Document
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
(Mark One)
[ X ]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended
December 31, 2017
or
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from
 
to
 
Commission File No.
Exact Name of Registrants as Specified in their Charters, Address and Telephone Number
 
State of Incorporation
 
I.R.S. Employer
Identification Nos.
1-14201
SEMPRA ENERGY
 
California
 
33-0732627
 
488 8th Avenue
 
 
 
 
 
San Diego, California 92101
 
 
 
 
 
(619) 696-2000
 
 
 
 
 
 
 
 
 
 
1-03779
SAN DIEGO GAS & ELECTRIC COMPANY
 
California
 
95-1184800
 
8326 Century Park Court
 
 
 
 
 
San Diego, California 92123
 
 
 
 
 
(619) 696-2000
 
 
 
 
 
 
 
 
 
 
1-01402
SOUTHERN CALIFORNIA GAS COMPANY
 
California
 
95-1240705
 
555 West Fifth Street
 
 
 
 
 
Los Angeles, California 90013
 
 
 
 
 
(213) 244-1200
 
 
 
 
 
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each Class
 
Name of Each Exchange on Which Registered
Sempra Energy Common Stock, without par value
 
NYSE
 
 
 
Sempra Energy 6% Mandatory Convertible Preferred Stock, Series A,
NYSE
$100 liquidation preference
 
 
 
 
 
 
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
 
Southern California Gas Company Preferred Stock, $25 par value
 
6% Series A, 6% Series

 

1


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
 
 
 
 
 
Sempra Energy
Yes
X
No
 
San Diego Gas & Electric Company
Yes
 
No
X
Southern California Gas Company
Yes
 
No
X
 
 
 
 
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
 
 
 
 
 
Sempra Energy
Yes
 
No
X
San Diego Gas & Electric Company
Yes
 
No
X
Southern California Gas Company
Yes
 
No
X
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
 
 
 
 
 
 
Yes
X
No
 
 
 
 
 
 
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
 
 
 
 
 
 
Yes
X
No
 
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
 
 
 
 
 
Sempra Energy
 
 
 
X
San Diego Gas & Electric Company
 
 
 
X
Southern California Gas Company
 
 
 
X
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large
accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
Sempra Energy
[  X  ]
[      ]
[       ]
[      ]
[      ]
San Diego Gas & Electric Company
[       ]
[      ]
[  X  ]
[      ]
[      ]
Southern California Gas Company
[       ]
[      ]
[  X  ]
[      ]
[      ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
 
 
 
 
 
Sempra Energy
Yes
 
No
 
San Diego Gas & Electric Company
Yes
 
No
 
Southern California Gas Company
Yes
 
No
 

2


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
 
 
 
 
Sempra Energy
Yes
 
No
X
San Diego Gas & Electric Company
Yes
 
No
X
Southern California Gas Company
Yes
 
No
X
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2017:
 
 
Sempra Energy
$28.3 billion (based on the price at which the common equity was last sold as of the last business day of the most recently completed second fiscal quarter)
San Diego Gas & Electric Company
$0
Southern California Gas Company
$0
 
 
 
 
 
Common Stock outstanding, without par value, as of February 22, 2018:
 
Sempra Energy
255,324,212 shares
San Diego Gas & Electric Company
Wholly owned by Enova Corporation, which is wholly owned by Sempra Energy
Southern California Gas Company
Wholly owned by Pacific Enterprises, which is wholly owned by Sempra Energy
SAN DIEGO GAS & ELECTRIC COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY GENERAL INSTRUCTION I(2).
 
DOCUMENTS INCORPORATED BY REFERENCE:
 
Portions of the Sempra Energy Proxy Statement to be filed for its May 2018 annual meeting of shareholders are incorporated by reference into Part III of this annual report on Form 10-K.
 
Portions of the Southern California Gas Company Information Statement to be filed for its May 2018 annual meeting of shareholders are incorporated by reference into Part III of this annual report on Form 10-K.
 
 
 
 
 
 

3


SEMPRA ENERGY FORM 10-K

SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-K

SOUTHERN CALIFORNIA GAS COMPANY FORM 10-K
TABLE OF CONTENTS
 
Page
 
 
 
PART I
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
PART II
 
 
Item 5.
Item 6.
Item 7.
 
 
 
 
 
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
PART III
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
PART IV
 
 
Item 15.
Item 16.
 
 
 
 
 
 
This combined Form 10-K is separately filed by Sempra Energy, San Diego Gas & Electric Company and Southern California Gas Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.
You should read this report in its entirety as it pertains to each respective reporting company. No one section of the report deals with all aspects of the subject matter. Separate Item 6 and 8 sections are provided for each reporting company, except for the Notes to Consolidated Financial Statements in Item 8. The Notes to Consolidated Financial Statements for all of the reporting companies are combined. All Items other than Items 6 and 8 are combined for the reporting companies.

