, 2019 was an increase of $14 million to beginning Retained Earnings and Accumulated Other Comprehensive Loss.


▪	removes the exception to the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items, including discontinued operations or other comprehensive income;


▪	simplifies the recognition of deferred taxes related to basis differences as a result of ownership changes in investments;


▪	specifies an entity is not required to allocate the consolidated amount of current and deferred tax expense to a legal entity that is not subject to tax in its separate financial statements; and


▪	requires an entity to reflect the effect of an enacted change in tax laws or rates in the annual ETR computation in the interim period that includes the enactment date.

Revenue from Contract with Customer

Our revenues from contracts with customers are primarily related to the transmission, distribution and storage of natural gas and the generation, transmission and distribution of electricity through our regulated utilities. We also provide other midstream and renewable energy-related services. We assess our revenues on a contract-by-contract basis 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 natural gas and electricity and providing of natural gas storage services as ongoing and integrated services. Generally, natural gas or electricity 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 natural gas or electricity 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.

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 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 transmission, distribution and storage of natural gas at:


▪	SDG&E


▪	SoCalGas


▪	Sempra Mexico’s Ecogas

The generation, transmission and distribution of electricity at SDG&E.

Utilities revenues are derived from and recognized upon the delivery of natural gas or electricity 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 operating costs 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 the FERC. Revenue is recognized over time as access is provided to the California ISO.

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.

Energy-Related Businesses Revenues

Midstream Revenues

Midstream revenues at Sempra Mexico and Sempra LNG 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 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’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 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, Sempra LNG records the related costs as an offset to revenues, with no impact to Sempra Energy’s consolidated 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 February 7, 2019, Sempra LNG completed the sale of its non-utility natural gas storage assets in the southeast U.S. (comprised of Mississippi Hub and Bay Gas).

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, in December 2018, we completed the sale of Sempra Renewables’ U.S. operating solar assets, solar and battery storage development projects and its 50% ownership interest in a wind power generation facility. In April 2019, Sempra Renewables completed the sale of its remaining wind assets and investments.

Sempra LNG continues to have a contractual agreement to provide scheduling and marketing of renewable power for Sempra Mexico’s renewables’ entities. Invoiced amounts are based on a fixed fee per MWh scheduled.

Other Revenues from Contracts with 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) variable consideration 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 December 31, 2019, we expect to recognize revenue related to the fixed fee component of the consideration as shown below. Sempra Energy’s remaining performance obligations primarily relate to capacity agreements for natural gas storage and transportation at Sempra Mexico. SoCalGas did not have any remaining performance obligations at December 31, 2019.

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 natural gas and electricity 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 IOUs, 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, and the FERC as it relates to SDG&E, authorize the California Utilities to collect revenue requirements for operating costs and capital related costs (such as depreciation, taxes and return on rate base) from customers, including:


▪	costs to purchase natural gas and electricity;


▪	costs associated with administering public purpose, demand response, and customer energy efficiency programs;


▪	other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation; and


▪	costs associated with third party liability insurance premiums.

Authorized costs are recovered as the commodity or service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded within a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met at the time the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may impose various review procedures before authorizing recovery or refund for programs authorized, 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.

We discuss balancing accounts and their effects further in Note 4.

Other Revenues

Sempra LNG has an agreement to supply LNG to Sempra Mexico’s ECA LNG Regasification 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 is contractually required to make monthly indemnity payments to Sempra Mexico for failure to deliver the contracted LNG.

Sempra Mexico generates lease revenues from operating lease agreements with PEMEX and CENAGAS for the use of natural gas and ethane pipelines and LPG storage facilities. Certain PPAs at Sempra Renewables were also accounted for as operating leases prior to sale of its solar and wind assets in December 2018 and April 2019.

Sempra LNG also recognizes other revenues from:


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

▪

sales of natural gas and electricity 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.

Business Combinations

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.

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.

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

Investments in Noncontrolling Interests

Oncor is a domestic partnership for U.S. federal income tax purposes and is not included in the consolidated income tax return of Sempra Energy. Rather, only our pretax 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 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.

