SOUTHERN CALIFORNIA GAS CO - Annual Report: 2019 (Form 10-K)

---

---

---

---

---

---

---

---

▪	California wildfires and the risk that we may be found liable for damages regardless of fault and the risk that we may not be able to recover any such costs from insurance, the Wildfire Fund or in rates from customers;

▪	decisions, investigations, regulations, issuances of permits and other authorizations, renewal of franchises, and other actions by the CFE, CPUC, DOE, PUCT, regulatory and governmental bodies and jurisdictions in the U.S. and other countries in which we operate;

▪

the success of business development efforts, construction projects and major acquisitions and divestitures, including risks in (i) the ability to make a final investment decision and completing construction projects on schedule and budget; (ii) obtaining the consent of partners; (iii) counterparties’ financial or other ability to fulfill contractual commitments; (iv) the ability to complete contemplated acquisitions and/or divestitures; and (v) the ability to realize anticipated benefits from any of these efforts once completed;

▪	the resolution of civil and criminal litigation, regulatory investigations and proceedings and arbitrations;

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

▪	moves to reduce or eliminate reliance on natural gas;

▪

weather, natural disasters, accidents, equipment failures, computer system outages and other events that disrupt our operations, damage our facilities and systems, cause the release of harmful materials, cause fires and subject us to liability for property damage or personal injuries, fines and penalties, some of which may not be covered by insurance (including costs in excess of applicable policy limits), may be disputed by insurers or may otherwise not be recoverable through regulatory mechanisms or may impact our ability to obtain satisfactory levels of affordable insurance;

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

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

▪	expropriation of assets, the failure of foreign governments and state-owned entities to honor the terms of contracts, and property disputes;

▪	the impact at SDG&E on competitive customer rates and reliability due to the growth in distributed power generation and from departing retail load resulting from customers transferring to DA, CCA or other forms of distributed power generation and the risk of nonrecovery for stranded assets and contractual obligations;

▪	Oncor’s ability to eliminate or reduce its quarterly dividends due to regulatory and governance requirements and commitments, including by actions of Oncor’s independent directors or a minority member director;

▪	volatility in foreign currency exchange, interest and inflation rates and commodity prices and our ability to effectively hedge the risk of such volatility;

▪	changes in trade policies, laws and regulations, including tariffs and revisions to or replacement of international trade agreements, such as the NAFTA, that may increase our costs or impair our ability to resolve trade disputes;

▪	the impact of changes to federal and state tax laws and our ability to mitigate adverse impacts; and

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

---

---

▪	Sempra Energy and its consolidated entities

▪	SDG&E and its consolidated VIE (until deconsolidation of the VIE on August 23, 2019)

▪	SoCalGas

▪	SDG&E

▪	SoCalGas

▪	Sempra Texas Utilities

▪	Sempra Mexico

▪	Sempra Renewables (until April 2019)

▪	Sempra LNG

---

(1)	Excludes approximately 107.5 MW of battery storage owned and approximately 9.5 MW of battery storage contracted.

(2)	SDG&E owns and operates four natural gas-fired power plants, three of which are in California and one of which is in Nevada.

---

(1)	Includes intercompany sales.

---

---

(1)	Includes intercompany sales.

---

---

---

---

---

▪	high levels of developed and undeveloped North American unconventional natural gas and tight oil resources relative to domestic consumption levels;

▪	increasing gas and oil drilling productivity and decreasing unit costs of gas production;

▪	low breakeven prices of marginal North American unconventional gas production; and

▪	proximity to ample existing gas transmission pipeline and underground gas storage capacity.

---

---

▪	consists of five commissioners appointed by the Governor of California for staggered, six-year terms;

▪	regulates SDG&E’s and SoCalGas’ rates and conditions of service, sales of securities, rates of return, capital structure, rates of depreciation, and long-term resource procurement, except as described below in “U.S. Utility Regulation;”

▪	has jurisdiction over the proposed construction of major new electric generation, transmission and distribution, and natural gas storage, transmission and distribution facilities in California;

▪	conducts reviews and audits of utility performance and compliance with regulatory guidelines and conducts investigations into various matters, such as safety, deregulation, competition and the environment, to determine its future policies; and

▪	regulates the interactions and transactions of the California Utilities with Sempra Energy and its other affiliates.

▪	determines the need for additional energy sources and conservation programs;

▪	sponsors alternative-energy research and development projects;

▪	promotes energy conservation programs to reduce demand for natural gas and electricity within California;

▪	maintains a statewide plan of action in case of energy shortages; and

▪	certifies power-plant sites and related facilities within California.

---

---

▪	market-based for wholesale electricity sales

▪	cost-based for the transportation of natural gas

▪	market-based for the purchase and sale of LNG and natural gas

---

▪	operational incentives (electric reliability)

▪	energy efficiency

▪	energy efficiency

▪	natural gas procurement

▪	unbundled natural gas storage and system operator hub services

---

▪	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.

---

(1)	Ages are as of February 27, 2020.

---

(1)	Ages are as of February 27, 2020.

---

(1)	Ages are as of February 27, 2020.

(1)	Excludes employees of equity method investees and discontinued operations.

---

▪	Sempra Energy – www.sempra.com

▪	SDG&E – www.sdge.com

▪	SoCalGas – www.socalgas.com

---

▪	adverse changes to laws and regulations in the states and countries in which we operate

▪	the overall health of the energy industry

▪	volatility in natural gas or electricity prices

▪	credit ratings downgrades

▪	general economic and financial market conditions

---

---

▪	making it more difficult and/or costly for us to service our debt or pay or refinance our debts as they become due, particularly during adverse economic or industry conditions;

▪	limiting our flexibility to pursue other strategic opportunities or react to changes in our business and the industry sectors in which we operate;

▪

requiring a substantial portion of our available cash to be used for debt service payments, including interest, thereby reducing the availability of our cash to fund working capital, capital expenditures, development projects, acquisitions, dividend payments and other general corporate purposes, which could hinder our prospects for growth and the market price of our common stock, preferred stock and debt securities, among other things;

▪	requiring that additional materially adverse terms, conditions or covenants be placed on us under our debt instruments, which covenants might limit additional borrowings; and

▪	imposing specific restrictions on uses of our assets, as well as prohibiting or limiting our ability to create liens, pay dividends, receive distributions from our subsidiaries, redeem or repurchase our stock or make investments, any of which could hinder our access to capital markets and limit our ability to carry out our capital expenditure program.

▪	delays at the Cameron LNG project and the impact on financial credit metrics;

▪	construction of LNG liquefaction projects and the impact on business mix and financial credit metrics over time;

▪	Sempra Energy’s failure to meet certain financial credit metrics;

▪	the CPUC does not effectively implement the more supportive prudency standard associated with the Wildfire Legislation; or

▪	a ratings downgrade at SDG&E and/or SoCalGas.

▪	the CPUC does not effectively implement the more supportive prudency standard associated with the Wildfire Legislation;

---

▪	a consistent weakening of SDG&E’s financial metrics;

▪	catastrophic wildfires caused by California electric IOUs that participate in the Wildfire Fund, which could exhaust the fund considerably earlier than expected; or

▪	a ratings downgrade at Sempra Energy.

▪	SoCalGas’ credit metrics do not improve materially after implementation of the GRC and cost of capital decisions finalized in 2019;

▪	SoCalGas experiences increased business risk, weakening its standalone business risk profile;

▪	deterioration of, or uncertainty in, the political or regulatory environment for local natural gas distribution companies operating in California; or

▪	a ratings downgrade at Sempra Energy.

---

▪	natural gas, propane and ethane pipelines, storage and compressor facilities

▪	electric transmission and distribution

▪	power generation plants, including renewable energy and natural gas-fired generation

▪	marine and inland ethane and liquid fuels, LNG, and LPG facilities, terminals and storage

▪	nuclear power facilities, nuclear fuel and nuclear waste storage facilities (through SDG&E’s 20% minority interest in SONGS, which is currently being decommissioned)

---

---

---

▪	conditions of service

▪	sales of securities

▪	rates of return

---

▪	capital structure

▪	rates of depreciation

▪	long-term resource procurement

---

---

▪	challenges associated with meeting customer demand for natural gas and/or electricity that results in customer curtailments, controlled/uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life;

▪	a prolonged widespread electrical black-out that results in damage to the California Utilities’ equipment or damage to property owned by customers or other third parties;

▪	inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that could lead to public or employee harm or extended outages; severe weather events such as storms, tornadoes, floods, drought, earthquakes, tsunamis, fires, pandemics, solar events, electromagnetic events or other natural disasters;

▪	the release of hazardous or toxic substances into the air, water or soil, including gas leaks from natural gas pipelines or storage facilities; and

▪	attacks by third parties, including cyber-attacks, acts of terrorism, vandalism or war.

---

---

---

---

▪	the potential release of a radioactive material including from a natural disaster such as an earthquake or tsunami that could cause catastrophic harm to human health and the environment;

▪	the potential harmful effects on the environment and human health resulting from the prior operation of nuclear facilities and the storage, handling and disposal of radioactive materials;

▪	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with operations and the decommissioning of the facility; and

▪	uncertainties with respect to the technological and financial aspects of decommissioning the facility.