4


The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
GLOSSARY
 
 
 
2016 GRC FD
final decision in the California Utilities’ 2016 General Rate Case
AB
Assembly Bill
AFUDC
allowance for funds used during construction
ALJ
administrative law judge
AOCI
accumulated other comprehensive income (loss)
ARO
asset retirement obligation
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
Bankruptcy Court
U.S. Bankruptcy Court for the District of Delaware
Bay Gas
Bay Gas Storage Company, Ltd.
Bcf
billion cubic feet
BP
British Petroleum
bps
basis points
CAISO
California Independent System Operator
California Utilities
San Diego Gas & Electric Company and Southern California Gas Company, collectively
Cameron LNG JV
Cameron LNG Holdings, LLC
CARB
California Air Resources Board
CCA
Community Choice Aggregation
CCC
California Coastal Commission
CCM
cost of capital adjustment mechanism
CEC
California Energy Commission
CENAGAS
Centro Nacional de Control de Gas
CEQA
California Environmental Quality Act
CFCA
Core Fixed Cost Account
CFE
Comisión Federal de Electricidad (Federal Electricity Commission in Mexico)
Chilquinta Energía
Chilquinta Energía S.A. and its subsidiaries
CLF
Chilean Unidad de Fomento
CNE
Comisión Nacional de Energía (National Energy Commission) (Chile)
CNF
Cleveland National Forest
COFECE
Comisión Federal de Competencia Económica (Mexican Competition Commission)
CPCN
Certificate of Public Convenience and Necessity
CPED
Consumer Protection and Enforcement Division
CPI
Consumer Price Index
CPUC
California Public Utilities Commission
CRE
Comisión Reguladora de Energía (Energy Regulatory Commission in Mexico)
CRR
congestion revenue right
DA
Direct Access
DEN
Ductos y Energéticos del Norte, S. de R.L. de C.V.
DOE
U.S. Department of Energy
DOGGR
California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources
DOT
U.S. Department of Transportation
DPH
Los Angeles County Department of Public Health
ECA
Energía Costa Azul
Ecogas
Ecogas México, S. de R.L. de C.V.
Edison
Southern California Edison Company, a subsidiary of Edison International
EFH
Energy Future Holdings Corp.
EFIH
Energy Future Intermediate Holding Company LLC
EIR
environmental impact report
Eletrans
Eletrans S.A., Eletrans II S.A. and Eletrans III S.A., collectively
EMA
energy management agreement
EnergySouth
EnergySouth Inc.
Enova
Enova Corporation
EPA
U.S. Environmental Protection Agency

5


GLOSSARY (CONTINUED)
 
 
 
EPC
engineering, procurement and construction
EPS
earnings per common share
ERR
eligible renewable energy resource
ERRA
Energy Resource Recovery Account
ETR
effective income tax rate
EV
electric vehicle
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FTA
Free Trade Agreement
Gazprom
Gazprom Marketing & Trading Mexico
GCIM
Gas Cost Incentive Mechanism
GdC
Gasoductos de Chihuahua, S. de R.L. de C.V. (now known as IEnova Pipelines)
GHG
greenhouse gas
GRC
General Rate Case
HLBV
hypothetical liquidation at book value
HMRC
United Kingdom’s Revenue and Customs Department
IEnova
Infraestructura Energética Nova, S.A.B. de C.V.
IEnova Pipelines
IEnova Pipelines, S. de R.L. de C.V. (formerly known as GdC)
IMG
Infraestructura Marina del Golfo
IOU
investor-owned utility
IRS
Internal Revenue Service
ISFSI
independent spent fuel storage installation
IRC
U.S. Internal Revenue Code of 1986 (as amended)
ITC
investment tax credit
Joint Application
Joint Report and Application for Regulatory Approvals of Sempra Energy and Oncor Pursuant to PURA Sections 14.101, 39.262 and 39.915
JP Morgan
J.P. Morgan Chase & Co.
kV
kilovolt
kW
kilowatt
kWh
kilowatt hour
LA Storage
LA Storage, LLC
LA Superior Court
Los Angeles County Superior Court
LIFO
last in first out
LNG
liquefied natural gas
LPG
liquid petroleum gas
Luz del Sur
Luz del Sur S.A.A. and its subsidiaries
Merger
The merger of EFH with an indirect subsidiary of Sempra Energy, with EFH continuing as the surviving company and as an indirect, wholly owned subsidiary of Sempra Energy
 
Merger Agreement
Agreement and Plan of Merger dated August 21, 2017, as supplemented by a Waiver Agreement dated October 3, 2017 and an amendment dated February 15, 2018, between Sempra Energy, EFH, EFIH and an indirect subsidiary of Sempra Energy
 
Merger Consideration
Under the Merger Agreement, Sempra Energy will pay consideration of $9.45 billion in cash
Mexican Stock Exchange
La Bolsa Mexicana de Valores, S.A.B. de C.V., or BMV
MHI
Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc., collectively
Mississippi Hub
Mississippi Hub, LLC
MMBtu
million British thermal units (of natural gas)
MMcf
million cubic feet
Mobile Gas
Mobile Gas Service Corporation
Moody’s
Moody’s Investor Service
Mtpa
million tonnes per annum
MW
megawatt
MWh
megawatt hour
NAFTA
North American Free Trade Agreement
NDT
nuclear decommissioning trusts
NEIL
Nuclear Electric Insurance Limited

6


GLOSSARY (CONTINUED)
 
 
 
 
 