We generally account for investments under the equity method when we have significant influence over, but do not have control of, these entities. Equity earnings and losses, both before and net of income tax, are combined and presented as Equity Earnings on the Consolidated Statements of Operations.

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) Benefit on the Consolidated Statement of Operations. Our foreign equity method investees are corporations whose operations are generally taxable on a standalone basis in the countries in which they operate, and we recognize our equity in such income or loss net of investee income tax. See Note 8 for information on how equity earnings and losses before income taxes are factored into the calculations of our pretax income or loss and ETR.

Employee Benefit Plans

For our employee benefit plans, we:


▪	recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the balance sheet;


▪	measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year; and


▪	recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity.

The detailed information presented below covers the employee benefit plans of primarily Sempra Energy and its consolidated subsidiaries.

Sempra Energy has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E and SoCalGas, which collectively cover all eligible employees, including members of the Sempra Energy board of directors who were participants in a predecessor plan on or before June 1, 1998. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology.

IEnova has an unfunded noncontributory defined benefit plan covering all employees that provides defined benefits to retirees based on date of hire, years of service and final average earnings.

Sempra Energy also has PBOP plans, including separate plans for SDG&E and SoCalGas, which collectively cover all domestic and certain foreign employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. Other postretirement benefits include medical benefits for retirees’ spouses.

Pension and other postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. We review these assumptions on an annual basis and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions. We use a December 31 measurement date for all of our plans.

Net Assets and Liabilities

The assets and liabilities of the pension and PBOP plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and other postretirement benefit costs over a period of years. Our funded pension and PBOP plans use the asset smoothing method, except for those at SDG&E. This method develops an asset value that recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used in conjunction with an expected long-term rate of return to determine the expected return-on-assets component of net periodic benefit cost. SDG&E does not use the asset smoothing method, but rather recognizes realized and unrealized investment gains and losses during the current year.

The 10% corridor accounting method is used at Sempra Energy Consolidated, SDG&E and SoCalGas. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of

active participants. The asset smoothing and 10% corridor accounting methods help mitigate volatility of net periodic benefit costs from year to year.

We recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets or liabilities, respectively; unrecognized changes in these assets and/or liabilities are normally recorded in AOCI on the balance sheet. The California Utilities record regulatory assets and liabilities that offset the funded pension and other postretirement plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on decisions by regulatory agencies.

The California Utilities record annual pension and other postretirement net periodic benefit costs equal to the contributions to their qualified plans as authorized by the CPUC. The annual contributions to the pension plans are the greater of:


▪	a minimum required funding amount as required by the IRS;


▪	the amount required to maintain an 85% Adjusted Funding Target Attainment Percentage as defined by the Pension Protection Act of 2006, as amended; or

▪

beginning January 1, 2019 and for the duration of the 2019 GRC cycle, a fixed amount equal to the estimated annual service cost as defined by U.S. GAAP plus one year of a 14-year amortization of the unfunded projected benefit obligation of the pension plan as of January 1, 2019, and limited to an annual amount that keeps the fair value of the pension plan assets from exceeding 110% of the pension benefit obligation of the plan.

The annual contributions to PBOP plans are equal to the lesser of the maximum tax deductible amount or the net periodic cost calculated in accordance with U.S. GAAP for pension and PBOP plans. Any differences between booked net periodic benefit cost and amounts contributed to the pension and other postretirement plans for the California Utilities are disclosed as regulatory adjustments in accordance with U.S. GAAP for rate-regulated entities.

Assumptions for Pension and Other Postretirement Benefit Plans

Benefit Obligation and Net Periodic Benefit Cost

Except for the IEnova plans, we develop the discount rate assumptions using a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flows to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of corporate bonds with a Bloomberg Composite of AA or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plans’ projected benefit payments discounted at this rate with the market value of the bonds selected.

We develop the discount rate assumptions for the plans at IEnova by constructing a synthetic government zero coupon bond yield curve from the available market data, based on duration matching, and we add a risk spread to allow for the yields of high-quality corporate bonds. Such method is required when there is no deep market for high quality corporate bonds.