---

▪	seven members of Oncor’s 13-person board of directors will be independent directors in relation to Sempra Energy and any other direct or indirect owners of Oncor. With respect to the non-independent directors, two will be designated by Sempra Energy, two will be appointed by Oncor’s minority owner, TTI, and two will be current or former Oncor officers;

▪	Oncor may not pay any dividends if a majority of its independent directors or a minority member director determines that it is in the best interests of Oncor to retain such amounts;

▪	Oncor will not pay dividends if that payment would cause its debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT;

▪	if Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or Baa2 for Moody’s), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT;

▪	there must be maintained certain “separateness measures” that reinforce the financial separation of Oncor from Sempra Energy, including a requirement that dealings between Oncor and Sempra Energy must be on an arm’s-length basis, limitations on affiliate transactions and a prohibition on pledging Oncor assets or stock for any entity other than Oncor;

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

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

---

▪	negotiation of satisfactory EPC agreements

▪	negotiation of satisfactory LNG offtake and equity agreements

---

▪	negotiation of supply, natural gas and LNG sales agreements or firm capacity service agreements and PPAs

▪	timely receipt of required governmental permits, licenses and other authorizations and maintenance of these authorizations

▪	our counterparties’ financial or other ability to fulfill their contractual commitments

▪	timely implementation and satisfactory completion of construction

▪	obtaining adequate and reasonably priced financing for the project

▪	unforeseen engineering problems

▪	construction delays due to adverse weather conditions, work stoppages, equipment unavailability and other events and contractor performance shortfalls

▪	our counterparties’ financial or other inability to fulfill their contractual commitments

▪	failure to obtain or maintain required governmental permits, licenses and other authorizations

▪	litigation

▪	unsettled property rights

---

---

---

---

▪	deliver the natural gas and electricity we sell to wholesale markets or that we use for our liquefaction facilities;

▪	supply natural gas to our gas storage and electric generation facilities; and

▪	provide retail energy services to customers.

▪	changes in foreign laws and regulations, including tax and environmental laws and regulations, and U.S. laws and regulations, in each case, that are related to foreign operations;

▪	actions by local regulatory bodies, including setting of rates and tariffs that may be earned by our businesses;

▪	adverse changes in market conditions, trade restrictions, limitations on ownership in foreign countries and inadequate enforcement of regulations;

▪	foreign cash balances that may be unavailable to fund U.S. operations, or available only at unfavorable U.S. and/or foreign tax rates upon repatriation of such amounts or changes in tax law;

▪	permitting and regulatory compliance;

▪	adverse rulings by foreign courts or tribunals, challenges to permits and approvals, difficulty in enforcing contractual and property rights, and unsettled property rights and titles in Mexico;

▪	energy policy reform that may result in adverse changes to and/or difficulty in enforcing existing contracts, as we discuss below;

▪	expropriation or theft of assets;

▪	adverse changes in the stability of the governments in the countries in which we operate;

▪	social unrest; and

▪	compliance with the Foreign Corrupt Practices Act and similar laws.

---

---

---

---

(1)	Excludes discontinued operations.

(2)	Includes long-term debt due within one year and current portion of finance lease obligations. Excludes discontinued operations.

---

(1)	Includes long-term debt due within one year and current portion of finance lease obligations.

---

▪	The California Utilities received a constructive final GRC decision for the 2019 revenue requirement and attrition year adjustments for 2020 and 2021, and a final decision in the 2020 cost of capital proceeding.

▪	SDG&E contributed to the Wildfire Fund that was created through the Wildfire Legislation that addresses certain issues related to catastrophic wildfires in California.

▪	We supported Oncor’s acquisition of InfraREIT and acquired an indirect 50% interest in Sharyland Holdings in Texas.

▪	Cameron LNG JV’s Train 1 commenced commercial operation.

▪	We sold our non-utility natural gas storage assets in the southeast U.S. (comprised of Mississippi Hub and Bay Gas) and our remaining U.S. wind assets and investments. In April 2019, our Sempra Renewables segment ceased to exist.

▪	We entered into agreements to sell our equity interests in our South American businesses, which were previously included in our Sempra South American Utilities segment, and expect those sales to close in the first half of 2020.

▪	Overall results of operations of Sempra Energy

▪	Segment results

▪	Significant changes in revenues, costs and earnings

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

---

(1)	Includes $914 million income tax expense from the effects of the TCJA in 2017, intercompany eliminations recorded in consolidation and certain corporate costs.

▪	$71 million higher CPUC base operating margin authorized for 2019, net of operating expenses;

▪	$31 million income tax benefit from the release of a regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed to be allocated to shareholders in a January 2019 decision; and

▪	$11 million higher margin from electric transmission operations, net of a FERC formulaic rate adjustment benefit in 2018; offset by

▪	$10 million amortization of Wildfire Fund asset.

▪	$208 million charge in 2017 for the write-off of a regulatory asset associated with 2007 wildfire costs;

▪	$65 million higher margin from electric transmission operations in 2018, including the annual FERC formulaic rate adjustment;

▪	$28 million unfavorable impact in 2017 from the remeasurement of certain U.S. federal deferred income tax assets as a result of the TCJA; and

▪	$27 million higher CPUC base operating margin authorized for 2018, primarily related to the lower federal income tax rate in 2018; offset by

▪	$35 million higher net interest expense, of which $25 million relates to the lower federal income tax rate in 2018; and

▪	$11 million unfavorable impact due to lower cost of capital related to GRC base business, which excludes incremental projects and other balanced capital programs, in 2018, of which $2 million relates to the lower federal income tax rate in 2018.

▪	$216 million higher CPUC base operating margin authorized for 2019, net of operating expenses;

▪	$38 million income tax benefit from the impact of the January 2019 CPUC decision allocating certain excess deferred income tax balances to shareholders;

▪	$22 million from impacts associated with Aliso Canyon natural gas storage facility litigation in 2018; and

▪	$14 million higher income tax benefits from flow-through items; offset by

▪	$21 million impairment of non-utility native gas assets in 2019;

▪	$18 million higher net interest expense; and

▪	$8 million penalties in 2019 related to the SoCalGas billing practices OII.

▪	$36 million higher CPUC base operating margin authorized for 2018, net of expenses including depreciation (of this increase, $28 million relates to the lower federal income tax rate in 2018); and

▪	$16 million higher PSEP earnings; offset by

▪	$22 million higher net interest expense, of which $15 million relates to the lower federal income tax rate in 2018;

▪	$21 million unfavorable impact due to lower cost of capital related to GRC base business in 2018, of which $4 million relates to the lower federal income tax rate in 2018; and

---

▪	$22 million in 2018 from impacts associated with Aliso Canyon natural gas storage facility litigation compared to $20 million in 2017.

▪	$18 million primarily due to the start of commercial operations of the Sur de Texas-Tuxpan marine pipeline at IMG JV in the third quarter of 2019;

▪	$16 million lower income tax expense in 2019 primarily from a two-year tax abatement that expires in 2020; and

▪	$122 million earnings attributable to NCI at IEnova in 2019 compared to $132 million earnings in 2018; offset by

▪	$20 million lower earnings primarily from force majeure payments that ended on August 22, 2019 with respect to the Guaymas-El Oro segment of the Sonora pipeline; and

▪	$17 million unfavorable impact from foreign currency and inflation effects, net of foreign currency derivatives effects, comprised of:

◦	in 2019, $88 million unfavorable foreign currency and inflation effects, offset by a $29 million gain from foreign currency derivatives, offset by

◦	in 2018, $43 million unfavorable foreign currency and inflation effects, offset by a $1 million gain from foreign currency derivatives (we discuss these effects below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.”)

▪	$107 million higher earnings at TdM, including $71 million impairment in 2017 of assets that were held for sale until June 1, 2018 and $32 million improved operating results primarily as a result of major maintenance in 2017 and higher revenues in 2018;

▪	$37 million higher earnings, primarily attributable to pipeline assets placed in service in the second quarter of 2017 and IEnova’s increased indirect ownership interest in TAG JV; and

▪	$10 million improved operating results at Ecogas, mainly due to new rates approved by the CRE and regulated revenues associated with recovery for revised tariffs; offset by

▪	$132 million earnings attributable to NCI at IEnova in 2018 compared to $73 million in 2017;

▪	$22 million lower capitalized financing costs, primarily associated with assets placed in service at the end of the first half of 2017, net of higher equity earnings in 2018 from AFUDC at IMG JV; and

▪	$7 million unfavorable impact from foreign currency and inflation effects, net of foreign currency derivatives effects, comprised of:

◦	in 2018, $43 million unfavorable foreign currency and inflation effects, offset by a $1 million gain from foreign currency derivatives, offset by

◦	in 2017, $84 million unfavorable foreign currency and inflation effects, offset by a $49 million gain from foreign currency derivatives.