NEM
net energy metering
NEPA
National Environmental Policy Act
NOL
net operating loss
NRC
Nuclear Regulatory Commission
OCI
other comprehensive income (loss)
OII
Order Instituting Investigation
O&M
operation and maintenance expense
OMEC
Otay Mesa Energy Center
OMEC LLC
Otay Mesa Energy Center LLC
OMI
Oncor Management Investment LLC
Oncor
Oncor Electric Delivery Company LLC
Oncor Holdings
Oncor Electric Delivery Holdings Company LLC
ORA
CPUC Office of Ratepayer Advocates
OSINERGMIN
Organismo Supervisor de la Inversión en Energía y Minería (Energy and Mining Investment Supervisory Body) (Peru)
Otay Mesa VIE
OMEC LLC VIE
PBOP
postretirement benefits other than pension
PE
Pacific Enterprises
PEMEX
Petróleos Mexicanos (Mexican state-owned oil company)
PG&E
Pacific Gas and Electric Company
PHMSA
Pipeline and Hazardous Materials Safety Administration
PPA
power purchase agreement
PP&E
property, plant and equipment
PRP
Potentially Responsible Party
PSEP
Pipeline Safety Enhancement Plan
PTC
production tax credit
PUCT
Public Utility Commission of Texas
PURA
Public Utility Regulatory Act
QF
Qualifying Facility
RAMP
Risk Assessment Mitigation Phase
RBS
The Royal Bank of Scotland plc
RBS SEE
RBS Sempra Energy Europe
RBS Sempra Commodities
RBS Sempra Commodities LLP
REC
renewable energy certificate
REX
Rockies Express pipeline
Rockies Express
Rockies Express Pipeline LLC
ROE
return on equity
RPS
Renewables Portfolio Standard
RSA
restricted stock award
RSU
restricted stock unit
SB
Senate Bill
SCAQMD
South Coast Air Quality Management District
SDCA
U.S. District Court for the Southern District of California
SDG&E
San Diego Gas & Electric Company
SEC
U.S. Securities and Exchange Commission
SEDATU
Secretaría de Desarrollo Agrario, Territorial y Urbano (Mexican agency in charge of agriculture, land and urban development)
Sempra Global
holding company for Sempra Energy subsidiaries not subject to California or Texas utility regulation
SFP
secondary financial protection
SGRP
Steam Generator Replacement Project
Shell
Shell México Gas Natural
SoCalGas
Southern California Gas Company
SONGS
San Onofre Nuclear Generating Station
SONGS OII
CPUC’s Order Instituting Investigation into the SONGS Outage
the Stipulation
settlement agreement between Sempra Energy, Oncor and key stakeholders in the PUCT proceeding regarding the Joint Application

7


GLOSSARY (CONTINUED)
 
 
 
 
 
S&P
Standard & Poor’s
TAG
TAG Pipelines Norte, S. de R.L. de C.V.
Tangguh PSC
Tangguh PSC Contractors
TCJA
Tax Cuts and Jobs Act of 2017
TdM
Termoeléctrica de Mexicali
Tecnored
Tecnored S.A.
Tecsur
Tecsur S.A.
TO4
Electric Transmission Formula Rate, effective through December 31, 2018
TO5
Electric Transmission Formula Rate, new application
TOU
time-of-use
TransCanada
TransCanada Corporation
Tribunal
International Chamber of Commerce International Court of Arbitration Tribunal
TTI
Texas Transmission Investment LLC
TURN
The Utility Reform Network
U.S. GAAP
accounting principles generally accepted in the United States of America
Valero Energy
Valero Energy Corporation
VaR
value at risk
VAT
value-added tax
Ventika
Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V., collectively
VIE
variable interest entity
Vistra
Vistra Energy Corp.
Willmut Gas
Willmut Gas Company


8


 
 
 
 
 
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
We make statements in this report that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based upon assumptions with respect to the future, involve risks and uncertainties, and are not guarantees of performance. Future results may differ materially from those expressed in the forward-looking statements. These forward-looking statements represent our estimates and assumptions only as of the filing date of this report. We assume no obligation to update or revise any forward-looking statement as a result of new information, future events or other factors.
In this report, when we use words such as “believes,” “expects,” “anticipates,” “plans,” “estimates,” “projects,” “forecasts,” “contemplates,” “assumes,” “depends,” “should,” “could,” “would,” “will,” “confident,” “may,” “can,” “potential,” “possible,” “proposed,” “target,” “pursue,” “outlook,” “maintain,” or similar expressions, or when we discuss our guidance, strategy, plans, goals, opportunities, projections, initiatives, objectives or intentions, we are making forward-looking statements.
Factors, among others, that could cause our actual results and future actions to differ materially from those described in any forward-looking statements include risks and uncertainties relating to:
actions and the timing of actions, including decisions, new regulations, and issuances of permits and other authorizations by the CPUC, DOE, DOGGR, FERC, EPA, PHMSA, DPH, states, cities and counties, and other regulatory and governmental bodies in the U.S. and other countries in which we operate;
the timing and success of business development efforts and construction projects, including risks in obtaining or maintaining permits and other authorizations on a timely basis, risks in completing construction projects on schedule and on budget, and risks in obtaining the consent and participation of partners;
the resolution of civil and criminal litigation and regulatory investigations;
deviations from regulatory precedent or practice that result in a reallocation of benefits or burdens among shareholders and ratepayers; approvals of proposed settlements or modifications of settlements; and delays in, or disallowance or denial of, regulatory agency authorizations to recover costs in rates from customers (including with respect to amounts associated with the SONGS facility and 2007 wildfires) or regulatory agency approval for projects required to enhance safety and reliability;
the greater degree and prevalence of wildfires in California in recent years and risk that we may be found liable for damages regardless of fault, such as in cases where the doctrine of inverse condemnation applies, and risk that we may not be able to recover any such costs in rates from customers in California;
the risk that rulings by the CPUC such as denying recovery for wildfire damages may raise our cost of capital and materially impair our ability to finance our operations;
the availability of electric power, natural gas and liquefied natural gas, and natural gas pipeline and storage capacity, including disruptions caused by failures in the transmission grid, moratoriums or limitations on the withdrawal or injection of natural gas from or into storage facilities, and equipment failures;
changes in energy markets; volatility in commodity prices; moves to reduce or eliminate reliance on natural gas; and the impact on the value of our investments in natural gas storage and related assets from low natural gas prices, low volatility of natural gas prices and the inability to procure favorable long-term contracts for storage services;
risks posed by actions of third parties who control the operations of our investments, and risks that our partners or counterparties will be unable or unwilling to fulfill their contractual commitments;
weather conditions, natural disasters, accidents, equipment failures, computer system outages, explosions, terrorist attacks and other events that disrupt our operations, damage our facilities and systems, cause the release of GHG, radioactive materials and harmful emissions, cause wildfires and subject us to third-party liability for property damage or personal injuries, fines and penalties, some of which may not be covered by insurance (including costs in excess of applicable policy limits), may be disputed by insurers or may otherwise not be recoverable through regulatory mechanisms or may impact our ability to obtain satisfactory levels of insurance, to the extent that such insurance is available or not prohibitively expensive;
cybersecurity threats to the energy grid, storage and pipeline infrastructure, the information and systems used to operate our businesses and the confidentiality of our proprietary information and the personal information of our customers and employees;
capital markets and economic conditions, including the availability of credit and the liquidity of our investments; and fluctuations in inflation, interest and currency exchange rates and our ability to effectively hedge the risk of such fluctuations;
the impact of recent federal tax reform and uncertainty as to how it may be applied, and our ability to mitigate any adverse impacts;
actions by rating agencies to downgrade our credit ratings or those of our subsidiaries or to place those ratings on negative outlook;