Long-term return on assets is based on the weighted-average of the plans’ investment allocation as of the measurement date and the expected returns for those asset types.

Interest crediting rate is based on an average 30-year Treasury bond from the month of November of the preceding year.

We amortize prior service cost using straight line amortization over average future service (or average expected lifetime for plans where participants are substantially inactive employees), which is an alternative method allowed under U.S. GAAP.

Fair Value of Pension and Other Postretirement Benefit Plan Assets

We classify the investments in Sempra Energy’s pension master trust and the trusts for the California Utilities’ PBOP plans based on the fair value hierarchy, except for certain investments measured at NAV.

The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and other postretirement benefit plan trusts.

Equity Securities – Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.

Fixed Income Securities – Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information.

Registered Investment Companies – Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy. Investments in certain fixed income securities are valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks for the remaining fixed income securities.

Common/Collective Trusts – Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets.

Private Equity Funds – These funds consist of investments in private equities that are held by limited partnerships following various strategies, including private equity and corporate finance. These partnerships generally have limited lives of 10 years, after which liquidating distributions will be received. The value is determined based on the NAV of the proportionate share of an ownership interest in partners’ capital. Holdings in these types of private equity funds are negligible, as the funds are well past their expected investment term and have distributed the bulk of proceeds from investment sales.

Derivative Financial Instruments – Futures contracts that are publicly traded in active markets are valued at closing prices as of the last business day of the year. Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index futures contracts are valued at the last sales price quoted on the exchange on which they primarily trade.

While management believes the valuation methods described above are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

We provide more discussion of fair value measurements in Notes 1 and 12. The following tables set forth by level within the fair value hierarchy a summary of the investments in our pension and other postretirement benefit plan trusts measured at fair value on a recurring basis.

Share-based Compensation

Our practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases.We measure and recognize compensation expense for all share-based payment awards made to our employees and directors based on estimated fair values on the date of grant. We recognize compensation costs net of an estimated forfeiture rate (based on historical experience) and recognize the compensation costs for nonqualified stock options and RSUs on a straight-line basis over the requisite service period of the award, which is generally three or four years. However, for awards granted to retirement-eligible participants, the expense is recognized over the initial year in which the award was granted as the award requires service through the end of the year in which it was granted. For awards granted to participants who become eligible for retirement during the requisite service period, the expense is recognized over the period between the date of grant and the later of the end of the year in which the award was granted or the date the participant first becomes eligible for retirement. Substantially all awards outstanding are classified as equity instruments; therefore, we recognize additional paid in capital as we recognize the compensation expense associated with the awards.

SEMPRA ENERGY NONQUALIFIED STOCK OPTIONS

We use a Black-Scholes option-pricing model to estimate the fair value of each nonqualified stock option grant. The use of a valuation model requires us to make certain assumptions about selected model inputs. Expected volatility is calculated based on a blend of the historical and implied volatility of Sempra Energy’s common stock price. The average expected term for options is based on the vesting schedule, contractual term of the option, expected employee exercise and post-termination behavior. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected term estimated at the date of the grant.

SEMPRA ENERGY RESTRICTED STOCK UNITS

We use a Monte-Carlo simulation model to estimate the fair value of our RSUs that vest based on Sempra Energy’s total return to shareholders. Our determination of fair value is affected by the historical volatility of the common stock price for Sempra Energy and its peer group companies. The valuation also is affected by the risk-free rates of return and a number of other variables.

Derivative Financial Instruments

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 Consolidated Balance Sheets. We have derivatives that are (1) cash flow hedges, (2) fair value hedges, 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 hedges), on the balance sheet (regulatory offsets), or recognized in earnings (fair value hedges). 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 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.

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 Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.

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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 Consolidated Statements of Operations.

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Sempra Mexico and Sempra LNG 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 Energy-Related Businesses Cost of Sales on the 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 Consolidated Statements of Operations.

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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.

FOREIGN CURRENCY DERIVATIVES

We utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and JVs. 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 JVs 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 JVs, 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 for inflation.