▪	$367 million gain on the sale of all Sempra Renewables’ operating solar assets, solar and battery storage development projects and its 50% interest in a wind power generation facility in December 2018; and

▪	$92 million lower earnings from assets sold in December 2018 and April 2019, net of lower general and administrative and other costs due to the wind-down of this business; offset by

▪	$145 million other-than-temporary impairment of certain U.S. wind equity method investments in 2018; and

▪	$45 million gain on sale of Sempra Renewables’ remaining wind assets in 2019.

---

▪	$367 million gain on the sale of all Sempra Renewables’ operating solar assets, solar and battery storage development projects and its 50% interest in a wind power generation facility in December 2018;

▪	$35 million higher pretax losses attributed to NCI, including the impact of the TCJA on NCI allocations computed using the HLBV method; and

▪	$19 million lower depreciation as a result of solar and wind assets held for sale; offset by

▪	$192 million favorable impact in 2017 from the remeasurement of U.S. federal deferred income tax liabilities as a result of the TCJA; and

▪	$145 million other-than-temporary impairment of certain U.S. wind equity method investments in 2018.

▪	$665 million net impairment of certain non-utility natural gas storage assets in the southeast U.S. in 2018, including $801 million impairment in the second quarter of 2018, offset by a $136 million reduction to the impairment in the fourth quarter of 2018;

▪	$17 million higher equity earnings from Cameron LNG JV, including:

◦	$36 million increase primarily due to Train 1 commencing commercial operation under its tolling agreements in August 2019, offset by

◦	$19 million decrease due to the write-off of unamortized debt issuance costs and associated fees related to Cameron LNG JV’s debt refinancing; and

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

▪	$36 million losses attributable to NCI in 2018 related to the net impairment discussed above; and

▪	$28 million higher liquefaction project development costs and operating costs.

▪	$665 million net impairment of certain non-utility natural gas storage assets in 2018;

▪	$142 million higher income tax expense in 2018, which included $133 million favorable impact in 2017 from the remeasurement of U.S. federal deferred income tax liabilities as a result of the TCJA and $9 million unfavorable impact in 2018 to adjust TCJA provisional amounts recorded in 2017; and

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

▪	$36 million losses attributable to NCI in 2018 related to the net impairment discussed above;

▪	$24 million higher earnings from midstream activities primarily driven by lower depreciation and amortization as a result of natural gas storage assets held for sale; and

▪	$15 million improved results in 2018 from LNG marketing activities.

▪	$65 million impairment of the RBS Sempra Commodities equity method investment in 2018;

▪	$48 million higher investment gains in 2019 on dedicated assets in support of our employee nonqualified benefit plan obligations, net of deferred compensation expenses;

▪	$32 million income tax expense in 2018 to adjust provisional amounts recorded in 2017 related to the TCJA; and

▪	$10 million income tax benefit in 2019 to reduce a valuation allowance against certain NOL carryforwards as a result of our decision to sell our South American businesses; offset by

▪	$17 million increase in mandatory convertible preferred stock dividends primarily from the issuance of series B preferred stock in July 2018;

▪	$11 million increase primarily related to settlement charges from our nonqualified pension plan; and

▪	$11 million loss from foreign currency derivatives used to hedge exposure to fluctuations in the Peruvian Sol related to the sale of our operations in Peru.

---

▪	$914 million unfavorable impact in 2017 from the TCJA, offset by $32 million income tax expense in 2018 to adjust provisional amounts recorded in 2017 (we discuss the impacts from the TCJA in “Significant Changes in Revenues, Costs and Earnings – Income Taxes” below); offset by

▪	$179 million increase in net interest expense, of which $58 million relates to the lower tax rate in 2018;

▪	$125 million mandatory convertible preferred stock dividends declared;

▪	$65 million impairment of the RBS Sempra Commodities equity method investment; and

▪	$15 million investment losses in 2018 compared to $41 million investment gains in 2017 on dedicated assets in support of our employee nonqualified benefit plan obligations, net of deferred compensation expenses.

▪	$91 million higher earnings from South American operations mainly from higher rates, lower cost of purchased power at Peru, and including $38 million lower depreciation expense due to assets classified as held for sale;

▪	$89 million income tax benefit in 2019 from outside basis differences in our South American businesses primarily related to the change in our indefinite reinvestment assertion from our decision on January 25, 2019 to hold those businesses for sale and a change in the anticipated structure of the sale; and

▪	$44 million income tax expense in 2018 to adjust TCJA provisional amounts recorded in 2017 primarily related to withholding tax on our expected future repatriation of foreign undistributed earnings; offset by

▪	$51 million income tax expense related to the increase in outside basis differences from 2019 earnings since January 25, 2019.

▪

The cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred. However, SoCalGas’ GCIM provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Note 3 of the Notes to Consolidated Financial Statements and in “Item 1. Business – Ratemaking Mechanisms.”

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

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

---

▪	$563 million increase at SoCalGas, which included:

◦	$383 million higher authorized revenue in 2019,

◦	$105 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M,

◦	$62 million higher non-service component of net periodic benefit cost in 2019, which fully offsets in Other Income, Net,

◦	$29 million charges in 2018 associated with tracking the income tax benefit from flow-through items in relation to forecasted amounts in the 2016 GRC FD, and

◦	$16 million higher net revenues from PSEP, offset by

◦	$71 million decrease in the cost of natural gas sold, which we discuss below; and

---

▪	$93 million increase at SDG&E, which included:

◦	$68 million higher authorized revenue in 2019, and

◦	$24 million increase in the cost of natural gas sold, which we discuss below.

▪	$177 million increase at SoCalGas, which included:

◦	$160 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M,

◦	$71 million increase in 2018 due to an increase in rates permitted under the attrition mechanism in the 2016 GRC FD,

◦	$23 million increase in cost of natural gas sold, and

◦	$19 million decrease in charges in 2018 associated with tracking the income tax benefit from flow-through items in relation to forecasted amounts in the 2016 GRC FD, offset by

◦	$67 million revenue deferral due to the effect of the TCJA,

◦	$29 million lower cost of capital related to GRC base business in 2018, and

◦	$10 million lower net revenues from capital projects, including $60 million decrease for advanced metering infrastructure due to completion of the project, offset by increases of $14 million for PSEP and $36 million for other capital projects; and

▪	$24 million increase at SDG&E primarily due to higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M, and 2018 attrition; offset by

▪	$32 million decrease at Sempra Mexico, which included:

◦

$46 million lower volumes at Ecogas primarily as a result of the new regulations that went into effect on March 1, 2018 that no longer allow Ecogas to sell natural gas to high consumption end users (defined by the CRE as customers with annual consumption that exceeds 4,735 MMBtu) and require those end users to procure their natural gas needs from natural gas marketers, including Sempra Mexico’s marketing business, offset by

◦	$13 million higher rates approved by the CRE, including $7 million from a regulatory adjustment to rates charged to end users in 2014 through 2016.

▪	$71 million decrease at SoCalGas, including $164 million due to lower average natural gas prices, offset by $93 million from higher volumes driven by weather; and

▪	$15 million increase in intercompany eliminations primarily associated with sales between Sempra LNG and SoCalGas; offset by

▪	$24 million increase at SDG&E, including $19 million from higher volumes driven by weather and $5 million from higher average natural gas prices.

▪	$56 million increase primarily from lower elimination of intercompany costs at Sempra Mexico; and

▪	$23 million increase at SoCalGas due to $43 million from higher average gas prices, offset by $20 million from lower volumes driven by weather; offset by

▪	$49 million decrease at Sempra Mexico primarily associated with the lower revenues at Ecogas; and

▪	$12 million decrease at SDG&E primarily due to lower average gas prices.

▪	$121 million higher authorized revenue in 2019, including $108 million of revenues to cover liability insurance premium costs that are now balanced and offset in O&M;

▪	$40 million higher revenues from transmission operations, net of a FERC formulaic rate adjustment benefit in 2018;

▪	$34 million higher recovery of costs associated with CPUC-authorized refundable programs, excluding 2019 liability insurance premium costs, which revenues are offset in O&M;

▪	$27 million higher finance lease costs, offset by lower cost of electric fuel and purchased power, which we discuss below; and

▪	$21 million charges in 2018 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD.

---

▪	$77 million higher cost of electric fuel and purchased power;

▪	$50 million higher revenues from transmission operations, including the annual FERC formulaic rate adjustment;

▪	$32 million decrease in charges in 2018 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD; and

▪	$32 million increase due to 2018 attrition; offset by

▪	$65 million revenue deferral due to the effect of the TCJA;

▪	$39 million revenue deferral related to the SONGS settlement, which is offset by the discontinuation of amortization; and

▪	$13 million lower cost of capital related to the CPUC base business in 2018.

▪	$103 million of finance lease costs for PPAs in 2018. Similar amounts are now included in Interest Expense and Depreciation and Amortization Expense as a result of the 2019 adoption of the lease standard; and

▪	$73 million decrease primarily from lower electricity market cost, offset by an increase primarily due to an additional capacity contract.

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

(2)	Includes eliminations of intercompany activity.