9


changes in foreign and domestic trade policies and laws, including border tariffs, and revisions to international trade agreements, such as NAFTA, that make us less competitive or impair our ability to resolve trade disputes;
the ability to win competitively bid infrastructure projects against a number of strong and aggressive competitors;
expropriation of assets by foreign governments and title and other property disputes;
the impact on reliability of SDG&E’s electric transmission and distribution system due to increased amount and variability of power supply from renewable energy sources;
the impact on competitive customer rates due to the growth in distributed and local power generation and the corresponding decrease in demand for power delivered through SDG&E’s electric transmission and distribution system and from possible departing retail load resulting from customers transferring to DA and CCA or other forms of distributed and local power generation and the potential risk of nonrecovery for stranded assets and contractual obligations; and
other uncertainties, some of which may be difficult to predict and are beyond our control.
Forward-looking statements also include statements about the anticipated benefits of the proposed Merger involving Sempra Energy, EFH, and EFH’s 80.03 percent indirect interest in Oncor, including future financial or operating results of Sempra Energy or Oncor, Sempra Energy’s, EFH’s or Oncor’s plans, objectives, expectations or intentions, the anticipated impact of the Merger, if consummated, on the credit ratings of Sempra Energy or Oncor, the expected timing of completion of the Merger, plans regarding future capital investments by Sempra Energy or Oncor, future ROE or capital structure of Sempra Energy or Oncor, and other statements that are not historical facts.
Additional factors, among others, that could cause our actual results and future actions to differ materially from those described in any forward-looking statements include risks and uncertainties relating to:
the risk that Sempra Energy, EFH or Oncor may be unable to satisfy all closing conditions including obtaining governmental and regulatory approvals required for the Merger, or that required governmental and regulatory approvals may delay the Merger or result in the imposition of conditions that could cause the parties to abandon the Merger or be onerous to Sempra Energy;
the risk that the Merger may not be completed for other reasons, or may not be completed on the terms or timing currently contemplated;
the risk that the anticipated benefits from the Merger may not be fully realized or may take longer to realize than expected and that liabilities that survive the bankruptcy will be greater than we anticipate;
the risk that Sempra Energy may be unable to obtain additional permanent equity financing for the Merger on favorable terms;
the risk that indebtedness Sempra Energy incurs in connection with the Merger may make it more difficult for Sempra Energy to repay or refinance its debt or take other actions, which may decrease business flexibility and increase borrowing costs;
the diversion of management time and attention to Merger-related issues and related costs, whether or not the Merger is completed, as well as disruptions to our business; and
the risk that Oncor will eliminate or reduce its quarterly dividends due to its requirement to meet and maintain its new regulatory capital structure, or because any of the three major rating agencies rates Oncor’s senior secured debt securities below BBB (or the equivalent) or Oncor’s independent directors or a minority member director determine that it is in the best interest of Oncor to retain such amounts to meet future capital expenditures.
We caution you not to rely unduly on any forward-looking statements. You should review and consider carefully the risks, uncertainties and other factors that affect our business as described herein and other reports that we file with the SEC.


10


PART I.

 
 
 
 
 
ITEM 1. BUSINESS
This report on Form 10-K includes information for the following separate registrants:
Sempra Energy and its consolidated entities
SDG&E and its consolidated VIE
SoCalGas
References in this report to “we,” “our,” “us,” “our company” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by the context. SDG&E and SoCalGas are collectively referred to as the California Utilities.
OVERVIEW
We are a Fortune 500 energy-services holding company. Our operating units invest in, develop and operate energy infrastructure, and provide electric and gas services to customers in North and South America. We were formed in 1998 through a business combination of Enova and PE, the holding companies of our regulated public utilities in California: SDG&E, which began operations in 1881, and SoCalGas, which began operations in 1867. Since our formation in 1998, we have expanded our investment in regulated utility operations through business acquisitions in 2011 in South America. Additionally, in response to changes in Mexican gas regulation in 1995, we entered the energy infrastructure business in Mexico through what is now known as IEnova, the first energy infrastructure company to be listed on the Mexican Stock Exchange. Our energy infrastructure footprint continues to expand across the U.S., through renewable energy generation projects and LNG and natural gas midstream projects and assets. In August 2017, we entered into the Merger Agreement to acquire an indirect ownership interest in Oncor, a regulated electric distribution and transmission business that operates the largest distribution and transmission system in Texas. We expect the Merger to close in the first half of 2018.
We have two principal operating units, Sempra Utilities and Sempra Infrastructure. Sempra Utilities includes SDG&E, SoCalGas and Sempra South American Utilities. Sempra Infrastructure includes Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream. If the Merger is consummated, our investment in Oncor will be included in a new reportable segment within the Sempra Utilities operating unit.
All references to “Sempra Utilities” and “Sempra Infrastructure” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name. Sempra Infrastructure also owns or owned (during periods presented in this report) regulated utilities that are not included in our references to the Sempra Utilities. We provide financial information about all our reportable segments and about the geographic areas in which we do business in Note 16 of the Notes to Consolidated Financial Statements.
Business Strategy
Our objective is to increase shareholder value by developing, investing in and operating utilities and long-term-contracted energy infrastructure assets and operating our companies in a safe and reliable manner.
The key components of our strategy include the following disciplined growth platforms:
U.S. and South American regulated utilities
U.S. and Mexican energy infrastructure
Operating within these areas, we are focused on generating stable, predictable earnings and cash flows by investing in assets that are primarily regulated or contracted on a long-term basis. We have a robust capital program and take a disciplined approach to deploying this capital to areas that fit our strategy and are designed to create shareholder value.
PENDING ACQUISITION
Energy Future Holdings Corp.