We also utilize foreign currency derivatives to hedge exposure to fluctuations in the Peruvian Sol related to the sale of our operations in Peru.

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 JVs, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. 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 entered into interest rate swap agreements, designated as cash flow hedges, to moderate its exposure to interest rate changes.

Earnings Per Share

The potentially dilutive impact from stock options 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.

Basic EPS is calculated by dividing earnings attributable to common shares (from both continuing and discontinued operations) 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.

Leases

Certain of our contracts are short-term leases, which have a lease term of 12 months or less at lease commencement. We do not recognize a lease liability or ROU asset arising from short-term leases for all existing classes of underlying assets. In such cases, we recognize short-term lease costs on a straight-line basis over the lease term. Our short-term lease costs for the period reasonably reflect our short-term lease commitments.

As of the lease commencement date, we recognize a lease liability for our obligation to make future lease payments, which we initially measure at present value using our incremental borrowing rate at the date of lease commencement, unless the rate implicit in the lease is readily determinable. We determine our incremental borrowing rate based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We also record a ROU asset for our right to use the underlying asset, which is initially equal to the lease liability and adjusted for lease payments made at or before lease commencement, lease incentives, and any initial direct costs. Like other long-lived assets, we test ROU assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the ROU assets.

For our operating leases, our non-regulated entities recognize a single lease cost on a straight-line basis over the lease term in operating expenses. The California Utilities recognize this single lease cost on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.

For our finance leases, the interest expense on the lease liability and amortization of the ROU asset are accounted for separately. Our non-regulated entities use the effective interest rate method to account for the imputed interest on the lease liability and amortize the ROU asset on a straight-line basis over the lease term. The California Utilities recognize amortization of the ROU asset on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.

Lessor, Leases

Generally, we recognize operating lease income on a straight-line basis over the lease term and evaluate the underlying asset for impairment. Certain of our leases contain rate adjustments or are based on foreign currency exchange rates that may result in lease payments received that vary from one period to the next.

Environmental Costs

We generally capitalize the significant costs we incur to mitigate or prevent future environmental contamination or extend the life, increase the capacity, or improve the safety or efficiency of property used in current operations. The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:

We record the present value of environmental liabilities when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and cleanups proceed, we make adjustments as necessary.

At the California Utilities, costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.

The environmental issues currently facing us, except for those related to the Aliso Canyon natural gas storage facility leak as we discuss above or resolved during the last three years, include (1) investigation and remediation of the California Utilities’ manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by the California Utilities at which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS.

Segment Reporting

We have five 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.

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Sempra Texas Utilities holds our investment in Oncor Holdings, which, at December 31, 2019, owns an 80.25% interest in Oncor, a regulated electric transmission and distribution utility serving customers in the north-central, eastern and western and panhandle regions of Texas, and our indirect, 50% interest in Sharyland Holdings, which owns a regulated electric transmission and distribution utility serving customers near the Texas-Mexico border. As we discuss in Note 5, we acquired our investment in Oncor Holdings in March 2018 and Sharyland Holdings in May 2019.


▪	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 LNG (previously known as Sempra LNG & Midstream) develops projects for the export of LNG, holds an interest in a facility for the export of LNG, owns and operates natural gas pipelines, and buys, sells and transports natural gas through its

marketing operations, all within the U.S. and Mexico. In February 2019, we completed the sale of our natural gas storage assets at Mississippi Hub and Bay Gas.

In December 2018, Sempra Renewables completed the sale of all its operating solar assets, solar and battery storage development projects and one wind generation facility. In April 2019, Sempra Renewables completed the sale of its remaining wind assets and investments. Upon completion of this sale, remaining nominal business activities at Sempra Renewables were subsumed into Parent and other and the Sempra Renewables segment ceased to exist. The tables below include amounts from Sempra Renewables up until cessation of the segment.

As we discuss in Note 5, the financial information related to our businesses that constituted the Sempra South American Utilities segment has been reclassified to discontinued operations for all periods presented. The information in the tables below excludes amounts from discontinued operations unless otherwise noted.

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 and the FERC. We describe the accounting policies of all of our segments in Note 1.

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.