▪	$114 million decrease at Sempra Renewables primarily due to the sale of assets in December 2018 and April 2019; and

▪	$62 million decrease at Sempra LNG primarily due to:

◦	$45 million lower natural gas storage revenues primarily due to the sale of storage assets in February 2019,

◦	$15 million from the marketing business due to lower turnback cargo revenues, and

◦	$12 million from LNG sales to Cameron LNG JV in January 2018, offset by

◦	$14 million from natural gas marketing activities primarily due to changes in natural gas prices; offset by

▪	$4 million increase at Sempra Mexico primarily due to:

◦	$23 million from the marketing business, including an increase in volumes due to new regulations that went into effect on March 1, 2018 that require high consumption end users (previously serviced by Ecogas and other natural gas utilities) to procure their natural gas needs from natural gas marketers, such as Sempra Mexico’s marketing business, offset by lower natural gas prices, and

---

◦	$6 million increase primarily due to renewable assets placed in service in 2019, offset by

◦	$27 million lower revenues primarily from force majeure payments that ended on August 22, 2019 with respect to the Guaymas-El Oro segment of the Sonora pipeline.

▪	$212 million increase at Sempra Mexico primarily due to:

◦	$84 million from the marketing business, primarily due to new regulations that went into effect on March 1, 2018 and from higher volumes and gas prices,

◦	$69 million at TdM primarily due to the plant outage in 2017 as a result of scheduled major maintenance and higher power prices,

◦	$34 million primarily due to pipeline assets placed in service in the second quarter of 2017, and

◦	$18 million from O&M services provided to the TAG JV;

▪	$39 million increase from lower intercompany eliminations associated with sales between Sempra LNG and Sempra Mexico; and

▪	$30 million increase at Sempra Renewables primarily due to solar and wind assets placed in service in the fourth quarter of 2017 and the second quarter of 2018; offset by

▪	$68 million decrease at Sempra LNG primarily due to:

◦	$98 million costs associated with indemnity payments to Sempra Mexico in 2018. Indemnity payments of $103 million in 2017 were recorded in Energy-Related Businesses Cost of Sales prior to adoption of ASC 606, offset by

◦	$50 million from the marketing business primarily from higher natural gas sales and turnback cargo revenues.

▪	$102 million at Sempra Mexico primarily associated with higher revenues from the marketing business as a result of the new regulations that went into effect on March 1, 2018. The increase at Sempra Mexico was also due to higher volumes in 2018 due to the TdM plant outage in 2017;

▪	$57 million in settlement proceeds received by Sempra LNG in May 2017 from a breach of contract claim against a counterparty, of which $47 million is related to a charge in 2016 from permanent release of pipeline capacity; and

▪	$4 million lower intercompany eliminations of costs between Sempra LNG and Sempra Mexico, including $103 million elimination of indemnity payments made by Sempra LNG in 2017 now recorded as a reduction to Energy-Related Business Revenues since adoption of ASC 606; offset by

▪	$88 million decrease at Sempra LNG primarily due to indemnity payments to Sempra Mexico in 2017 recorded in revenue in 2018 pursuant to adoption of ASC 606.

---

(1)	Excludes $6 million of impairment losses, which we discuss below.

(2)	Includes eliminations of intercompany activity.

▪	$167 million increase at SoCalGas, which included:

◦	$105 million higher expenses associated with CPUC-authorized refundable programs for which costs incurred are recovered in revenue (refundable program expenses), and

◦	$57 million higher non-refundable operating costs, including labor, contract services and administrative and support costs;

▪	$117 million increase at SDG&E which included:

◦	$147 million higher expenses associated with CPUC-authorized refundable programs, including $112 million of 2019 liability insurance premium costs that are now balanced in revenue, and

◦	$12 million amortization of Wildfire Fund asset, offset by

◦	$46 million lower non-refundable operating costs, including $87 million decrease from liability insurance premium costs for 2018 that were not balanced, offset by $41 million of higher operating costs;

▪	$53 million increase at Parent and other primarily from higher deferred compensation expense;

▪	$33 million increase at Sempra LNG primarily from higher liquefaction development project costs and higher operating costs; and

▪	$17 million increase at Sempra Mexico primarily due to expenses associated with growth in the business and operating lease costs in 2019; offset by

▪	$71 million decrease at Sempra Renewables primarily due to lower general and administrative and other costs due to the wind-down of the business.

▪	$139 million increase at SoCalGas, which included:

◦	$160 million higher expenses associated with CPUC-authorized refundable programs, offset by

◦	$20 million Aliso Canyon litigation reserves in 2017;

▪	$34 million increase at SDG&E, which included:

◦	$22 million higher non-refundable operating costs, including labor, contract services and administrative and support costs, and

◦	$11 million reimbursement of litigation costs in 2017 associated with the arbitration ruling over the SONGS replacement steam generators; and

▪	$16 million increase at Sempra Renewables primarily due to solar and wind assets placed in service in the fourth quarter of 2017 and the second quarter of 2018 and selling costs associated with the sale of assets.

---

▪	$61 million investment gains in 2019 compared to $6 million investment losses in 2018 on dedicated assets in support of our executive retirement and deferred compensation plans; and

▪	$54 million higher net gains from interest rate and foreign exchange instruments and foreign currency transactions primarily due to:

◦	$37 million higher gains in 2019 on foreign currency derivatives as a result of fluctuation of the Mexican peso, and

◦	$30 million foreign currency gains in 2019 compared to $3 million foreign currency losses in 2018 on a Mexican peso-denominated loan to IMG JV, which is offset in Equity Earnings, offset by

◦	$15 million losses in 2019 on foreign currency derivatives used to hedge exposure to fluctuations in the Peruvian Sol related to the sale of our operations in Peru; offset by

▪	$97 million higher non-service component of net periodic benefit cost in 2019, including $14 million at SDG&E and $62 million at SoCalGas.

▪	$70 million decrease in equity-related AFUDC mainly from completion of pipeline projects at Sempra Mexico in 2017;

▪	$6 million investment losses in 2018 compared to $56 million investment gains in 2017 on dedicated assets in support of our executive retirement and deferred compensation plans;

▪	$15 million higher non-service component of net periodic benefit cost in 2018, including $10 million at SDG&E and $5 million at SoCalGas; and

▪	$13 million lower net gains from interest rate and foreign exchange instruments and foreign currency transactions primarily due to:

◦	$46 million lower gains in 2018 on foreign currency derivatives as a result of fluctuation of the Mexican peso, offset by

◦	$32 million lower losses in 2018 on a Mexican peso-denominated loan to IMG JV, which is offset in Equity Earnings.

---

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

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

▪	$45 million higher income tax expense in 2019 from foreign currency and inflation effects primarily as a result of fluctuation of the Mexican peso; offset by

▪	$69 million total income tax benefits from the release of regulatory liabilities at SDG&E and SoCalGas established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision;

▪	$41 million income tax expense in 2018 to adjust provisional estimates recorded in 2017 for the effects of tax reform;

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

▪	$10 million income tax benefit in 2019 from a reduction in a valuation allowance against certain NOL carryforwards as a result of our decision to sell our South American businesses.

▪	$619 million income tax expense in 2017 from the effects of the TCJA, as follows:

◦	$437 million related to future repatriation of foreign earnings, including $328 million of U.S. federal income tax expense pertaining to the deemed repatriation tax and $109 million U.S. state and non-U.S. withholding tax expense on our expected future repatriation of foreign undistributed earnings estimated for deemed repatriation, and

◦	$182 million from remeasurement of our U.S. federal deferred income tax balances from 35% to 21%;

---

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

▪	$98 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018; and

▪	$38 million lower income tax expense from foreign currency and inflation effects, as a result of fluctuation of the Mexican peso; offset by

▪	$41 million income tax expense in 2018 to adjust provisional estimates recorded in 2017 for the effects of tax reform;

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

▪	lower income tax benefits from flow-through deductions in 2018.

▪	$119 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018; and

▪	$28 million deferred income tax expense in 2017 from remeasurement of U.S. federal deferred income tax balances from 35% to 21%, primarily from the deferred income tax asset relating to the impairment of the SONGS Steam Generator Replacement Project in prior years; offset by

▪	$19 million lower income tax benefit in 2018 from the resolution of prior years’ income tax items; and

▪	lower income tax benefits from flow-through deductions in 2018.

▪	$38 million income tax benefit from the release of a regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision; and

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

▪	$69 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018; offset by

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

▪	lower income tax benefits from flow-through deductions in 2018.

▪	$174 million increase at Sempra Renewables, including $200 million other-than-temporary impairment of certain wind equity method investments in 2018;

▪	$155 million higher equity earnings, net of income tax, from our investment in Oncor Holdings, which we acquired in March 2018;

▪	$65 million impairment of our RBS Sempra Commodities equity method investment in 2018; and

▪	$24 million higher equity earnings from Cameron LNG JV including:

---

◦	$50 million increase primarily due to Train 1 commencing commercial operation under its tolling agreements in August 2019, offset by

◦	$26 million decrease due to the write-off of unamortized debt issuance costs and associated fees related to the JV’s debt refinancing; offset by

▪	$20 million lower equity earnings, net of income tax, from IMG JV, including $30 million foreign currency losses in 2019 compared to $3 million foreign currency gains in 2018 on its Mexican peso-denominated loans from its JV owners, which is fully offset in Other Income, Net.