11


On August 21, 2017, Sempra Energy entered into an Agreement and Plan of Merger, as supplemented by a Waiver Agreement dated October 3, 2017 and an amendment dated February 15, 2018 (together referred to as the Merger Agreement), with Energy Future Holdings Corp., the indirect owner of 80.03 percent of Oncor Electric Delivery Company LLC. Oncor is a regulated electric distribution and transmission business that operates the largest distribution and transmission system in Texas. Following closing, this acquisition will expand our regulated earnings base, while serving as a platform for future growth in the Texas energy market and U.S. Gulf Coast region. Under the Merger Agreement, we will pay the Merger Consideration of $9.45 billion in cash. Pursuant to the Merger Agreement and subject to the satisfaction of certain closing conditions described below, EFH will be merged with an indirect subsidiary of Sempra Energy, with EFH continuing as the surviving company and an indirect, wholly owned subsidiary of Sempra Energy (the Merger). The terms and conditions of the Merger Agreement (and a related letter agreement with Oncor) are described in more detail in Sempra Energy’s current reports on Form 8-K filed with the SEC on August 25, 2017, August 28, 2017 and October 6, 2017. The amendment dated February 15, 2018 (the Amendment) was made in connection with a settlement agreement, dated as of February 5, 2018, by and among the parties to the Merger Agreement and certain of their subsidiaries. The Amendment amends certain merger terms, in accordance with the settlement agreement, that relate to Oncor dividend payments and certain adjustments to the Merger Consideration. The Amendment is provided in its entirety by reference to Exhibit 2.1.3, filed herewith.
Ring-Fencing
In April 2014, EFH and the substantial majority of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the Bankruptcy Court. The bankruptcy does not include Oncor or Oncor Holdings. Oncor Holdings owns 80.03 percent of Oncor and is indirectly wholly owned by EFH. Certain existing “ring-fencing” measures, governance mechanisms and restrictions will remain in effect following the Merger, which are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, EFH or its other subsidiaries or the owners of EFH. In accordance with the ring-fencing measures and commitments made by Sempra Energy as part of the Joint Application to the PUCT for regulatory approval of the Merger, Sempra Energy and Oncor will be subject to certain restrictions following the Merger. Sempra Energy will not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and restrictions, as well as the Stipulation discussed below and elsewhere herein, will limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions. Thus, Oncor Holdings and Oncor will continue to be managed independently (i.e., ring-fenced). Upon consummation of the Merger, although we will consolidate EFH, EFH will continue to account for its ownership in Oncor Holdings as an equity method investment.
Settlement Agreement Regarding Joint Application
On October 5, 2017, Sempra Energy and Oncor filed a Joint Application with the PUCT and an application with the FERC seeking approval of the Merger. In December 2017, Sempra Energy and Oncor entered into a comprehensive Stipulation with the Staff of the PUCT, the Office of the Public Utility Counsel, the Steering Committee of Cities Served by Oncor and the Texas Industrial Energy Consumers, reflecting the parties’ settlement of all issues in the PUCT proceeding regarding the Joint Application. Pursuant to the Stipulation, the parties have agreed that Sempra Energy’s acquisition of EFH is in the public interest and will bring substantial benefits. The parties to the Stipulation also agreed to ask the PUCT to approve the Merger, consistent with the governance, regulatory and operating commitments outlined in the Stipulation.
The Stipulation includes regulatory commitments by us, as described below and elsewhere herein, most of which are similar to the regulatory commitments made by us as part of the Joint Application and are consistent with the “ring-fencing” measures currently in place. Sempra Energy and Oncor are entitled to seek modifications of the PUCT order to be entered in the proceedings regarding the Joint Application, which modifications would be subject to PUCT approval.
While Oncor’s Limited Liability Company Agreement generally provides that Oncor will make quarterly distributions to its members equal to the net income of Oncor, subject to certain exceptions, and Oncor Holdings’ Limited Liability Company Agreement generally provides that Oncor Holdings will make quarterly distributions to its member equal to the dividends received by Oncor, subject to certain exceptions, the Stipulation provides a number of circumstances in which Oncor is not permitted to make dividends or other distributions (except for contractual tax payments). In addition, the Stipulation provides that the respective boards of Oncor and Oncor Holdings will control each respective company’s dividend policy (and any changes to such policy must be approved by a majority of its independent directors), issuances of dividends and other distributions (except for contractual tax payments). The Stipulation also provides that the respective boards of Oncor and Oncor Holdings will control each respective company’s debt issuances, capital expenditures, operation and maintenance expenditures, management and service fees, and, subject to certain limitations, appointment or removal of board members.