▪	$371 million equity earnings, net of income tax, from our investment in Oncor Holdings, which we acquired in March 2018; offset by

▪	$200 million other-than-temporary impairment of certain wind equity method investments at Sempra Renewables in 2018;

▪	$65 million impairment of our RBS Sempra Commodities equity method investment in 2018; and

▪	$16 million lower equity earnings, net of income tax, from IMG JV, including $32 million lower foreign currency gains in 2018 on its Mexican peso-denominated loans from its JV owners, which is fully offset in Other Income, Net.

▪	$1 million earnings attributable to NCI at Sempra Renewables in 2019 compared to $58 million losses in 2018 primarily due to the sales of our tax equity investments in December 2018 and April 2019; and

▪	$36 million losses attributable to NCI at Sempra LNG in 2018 due to the net impairment of certain non-utility natural gas storage assets.

▪	$36 million losses attributable to NCI at Sempra LNG in 2018 due to the net impairment of certain non-utility natural gas storage assets; and

▪	$35 million higher pretax losses attributed to tax equity investors at Sempra Renewables; offset by

▪	$59 million higher earnings attributable to NCI at Sempra Mexico in 2018.

---

---

▪	finance capital expenditures

▪	meet liquidity requirements

▪	fund dividends

▪	fund new business or asset acquisitions or start-ups

▪	fund capital contribution requirements

▪	repay maturing long-term debt

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

(1)	Amounts at Sempra Energy Consolidated include $60 million held in non-U.S. jurisdictions. We discuss repatriation in Note 8 of the Notes to Consolidated Financial Statements.

(2)	Available unused credit is the total available on Sempra Energy’s, Sempra Global’s, SDG&E’s and SoCalGas’ credit facilities that we discuss in Note 7 of the Notes to Consolidated Financial Statements.

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

---

(1)	The largest amount outstanding at the end of the last day of any month during the year.

▪	If Sempra Energy were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 to 50 bps. The commitment fee on available unused credit would also increase 5 to 10 bps.

▪	If SDG&E were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 to 50 bps. The commitment fee on available unused credit would also increase 5 to 10 bps.

▪	If SoCalGas were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 to 25 bps. The commitment fee on available unused credit would also increase 2.5 to 5 bps.

---

---

---

---

---

---

---

---

---

---

---

(1)	Net of cash and cash equivalents acquired.

---

▪	$1.8 billion in 2019

▪	$4.5 billion in 2018

▪	$47 million in 2017

▪	$993 million for common stock and $142 million for preferred stock in 2019

▪	$877 million for common stock and $89 million for preferred stock in 2018

▪	$755 million for common stock in 2017

---

▪	$60.58 in 2019

▪	$54.35 in 2018

▪	$50.40 in 2017

▪	Sempra Energy Consolidated: increase in short-term debt and increase in equity from issuances of common stock and comprehensive income exceeding dividends.

▪	SDG&E: increase in equity from comprehensive income and common stock, partially offset by a decrease in NCI due to deconsolidation of Otay Mesa VIE.

▪	SoCalGas: increase in both long-term and short-term debt and from comprehensive income exceeding dividends.

---

(1)	We calculate expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps and cross-currency swaps. We calculate expected interest payments for variable-rate obligations based on forward rates in effect at December 31, 2019.

(2)	Includes $11 million of estimated variable payments.

(3)	Sempra LNG has a sale and purchase agreement for the supply of LNG to the ECA LNG Regasification terminal. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2020 to 2029.

(4)	Amounts represent expected company contributions to the plans for the next 10 years.

(5)	Excludes environmental matters for the Leak at SoCalGas’ Aliso Canyon natural gas storage facility.

(6)	Includes leases that have not yet commenced.

---

(1)	SDG&E calculates expected interest payments using the stated interest rate for fixed-rate obligations.

(2)	Amounts represent expected SDG&E contributions to the plans for the next 10 years.

(3)	Includes leases that have not yet commenced.

(1)	SoCalGas calculates interest payments using the stated interest rate for fixed-rate obligations.

(2)	Excludes amounts related to the natural gas leak at the Aliso Canyon natural gas storage facility.

(3)	Amounts represent expected SoCalGas contributions to the plans for the next 10 years.

▪	$93 million for Sempra Energy Consolidated

▪	$12 million for SDG&E

▪	$64 million for SoCalGas

---

▪	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

▪	the amount of the loss can be reasonably estimated

▪	changes in the regulatory and political environment or the utility’s competitive position

▪	issuance of a regulatory commission order

▪	passage of new legislation

---

▪	past resolutions of the same or similar issue

▪	the status of any income tax examination in progress

▪	positions taken by taxing authorities with other taxpayers with similar issues

▪	future impacts of various items, including changes in tax laws, regulations, interpretations and rulings

▪	our financial condition in future periods

▪	the resolution of various income tax issues between us and taxing and regulatory authorities

---

▪	discount rates

▪	expected return on plan assets

▪	health care cost trend rates

▪	mortality rates

▪	rate of compensation increases

▪	termination and retirement rates

▪	utilization of postretirement welfare benefits

▪	payout elections (lump sum or annuity)

▪	lump sum interest rates

▪	return on plan assets

▪	changing market and economic conditions

▪	higher or lower withdrawal rates

▪	longer or shorter participant life spans

▪	more or fewer lump sum versus annuity payout elections made by plan participants

▪	higher or lower retirement rates

▪	estimated decommissioning costs, including labor, equipment, material and other disposal costs

▪	inflation adjustment applied to estimated cash flows

▪	discount rate based on a credit-adjusted risk-free rate

▪	actual decommissioning costs, progress to date and expected duration of decommissioning activities

---

▪	consideration of market transactions

▪	future cash flows

▪	the appropriate risk-adjusted discount rate

▪	country risk

▪	entity risk

---

▪	equity sale offer price for the investment

▪	transportation rates for natural gas

▪	the appropriate risk-adjusted discount rate

▪	the availability and costs of natural gas and LNG

▪	competing fuels and electricity

▪	estimated future power generation and associated tax credits

▪	renewable power price expectations

---

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

---

(1)	Amount represents the impact to earnings for a change in the average exchange rate throughout the reporting period.

(2)	Amount primarily represents the effects of currency exchange rate movement from December 31, 2019 on monetary assets and liabilities and translation of non-U.S. deferred income tax balances at our Mexican subsidiaries.

(3)	Amount represents the effects of currency exchange rate movement from December 31, 2019 recorded to OCI at the end of each reporting period.

---

---

---

---

---

---

(1)

The 2013 LTIP consists of 247,577 options to purchase shares of our common stock, all of which were granted at an exercise price equal to 100% of the grant date fair market value of the shares subject to the option, 1,086,981 performance-based RSUs and 378,139 service-based RSUs. Each performance-based RSU represents the right to receive from zero to 2.0 shares of our common stock if applicable performance conditions are satisfied. No new awards may be granted under the 2013 LTIP. The 2019 LTIP consists of 37,648 service-based RSUs.

(2)	Represents only the weighted-average exercise price of the 247,577 outstanding options to purchase shares of our common stock under the 2013 LTIP. No options have been issued under the 2019 LTIP.

(3)

The number of shares available for future issuance is increased by the number of shares to which the participant would otherwise be entitled that are withheld or surrendered to satisfy the exercise price or to satisfy tax withholding obligations relating to any plan awards, and is also increased by the number of shares subject to awards that expire or are forfeited, canceled or otherwise terminated without the issuance of shares. No new awards may be granted under the 2013 LTIP or other previous shareholder-approved LTIPs.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

▪	We tested the effectiveness of management’s internal controls over the costs included in the related insurance receivable and the evaluation of the recoverability of this insurance receivable.

▪	With the assistance of our insurance specialist, we evaluated management’s judgments related to the determination of the recoverability of the insurance receivable by:

◦	Evaluating the coverage provided by Sempra Energy’s applicable insurance policies and evaluating the potential coverage available under such policies based on the nature of the underlying costs.

◦	Evaluating the probability of recovery of the insurance receivable by obtaining correspondence between Sempra Energy and the applicable insurers, and through discussions with management and with Sempra Energy’s external legal counsel.

◦	Searching external sources for and considering any contradictory evidence to Sempra Energy’s accounting assessment of probability of recoverability.

◦	Evaluating Sempra Energy’s external legal counsel’s view on the recoverability of the insurance receivable.

▪	We tested the effectiveness of management’s internal controls over the evaluation of the accounting treatment.

▪

With the assistance of professionals in our firm having expertise in insurance accounting, we evaluated management’s judgments related to the application of U.S. GAAP by evaluating management’s accounting analysis, Sempra Energy’s consideration of an insurance accounting model, and the potential methods of which to record the consumption of benefits related to the Contributions, to determine whether we agree with management’s accounting conclusions that the Contributions should be accounted for as an asset and systematically and rationally expensed over the estimated period of benefit.

---

▪

We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

▪

We read relevant regulatory orders issued by the Commissions for Sempra Energy and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.

▪	We evaluated Sempra Energy’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

▪	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.