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If the PUCT does not accept the Stipulation as presented, or issues an order inconsistent with the terms of the Stipulation, the parties have agreed that any party adversely affected by the alteration has the right to withdraw from the Stipulation and to exercise all rights available to such party under the law.
On January 5, 2018, Oncor, Sempra Energy and Staff of the PUCT jointly filed with the PUCT, requesting that the PUCT approve the Merger consistent with the Stipulation. As of January 31, 2018, all 10 intervening parties, including the Staff of the PUCT, agreed to the Stipulation.
We discuss the Merger and financing of the Merger Consideration, ring-fencing measures, additional regulatory commitments, governance mechanisms and restrictions, as well as the Stipulation, in Notes 3 and 18 of the Notes to Consolidated Financial Statements, “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Factors Influencing Future Performance.”
Closing Conditions
The Merger is subject to customary closing conditions, including the approval of the PUCT. Certain conditions, such as approval from the Bankruptcy Court, the FERC, the Vermont Department of Financial Regulation and receipt of a private letter ruling from the IRS, have been satisfied. If the required governmental consents and approvals are not received, or if they are not received on terms that satisfy the closing conditions in the Merger Agreement, the Merger could be abandoned, delayed or restructured.
The Merger Agreement provides that it will terminate if the Merger is not consummated by April 18, 2018, subject to limited exceptions. One of those exceptions provides that, if the Merger is not consummated because the requisite PUCT approval has not been obtained by April 18, 2018, but such approval is still capable of being obtained within 90 days thereafter, the April 18, 2018 date shall be extended for 90 days for purposes of continuing to pursue such approval, unless otherwise agreed by EFH and EFIH (acting together) and Sempra Energy.
We currently expect that the Merger will close in the first half of 2018, although there can be no assurance that the Merger will be completed on that timetable, or at all.
OUR SEGMENTS
No single customer accounted for 10 percent or more of Sempra Energy’s consolidated revenues in 2017, 2016 or 2015.
SDG&E
SDG&E is a regulated public utility that provides electric services to a population of approximately 3.6 million and natural gas services to approximately 3.3 million of that population, covering a 4,100 square mile service territory in Southern California that encompasses San Diego County and an adjacent portion of southern Orange County.
Electric Utility Operations
Customers and Demand. SDG&E provides electric services through the generation, transmission and distribution of electricity to the following customer classes:
SDG&E  ELECTRIC CUSTOMER METERS AND VOLUMES
 
 
 
Customer meter count
 
Volumes(1)
(millions of kWh)
 
 
December 31,
 
Years ended December 31,
 
 
2017
 
2017
2016
2015
Residential
1,286,200

 
6,577

6,685

7,143

Commercial
152,000

 
6,763

6,700

6,877

Industrial
400

 
2,198

2,189

2,161

Street and highway lighting
2,000

 
79

75

83

 
1,440,600

 
15,617

15,649

16,264

Direct access
4,900

 
3,394

3,515

3,652

 
Total
1,445,500

 
19,011

19,164

19,916

(1) 
Includes intercompany sales.

No single customer accounted for 10 percent or more of SDG&E’s revenues from electricity sold in 2017, 2016 or 2015.

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SDG&E’s system average rate is based on authorized revenue requirements divided by authorized sales volumes. SDG&E’s system average rate was $0.238, $0.206 and $0.218 per kWh in 2017, 2016 and 2015, respectively. The 2017 increase compared to 2016 was primarily the result of undercollected power costs in 2016. The 2016 decrease compared to 2015 was driven by the inclusion in 2015 of undercollections associated with activities prior to 2015, including the delay in implementing into rates the increases associated with the 2012 GRC. A significant proportion of SDG&E’s costs to operate are independent of sales volumes, which can contribute to system average rate variances as sales volumes change.
An electric utility’s system average rate can be affected by numerous factors, which are not necessarily common to other utilities regionally or nationally. In general, the utilization of a typical electric utility’s distribution assets is significantly less than their capacity because the assets are designed to meet peak needs. Compared to the typical utility in the U.S., SDG&E delivers a higher relative percentage of its total power sold to residential customers, who on average consume less power than an average commercial customer. San Diego’s mild climate and SDG&E’s robust energy efficiency programs also contribute to lower consumption by our customers. In addition, rooftop solar installations, especially in recent years, have reduced residential and commercial volumes sold by SDG&E. As of December 31, 2017, 2016 and 2015, the residential and commercial rooftop solar capacity in SDG&E’s territory totaled 836 MW, 694 MW and 496 MW, respectively. All these factors contribute to generally higher system average rates, where the cost of building and operating our assets is spread over a relatively smaller sales volume.
In addition to these factors, SDG&E’s CPUC-approved rate design includes a tiered residential pricing structure. We discuss electric rate reform further in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”
Demand for electricity is dependent on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preference, environmental regulations, legislation, renewable power generation, the effectiveness of energy efficiency programs, demand-side management goals and distributed generation resources. California’s energy policy supports increased electrification, particularly electrification of vehicles, which could result in significant increases in sales volumes in the coming years. Other external factors, such as the price of purchased power, the use of hydroelectric power, development of renewable energy resources, development of new natural gas supply sources, demand for natural gas, and general economic conditions, can also result in significant shifts in the market price of electricity, which may in turn impact demand. Demand for electricity is also impacted by seasonal weather patterns (or “seasonality”), tending to increase in the summer months to meet cooling load and in the winter months to meet heating load.
Electric Resources. To meet customer demand, SDG&E procures power from its own electric generation facilities and from other suppliers through CPUC-approved purchased-power contracts or through purchases on a spot basis. SDG&E’s supply as of December 31, 2017 is as follows:
SDG&E – ELECTRIC RESOURCES(1)
 