---

▪	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

---

▪	quoted forward prices for commodities

▪	time value

▪	current market and contractual prices for the underlying instruments

▪	volatility factors

▪	other relevant economic measures

▪	for SDG&E, funds held by a trustee for Otay Mesa VIE to pay certain operating costs until the deconsolidation of the VIE in August 2019; and

▪	for Sempra Mexico, funds primarily denominated in Mexican pesos to pay for rights-of-way, license fees, permits, topographic surveys and other costs pursuant to trust and debt agreements related to pipeline projects.

---

---

▪	prospective counterparties’ financial condition (including credit ratings)

▪	collateral requirements

▪	the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty

▪	downgrade triggers

---

•	historical wildfire experience of each IOU in the State of California, including frequency and severity of the wildfires

•	the value of property potentially damaged by wildfires

•	the effectiveness of wildfire risk mitigation efforts by each IOU

•	liability cap of each IOU

---

•	IOU prudency determination levels

•	FERC jurisdictional allocation levels

•	insurance coverage levels

▪	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.

---

---

(1)

At December 31, 2019, includes $484 million in electric transmission assets and $13 million in construction work in progress related to SDG&E’s 90% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Consolidated Statements of Operations.

(2)	Includes capital lease assets of $1.3 billion at December 31, 2018.

(3)	Includes capital lease assets of $13 million at December 31, 2018.

(4)	Includes capital lease assets of $40 million at December 31, 2018.

(5)	Includes $178 million and $154 million at December 31, 2019 and 2018, respectively, of utility plant, primarily pipelines and other distribution assets at Ecogas.

(6)	Estimated useful lives are for land rights.

(7)	Includes capital lease assets of $136 million and associated leasehold improvements of $24 million at December 31, 2018 related to our corporate headquarters build-to-suit arrangement, which is accounted for as a ROU asset as of January 1, 2019 upon adoption of the lease standard.

---

(1)	Includes accumulated depreciation for capital lease assets of $48 million at December 31, 2018. Includes $263 million at December 31, 2019 related to SDG&E’s 90% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.

(2)	Includes accumulated depreciation for capital lease assets of $37 million at December 31, 2018.

(3)

Includes accumulated depreciation for capital lease assets of $10 million and associated leasehold improvements of $3 million at December 31, 2018 related to our corporate headquarters’ build-to-suit arrangement, which is accounted for as a ROU asset as of January 1, 2019. Includes $49 million and $43 million at December 31, 2019 and 2018, respectively, of accumulated depreciation for utility plant at Ecogas.

---

▪	consideration of market transactions

▪	future cash flows

▪	the appropriate risk-adjusted discount rate

▪	country risk

▪	entity risk

▪	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.

▪	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.

▪	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.

---

---

▪	fuel and storage tanks

▪	natural gas transmission and distribution systems

▪	hazardous waste storage facilities

▪	asbestos-containing construction materials

▪	nuclear power facilities

▪	electric transmission and distribution systems

▪	energy storage systems

▪	power generation plants

▪	underground natural gas storage facilities and wells

---

▪	natural gas transportation and distribution systems

▪	power generation plants

▪	LNG facility

▪	LPG terminal

(1)	Current portion of the ARO for Sempra Energy Consolidated is included in Other Current Liabilities on the Consolidated Balance Sheets.

(2)	In 2018, we reclassified $6 million at Sempra Renewables and $8 million at Sempra LNG to liabilities held for sale, and $5 million related to TdM from liabilities held for sale, and deconsolidated $52 million at Sempra Renewables, as we discuss in Note 5. Liabilities held for sale are included in Other Current Liabilities on the Sempra Energy Consolidated Balance Sheets.

▪	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.

▪	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

---

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

(2)	Includes discontinued operations.

(3)	Pension and Other Postretirement Benefits and Total AOCI include a $4 million transfer of liabilities from SoCalGas to Sempra Energy related to the nonqualified pension plan.

---

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

(2)	Amounts are included in the computation of net periodic benefit cost (see “Net Periodic Benefit Cost” in Note 9).

---

---

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

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

(3)	In April 2019, PXiSE Energy Solutions, LLC was subsumed into Parent and other.

---

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

(2)	Mexican peso-denominated revolving line of credit for up to 14.2 billion Mexican pesos or approximately $751 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 bps (9.65% at December 31, 2019), to finance construction of the natural gas marine pipeline.

(3)	U.S. dollar-denominated loan at a variable interest rate based on the 30-day LIBOR plus 637.5 bps (8.89% at December 31, 2018).

(4)	U.S. dollar-denominated loan at a variable interest rate based on 6-month LIBOR plus 290 bps (4.81% at December 31, 2019).

(5)	U.S. dollar-denominated loan at a fixed interest rate.

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

---

---

▪	The CPUC requires that SDG&E’s and SoCalGas’ common equity ratios be no lower than one percentage point below the CPUC-authorized percentage of each entity’s authorized capital structure. The authorized percentage at December 31, 2019 is 52% at both SDG&E and SoCalGas.

▪	SDG&E and SoCalGas each have a revolving credit line that requires it to maintain a ratio of consolidated indebtedness to consolidated capitalization (as defined in the agreements) of no more than 65%, as we discuss in Note 7.

▪

In connection with the ring-fencing measures, governance mechanisms and commitments that we describe in Note 6, Oncor may not pay any dividends or make any other distributions (except for contractual tax payments) if a majority of its independent directors or a minority member director determines that it is in the best interests of Oncor to retain such amounts to meet expected future requirements.

▪	Oncor must remain in compliance with the debt-to-equity ratio established by the PUCT for ratemaking purposes and may not pay dividends or other distributions (except for contractual tax payments) if that payment would cause it to exceed its PUCT authorized debt-to-equity ratio (57.5% debt to 42.5% equity as of December 31, 2019).

▪	If the credit rating on Oncor’s senior secured debt by any of the three major credit rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. At December 31, 2019, all of Oncor’s senior secured ratings were above BBB.

▪	Oncor’s revolving credit line, note purchase agreements, and term loan credit agreements require it to maintain a consolidated senior debt-to-capitalization ratio of no more than 65% and observe certain affirmative covenants. At December 31, 2019, Oncor was in compliance with these covenants.

▪	Sharyland Utilities may not pay dividends or make other distributions (except for contractual payments) without the consent of the JV partner.

▪	Sharyland Utilities must remain in compliance with the debt-to-equity ratio established by the PUCT for ratemaking purposes and may not pay dividends or other distributions (except for contractual tax payments) if that payment would cause its debt-to-equity ratio to exceed 55% debt to 45% equity, which was authorized by the PUCT.

▪	Sharyland Utilities has a revolving credit line and a term loan credit agreement that require it to maintain a consolidated debt-to-capitalization ratio of no more than 70% and observe certain customary reporting requirements and other affirmative covenants. At December 31, 2019, Sharyland Utilities was in compliance with these and all other covenants.

---

▪	Mexico requires domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $178 million at Sempra Energy’s consolidated Mexican subsidiaries at December 31, 2019.

▪	Wholly owned IEnova Pipelines has a long-term debt agreement that requires it to maintain a reserve account to pay the projects’ debt. Under this restriction, net assets totaling $17 million are restricted at December 31, 2019.

▪

Wholly owned Ventika has long-term debt agreements that require it to maintain reserve accounts to pay the projects’ debt. The debt agreements may limit the project companies’ ability to incur liens, incur additional indebtedness, make investments, pay cash dividends and undertake certain additional actions. Under these restrictions, net assets totaling $14 million are restricted at December 31, 2019.

▪

Energía Sierra Juárez, a 50% owned and unconsolidated JV of Sempra Mexico, has long-term debt agreements that require the establishment and funding of project and reserve accounts to which the proceeds of loans, letter of credit borrowings, project revenues and other amounts are deposited and applied in accordance with the debt agreements. The long-term debt agreements also limit the JV’s ability to incur liens, incur additional indebtedness, make acquisitions and undertake certain actions. Under these restrictions, net assets totaling $15 million are restricted at December 31, 2019.

▪	TAG JV, a 50% owned and unconsolidated JV of Sempra Mexico, has a long-term debt agreement that requires it to maintain a reserve account to pay the projects’ debt. Under these restrictions, net assets totaling $171 million are restricted at December 31, 2019.

---

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

(2)	Includes gains of $30 million in 2019 and losses of $3 million and $35 million in 2018 and 2017, respectively, from translation to U.S. dollars of a Mexican peso-denominated loan to IMG JV, which are offset by corresponding amounts included in Equity Earnings on the Consolidated Statements of Operations.

---

---

▪	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.

▪	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.

---

▪	SDG&E

▪	SoCalGas

---

▪	Sempra Mexico’s Ecogas

---

(1)	Excludes intercompany transactions.

---

(1)	Includes $4 million and $4 million in Other Current Liabilities and $159 million and $87 million in Deferred Credits and Other on the Sempra Energy and SDG&E Consolidated Balance Sheets, respectively.

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

---

▪	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.

▪	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.

---

(1)	At December 31, 2019 and 2018, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $108 million and $78 million, respectively. At December 31, 2019 and 2018, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $500 million and $185 million, respectively.