 
Contract
Net operating
 
 
expiration date
capacity (MW)
% of total
Owned generation facilities, natural gas(2)
 
1,193

22
%
Purchased-power contracts:
 
 
 
Qualifying facilities
2019 to 2026
246

5

Renewables:
 
 
 
Wind
2018 to 2035
1,234

23

Solar
2030 to 2041
1,306

24

Other
2018 and thereafter
53

1

Tolling and other(3)
2019 to 2042
1,341

25

Total
 
5,373

100
%
(1) 
Excludes approximately 114 MW of battery storage owned (including 70 MW pending CPUC approval) and approximately 13.5 MW of battery storage contracted (all pending CPUC approval).
(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.
(3) 
Includes Otay Mesa VIE.

SDG&E is required to interconnect with and purchase power from QFs, a class of generating facilities established by the Public Utility Regulatory Policies Act of 1978, at rates that do not exceed SDG&E’s avoided cost. For SDG&E, QFs include cogeneration facilities, which produce electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, residential or institutional purposes. Charges under most of the contracts with QFs are based on what it

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would incrementally cost SDG&E to produce the power or procure it from other sources. Charges under the contracts with other suppliers are for firm and as-generated energy, and are based on the amount of energy received or are tolls based on available capacity. Tolling contracts are purchased-power contracts under which SDG&E provides natural gas for generation to the energy supplier. The prices under these contracts include 193 MW at prices that are based on the market value at the time the contracts were negotiated.
SDG&E provides bundled electric procurement service through various resources that are typically procured on a long-term basis, as shown above. While SDG&E provides such procurement service for the majority of its customer load, customers do have the ability to receive procurement service from a load serving entity other than SDG&E, through programs such as DA and CCA. DA is currently closed to new entrants, but utility customers can receive procurement through CCA, if the customer’s local jurisdiction (city) offers such a program. A number of cities in our service territory have expressed interest in CCA, which, if widely adopted, could result in substantial reductions in the load we are required to serve. For example, Solana Beach (representing less than 1 percent of SDG&E’s customer accounts) has elected to begin CCA service in 2018. When customers are served by another load serving entity, SDG&E no longer serves this departing load and the associated costs of the utility’s procured resources are otherwise borne by its remaining bundled procurement customers. The CPUC has tried to address this issue by adopting rate mechanisms that attempt to ensure bundled customer indifference in the event of departing load, but these existing mechanisms may not be sufficient to address the full extent of the potential cost shift in the event of significant departing load, and SDG&E bears some risk that its procured resources could become stranded without recovery of the associated costs.
Natural Gas Supply for Generation Facilities. SDG&E procures natural gas under short-term contracts for its owned generation facilities and for certain tolling contracts associated with purchased-power arrangements. Purchases are from various southwestern U.S. suppliers and are primarily priced based on published monthly bid-week indices.
Power Pool. SDG&E is a participant in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement that allows access to power trading with more than 300 member utilities, power agencies, energy brokers and power marketers located throughout the U.S. and Canada. Participants can make power transactions on standardized terms, including market-based rates, preapproved by the FERC. Participation in the Western Systems Power Pool is intended to assist members in managing power delivery and price risk.
Electric Transmission and Distribution System. Service to SDG&E’s customers is supported by its electric transmission and distribution system. At December 31, 2017, SDG&E’s electric transmission and distribution facilities included substations and overhead and underground lines. These electric facilities are in San Diego, Imperial and Orange counties of California, and in Arizona and Nevada. The facilities consist of 2,090 miles of transmission lines, 23,479 miles of distribution lines and 160 substations. Periodically, various areas of the service territory require expansion to accommodate customer growth, reliability and safety.
SDG&E’s 500-kV Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego, California. SDG&E’s share of the line is 1,162 MW, although it can be less under certain system conditions. SDG&E’s Sunrise Powerlink is a 500-kV transmission line constructed and operated by SDG&E with import capability of 1,000 MW of power.
Mexico’s Baja California transmission system is connected to SDG&E’s system via two 230-kV interconnections with combined capacity of up to 408 MW in the north-to-south direction and 800 MW in the south-to-north direction, although it can be less under certain system conditions.
Edison’s transmission system is connected to SDG&E’s system via five 230-kV transmission lines.
Competition. SDG&E faces competition to serve its customer load from the growth in distributed and local power generation, including rooftop solar installations, battery storage, and the corresponding decrease in demand for power delivered through SDG&E’s electric transmission and distribution system and from possible departing retail load resulting from customers transferring to DA and CCA. SDG&E does not earn any return on commodity sales.
Natural Gas Utility Operations
We discuss SDG&E’s natural gas utility operations below in “California Utilities’ Natural Gas Utility Operations.”
Key Noncash Performance Indicators
We use certain financial and non-financial metrics to measure how effective our businesses are in achieving their key business objectives. For SDG&E, these key noncash performance indicators include number of customers, electricity sold, system average rate and natural gas volumes transported and sold. Additional noncash performance indicators include goals related to safety,