(2)	Includes regulatory assets earning a return.

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

▪	Deferred income taxes refundable/recoverable in rates are based on current regulatory ratemaking and income tax laws.

---

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

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

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

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

▪	The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 50-year period.

▪	Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs, including commodity costs. Depreciation and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval.

---

---

---

---

•	$9,450 million of Merger Consideration;

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

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

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

(1)

In the fourth quarter of 2018, we received additional information regarding deferred income taxes related to the resolution of claims in EFH’s emergence from bankruptcy as of the acquisition date. As a result, we recorded an adjustment to increase our investment in Oncor Holdings by $64 million, decrease deferred income tax assets by $66 million and decrease deferred credits and other liabilities by $2 million. Also in the fourth quarter of 2018, we recorded $2 million of additional purchase price paid related to additional transaction costs.

---

---

▪	its operating solar assets, including assets that we owned through JVs or through tax equity arrangements (other than those interests held by tax equity investors);

▪	its solar and battery storage development projects; and

▪	its 50% interest in the Broken Bow 2 wind generation facility.

---

---

(1)	Primarily represents funds held in accordance with Peruvian tax law.

---

(1)

The carrying value of our equity method investment is $2,823 million and $2,814 million higher than the underlying equity in the net assets of the investee at December 31, 2019 and 2018, respectively, due to $2,868 million of equity method goodwill and $69 million in basis differences in AOCI, offset by $114 million at December 31, 2019 and $123 million at December 31, 2018 due to a tax sharing liability to TTI under the tax sharing agreement.

(2)	The carrying value of our equity method investment is $42 million higher than the underlying equity in the net assets of the investee due to equity method goodwill.

(3)	The carrying value of our equity method investment is $12 million higher than the underlying equity in the net assets of the investee due to the remeasurement of our retained investment to fair value in 2014.

(4)	The carrying value of our equity method investment is $5 million higher than the underlying equity in the net assets of the investee due to guarantees.

(5)	The carrying value of our equity method investment is $130 million higher than the underlying equity in the net assets of the investee due to equity method goodwill.

(6)	The carrying value of our equity method investment at December 31, 2018 was $169 million lower than the underlying equity in the net assets of the investee due to an other-than-temporary impairment recorded in 2018.

(7)	The carrying value of our equity method investment at December 31, 2018 was $31 million lower than the underlying equity in the net assets of the investee due to an other-than-temporary impairment recorded in 2018.

(8)

The carrying value of our equity method investment is $263 million and $246 million higher than the underlying equity in the net assets of the investee at December 31, 2019 and 2018, respectively, primarily due to guarantees, which we discuss below, interest capitalized on the investment prior to the JV commencing its planned principal operations in August 2019 and amortization of guarantee fees and capitalized interest thereafter.

---

(1)	We provide our ETR calculation in Note 8.

(2)	Losses from equity method investment in 2018 include an other-than-temporary impairment charge, which we discuss below.

---

---

---

---

(1)	On April 22, 2019, Sempra Renewables sold its remaining wind assets and investments to AEP. As of April 22, 2019, these wind assets and investments are no longer equity method investments.

(2)	On December 13, 2018, Sempra Renewables sold all its operating solar assets, including its solar equity method investments, and its 50% interest in the Broken Bow 2 wind power generation facility to a subsidiary of Con Ed. As of December 13, 2018, the solar equity method investments and Broken Bow 2 are no longer equity method investments.

(3)	On November 15, 2017, IEnova completed the asset acquisition of PEMEX’s 50% interest in DEN, increasing its ownership percentage to 100%. As of November 15, 2017, DEN is no longer an equity method investment.

(4)	Except for our investments in Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships.

---

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

(2)

The facility also provides for issuance of $200 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, Sempra Energy has the right to increase the letter of credit commitment up to $500 million. No letters of credit were outstanding at December 31, 2019.

(3)	Commercial paper outstanding is before reductions of unamortized discount of $3 million at Sempra Global and negligible amounts at SDG&E and SoCalGas.

(4)

The facility also provides for issuance of $100 million of letters of credit on behalf of the borrowing utility with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, the borrowing utility has the right to increase the letter of credit commitment up to $250 million. No letters of credit were outstanding at December 31, 2019.

▪	Each is a 5-year syndicated revolving credit agreement expiring in May 2024.

▪	Citibank N.A. serves as administrative agent for the Sempra Energy and Sempra Global facilities and JPMorgan Chase Bank, N.A. serves as administrative agent for the SDG&E and SoCalGas facilities.

▪	Each facility has a syndicate of 23 lenders. No single lender has greater than a 6% share in any facility.

▪	Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings in the case of the Sempra Energy and Sempra Global lines of credit, and with the borrowing utility’s credit rating in the case of SDG&E’s and SoCalGas’ lines of credit.

▪	Sempra Energy, SDG&E and SoCalGas each must maintain a ratio of indebtedness to total capitalization (as defined in each of the applicable credit facilities) of no more than 65% at the end of each quarter. At December 31, 2019, each entity was in compliance with this ratio and all other financial covenants under its respective credit facility.

▪	Sempra Energy guarantees Sempra Global’s obligations under its credit facility.

(1)	Five-year revolving credit facility with a syndicate of 10 lenders.

(2)	Three-year revolving credit facility with Scotiabank Inverlat, S.A. Withdrawals may be made for up to one year from April 11, 2019 in either U.S. dollars or Mexican pesos.

(3)	Two-year revolving credit facility with The Bank of Nova Scotia. Withdrawals may be made for up to two years from September 23, 2019 in U.S. dollars.

---

---

---

(1)	Callable long-term debt not subject to make-whole provisions.

(2)	This arrangement is now accounted for as an operating lease liability upon adoption of the lease standard on January 1, 2019. See Note 2.

(1)	Excludes finance lease obligations, discounts, and debt issuance costs.

---

▪	on or after October 1, 2024, at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest;

▪	before October 1, 2024, if the U.S. federal tax law or regulations are amended or certain other events occur such that there is more than insubstantial risk that interest payable on the notes would no longer be deductible for federal income tax purposes, at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest; or

▪	before October 1, 2024, if a credit rating agency publicly changes certain equity credit methodology for securities such as these notes that results in a shortening of the length of time for equity credit initially assigned or lowers the equity credit initially assigned, at a redemption price equal to 102% of the principal amount, plus accrued and unpaid interest.

---

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

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

▪	the equity portion of AFUDC, which is non-taxable

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

▪	utility self-developed software expenditures

▪	depreciation on a certain portion of utility plant assets

▪	state income taxes

---

---

(1)

Due to fluctuation of the Mexican peso against the U.S. dollar. We record income tax expense (benefit) from the transactional effects of foreign currency and inflation because of appreciation (depreciation) of the Mexican peso. We also recognize gains (losses) in Other Income, Net, on the Consolidated Statements of Operations from foreign currency derivatives that are partially hedging Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova.

(2)	Related to operations in Mexico.

---

---

▪	$89 million income tax benefit primarily related to outside basis differences existing as of the January 25, 2019 approval of our plan to sell our South American businesses; and

▪	$51 million income tax expense related to the increase in outside basis differences from 2019 earnings since January 25, 2019.

(1)	See “Income Tax Expense (Benefit) and Effective Income Tax Rates” table above for calculation of pretax income.

---

---

(1)	In addition to the financial over tax basis differences in fixed assets, the amount also includes financial over tax basis differences in various interests in partnerships and certain subsidiaries.

(2)	At December 31, 2019 and 2018, includes $155 million and $141 million, respectively, recorded as a noncurrent asset and $2,577 million and $2,321 million, respectively, recorded as a noncurrent liability on the Consolidated Balance Sheets.

---

(1)	We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not-basis.

(2)	We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as discussed below.

---

(1)	Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above.

---

▪	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.

---

---

---

---

---

▪	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.

---

(1)	Includes discontinued operations.

---

(1)	Includes discontinued operations.

---

---

---

▪	35% domestic equity

▪	24% international equity

▪	18% long credit

▪	8% ultra-long duration government securities

▪	5% global real estate investment trusts

▪	5% return-seeking credit

▪	5% real assets

---

▪	long-term cost

▪	variability and level of contributions

▪	funded status

▪	a range of expected outcomes over varying confidence levels

---

---

---

---

---

▪	nonqualified stock options

▪	incentive stock options

---

▪	restricted stock awards

▪	restricted stock units

▪	stock appreciation rights

▪	performance awards

▪	stock payments

▪	dividend equivalents

▪

Nonqualified Stock Options: Options to purchase common stock have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a three-year period (for awards granted in 2019) or over a four-year period (for awards granted in 2010 or earlier), and expire 10 years from the date of grant. Vesting and/or the ability to exercise may be accelerated upon a change in control, in accordance with severance pay agreements or in accordance with the terms of the grant. Options are subject to forfeiture or earlier expiration following termination of employment, subject to certain exceptions.

▪

Performance-Based Restricted Stock Units: These RSU awards generally vest in Sempra Energy common stock at the end of three-year (for awards granted during or after 2015) or four-year performance periods (for awards granted prior to 2015) based on Sempra Energy’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra Energy’s EPS. The comparative market indices for the awards that vest based on total return to shareholders are the S&P 500 Utilities Index and the S&P 500 Index. We use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies to develop our targets for awards that vest based on EPS growth.

◦	For awards granted in 2013 or earlier, if Sempra Energy’s total return to shareholders exceeds target levels, up to an additional 50% of the number of granted RSUs may be issued.

◦	For awards granted during or after 2014, up to an additional 100% of the granted RSUs may be issued if total return to shareholders or EPS growth exceeds target levels.

◦

For awards granted in 2015 and 2016 and certain awards granted in 2017 and 2018 that vest based on Sempra Energy’s total return to shareholders, a modifier adds 20% to the award’s payout (as initially calculated based on total return to shareholders relative to that of specified market indices) for total shareholder return performance in the top quartile relative to historical benchmark data for Sempra Energy and reduces the award’s payout by 20% for performance in the bottom quartile. However, in no event will more than an additional 100% of the granted RSUs be issued. If performance falls within the second or third quartiles, the modifier is not triggered, and the payout is based solely on total return to shareholders relative to that of specified market indices.

▪	Other Performance-Based Restricted Stock Units: RSUs were granted in 2014 and 2015 in connection with the creation of Cameron LNG JV.

◦	The 2014 awards vested in 2015 through 2017 as the Compensation Committee of Sempra Energy’s board of directors determined that the objectives of the JV were achieved. Those awards vested on the anniversary of the grant date over a period of either two or three years.

◦	The 2015 awards vested in 2019 as both of the following were achieved: (a) the Compensation Committee of Sempra Energy’s board of directors determined that Sempra Energy achieved positive cumulative net income for fiscal years 2015 through 2017 and (b) Cameron LNG JV commenced commercial operations of the first train.

▪	Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest over three-year service periods (for awards granted in 2019), or at the end of three-year (for awards granted during 2015 through 2018) or four-year service periods (for awards granted prior to 2015).

---

(1)	Includes activity of awards issued from the IEnova 2013 LTIP, which settle in cash upon vesting based on the price of IEnova’s common stock.

---

▪	$4 million in 2019

▪	$9 million in 2018

▪	$9 million in 2017

---

(1)	Each RSU represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based RSUs, up to an additional 100% of the shares represented by the RSUs may be issued if Sempra Energy exceeds target performance conditions.

---

▪

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.

▪

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.

▪

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.

▪	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.

---

(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE. On August 14, 2019, OMEC LLC paid in full its variable-rate loan and terminated its interest rate swaps.

---

(1)	Included in Current Assets: Fixed-Price Contracts and Other Derivatives for SDG&E.

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

---

(1)	Included in Current Assets: Fixed-Price Contracts and Other Derivatives for SDG&E.

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

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

---

(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. On August 14, 2019, OMEC LLC paid in full its variable-rate loan and terminated its interest rate swaps.

---

---

▪

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.

---

(1)	Excludes cash balances and cash equivalents.

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

---

(1)	Excludes cash balances and cash equivalents.

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

---

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

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

---

---

(1)	Before reductions of unamortized discount and debt issuance costs of $225 million and excluding finance lease obligations of $1,289 million.

(2)	Before reductions of unamortized discount and debt issuance costs of $48 million and excluding finance lease obligations of $1,270 million.

(3)	Before reductions of unamortized discount and debt issuance costs of $34 million and excluding finance lease obligations of $19 million.

(4)	Level 3 instruments include $220 million related to Otay Mesa VIE.

(5)	Before reductions of unamortized discount and debt issuance costs of $206 million and excluding build-to-suit arrangement and capital lease obligations of $1,413 million.

(6)	Before reductions of unamortized discount and debt issuance costs of $49 million and excluding capital lease obligations of $1,272 million.

(7)	Before reductions of unamortized discount and debt issuance costs of $32 million and excluding capital lease obligations of $3 million.

---

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

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

---

---

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

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

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

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

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

---

▪	$367 million (net of underwriting discounts and equity issuance costs of $8 million) to cover overallotment shares of 3,504,672 in the first quarter of 2018 at a settlement price of $105.07 per share;

▪	$900 million (net of underwriting discounts of $16 million) from the settlement of 8,556,630 shares in the first quarter of 2018 at a forward sale price of $105.18 per share;

▪	$800 million (net of underwriting discounts of $14 million) from the settlement of 7,651,671 shares in the second quarter of 2018 at forward sale prices ranging from $104.53 to $104.58 per share; and

▪	$728 million (net of underwriting discounts of $13 million) from the settlement of 7,156,185 shares in the third quarter of 2019 at a forward sale price of $101.74 per share.

▪	$164 million (net of underwriting discounts and equity issuance costs of $3 million) to cover overallotment shares of 1,462,500 in the third quarter of 2018 at a settlement price of $111.87 per share; and

▪	$1,066 million (net of underwriting discounts of $18 million) from the settlement of 9,750,000 shares in the fourth quarter of 2019 at a forward sale price of $109.33 per share.

---

(1)	Includes fully vested RSUs held in our Deferred Compensation Plan of 617 in 2019, 641 in 2018 and 609 in 2017. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.

(2)	Due to market fluctuations of both Sempra Energy common stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 10, dilutive RSUs may vary widely from period-to-period.

---

(1)	Includes dividend equivalents.

(2)	Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares.

(3)	Generally, we purchase shares of our common stock or units from LTIP participants who elect to sell to us a sufficient number of vested RSUs to meet minimum statutory tax withholding requirements.

---

---

---

(1)	Maturity dates are 2021-2050.

(2)	Maturity dates are 2020-2056.

(3)	Maturity dates are 2020-2072.

---

---

---

---

---

---

---

---

(1)	Includes costs capitalized in PP&E.

(2)	Short-term leases with variable lease costs are recorded and presented as variable lease costs.

---

---

---

(1)	Included in Machinery and Equipment — Pipelines and Storage within the major functional categories of PP&E.

(1)	Included in Revenues: Energy-Related Businesses on the Consolidated Statements of Operations.

---

(1)	Excludes amounts related to the LNG purchase agreement discussed below.

---

▪	Long-term contracts: 27% (of which 26% is provided by renewable energy contracts expiring on various dates through 2041)

▪	Other SDG&E-owned generation and tolling contracts: 59%

▪	Spot market purchases: 14%

(1)	Excludes purchase agreements accounted for as finance leases.

▪	$49 million for infrastructure improvements for electric and natural gas transmission and distribution systems; and

▪	$8 million related to spent fuel management at SONGS.

---

▪	$567 million for liquid fuels terminals;

▪	$283 million for natural gas pipelines and ongoing maintenance services; and

▪	$126 million for renewables projects.

---

(1)	There may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.

---

(1)	Sites for which we have been identified as a PRP.

(2)	Includes $7 million, $1 million and $6 million classified as current liabilities, and $44 million, $4 million and $39 million classified as noncurrent liabilities on Sempra Energy’s, SDG&E’s and SoCalGas’ Consolidated Balance Sheets, respectively.

(3)	Does not include SDG&E’s liability for SONGS marine environment mitigation.

(4)	Does not include SoCalGas’ liability for environmental matters for the Leak at the Aliso Canyon natural gas storage facility. We discuss matters related to the Leak above in “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak.”

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

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

▪

Sempra Texas 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

---

---

---

(1)	Revenues for reportable segments include intersegment revenues of $5 million, $69 million, $120 million and $222 million for 2019; $4 million, $64 million, $114 million and $215 million for 2018; and $7 million, $74 million, $103 million and $266 million for 2017 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG, respectively.

(2)	As we discuss in Note 2, in accordance with adoption of the lease standard on January 1, 2019, 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 Interest Expense.

(3)	Includes net PP&E and investments.

(4)	Amounts are based on where the revenue originated, after intercompany eliminations.

---

(1)	EPS is computed independently for each of the quarters and therefore may not sum to the total for the year.

(2)	In the quarters ended September 30, 2019 and December 31, 2018, due to the dilutive effect of certain mandatory convertible preferred stock, the numerator used to calculate diluted EPS included an add-back of related mandatory convertible preferred stock dividends declared in those quarters.

(3)	In the quarter ended June 30, 2018, the total weighted-average potentially dilutive securities were not included in the computation of losses per common share since to do so would have decreased the loss per share.

---

---

---

---

---

---

---

▪	$61 million, $(6) million and $56 million of gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans in 2019, 2018 and 2017, respectively;

▪	$3 million and $50 million net gains primarily from the settlement of foreign currency derivatives to hedge Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova in 2018 and 2017, respectively; and

▪	$15 million losses in 2019 from foreign currency derivatives used to hedge exposure of fluctuations in the Peruvian Sol related to the sale of our operations in Peru.

(1)	Included in Other Long-Term Assets.

(2)	Included in Shareholders’ Equity.

---

▪	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.

---

(1)	Callable long-term debt not subject to make-whole provisions.

(2)	This arrangement is now accounted for as an operating lease liability upon adoption of the lease standard on January 1, 2019. See Note 2.