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customer service, customer reputation, environmental considerations (including quantities of renewable energy purchases), on-time and on-budget completion of major projects and initiatives, and service reliability.
SoCalGas
SoCalGas is a regulated public utility that owns and operates a natural gas distribution, transmission and storage system that supplies natural gas to a population of approximately 21.8 million, covering a 24,000 square mile service territory that encompasses Southern California and portions of central California (excluding San Diego County, the city of Long Beach and the desert area of San Bernardino County).
Natural Gas Utility Operations
We provide additional information on SoCalGas’ natural gas utility operations below in “California Utilities’ Natural Gas Utility Operations.”
Key Noncash Performance Indicators
Key noncash performance indicators for SoCalGas include number of customers and natural gas volumes transported and sold. Additional noncash performance indicators include goals related to safety, customer service, customer reputation, environmental considerations, natural gas demand by customer segment, on-time and on-budget completion of major projects and initiatives, and service reliability.
California Utilities Natural Gas Utility Operations
Customers and Demand
SoCalGas and SDG&E sell, distribute and transport natural gas. SoCalGas purchases and stores natural gas for its core customers and SDG&E’s core customers on a combined portfolio basis and provides natural gas storage services for others.
CALIFORNIA UTILITIES – NATURAL GAS CUSTOMER METERS AND VOLUMES
 
 
Customer meter count
 
Volumes (Bcf)(1)
 
December 31,
 
Years ended December 31,
 
2017
 
2017
2016
2015
SDG&E:
 
Residential
850,800

 
 
 
 
Commercial
28,700

 
 
 
 
Electric generation and transportation
3,700

 
 
 
 
 
 
 
 
 
 
Natural gas sales
 
 
40

40

38

Transportation
 
 
35

31

35

Total
883,200

 
75

71

73

 
 
SoCalGas:
 
Residential
5,689,400

 
 
 
 
Commercial
247,700

 
 
 
 
Industrial
25,600

 
 
 
 
Electric generation and wholesale
40

 
 
 
 
 
 
 
 
 
 
Natural gas sales
 
 
301

294

291

Transportation
 
 
603

610

634

Total
5,962,740

 
904

904

925

(1) 
Includes intercompany sales.

For regulatory purposes, end-use customers are classified as either core or noncore customers. Core customers are primarily residential and small commercial and industrial customers.
Most core customers purchase natural gas directly from SoCalGas or SDG&E. While core customers are permitted to purchase directly from producers, marketers or brokers, the California Utilities are obligated to provide reliable supplies of natural gas to serve the requirements of their core customers. A substantial portion of SoCalGas’ revenues are from core customers.

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Noncore customers at SoCalGas consist primarily of electric generation, wholesale, large commercial and industrial, and enhanced oil recovery customers. A portion of SoCalGas’ noncore customers are non-end-users. SoCalGas’ non-end-users include wholesale customers consisting primarily of other IOUs, including SDG&E, or municipally owned natural gas distribution systems. Noncore customers at SDG&E consist primarily of electric generation and large commercial customers.
Noncore customers are responsible for the procurement of their natural gas requirements, as the regulatory framework does not allow us to recover the actual cost of natural gas procured and delivered to noncore customers.
No single customer accounted for 10 percent or more of SoCalGas’ or SDG&E’s revenues from natural gas operations in 2017, 2016 or 2015.
Demand for natural gas largely depends on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preference, environmental regulations, legislation, California’s energy policy supporting increased electrification and renewable power generation, and the effectiveness of energy efficiency programs. Other external factors such as weather, the price of electricity, the use of hydroelectric power, development of renewable energy resources, development of new natural gas supply sources, demand for natural gas outside the state of California, and general economic conditions, can also result in significant shifts in market price, which may in turn impact demand.
One of the larger sources for natural gas demand is electric generation. Natural gas-fired electric generation within Southern California (and demand for natural gas supplied to such plants) competes with electric power generated throughout the western U.S. Natural gas transported for electric generating plant customers may be affected by the overall demand for electricity, growth in renewable generation (including rooftop solar), the addition of more efficient gas technologies, new energy efficiency initiatives, and the extent that regulatory changes in electric transmission infrastructure investment divert electric generation from the California Utilities’ respective service areas. The demand for natural gas may also fluctuate due to volatility in the demand for electricity due to climate change, weather conditions and other impacts, and the availability of competing supplies of electricity such as hydroelectric generation and other renewable energy sources. Given the significant quantity of natural gas-fired generation, natural gas is the dispatchable fuel of choice to help ensure electric reliability in our California service territories.
The natural gas distribution business is seasonal, and cash provided from operating activities generally is greater during and immediately following the winter heating months. As is prevalent in the industry, but subject to current regulatory limitations, SoCalGas usually injects natural gas into storage during the summer months (April through October), which reduces cash provided by operating activities during this period, and usually withdraws natural gas from storage during the winter months (November through March), which increases cash provided by operating activities, when customer demand is higher.
Natural Gas Procurement and Transportation
At December 31, 2017, SoCalGas’ natural gas facilities include 2,964 miles of transmission and storage pipelines, 50,577 miles of distribution pipelines, 47,779 miles of service pipelines and nine transmission compressor stations, while SDG&E’s natural gas facilities consist of 168 miles of transmission pipelines, 8,928 miles of distribution pipelines, 6,503 miles of service pipelines and one compressor station.
SoCalGas purchases natural gas under short-term and long-term contracts for the California Utilities’ residential and smaller business customers. SoCalGas purchases natural gas from various sources, including from Canada, the U.S. Rockies and the southwestern regions of the U.S. Purchases of natural gas are primarily priced based on published monthly bid-week indices.
To help ensure the delivery of natural gas supplies to its distribution system and to meet the seasonal and annual needs of customers, SoCalGas has firm interstate pipeline capacity contracts that require the payment of fixed reservation charges to reserve firm transportation rights. Pipeline companies, primarily El Paso Natural Gas Company, Transwestern Pipeline Company, PG&E and Kern River Gas Transmission Company, provide transportation services into SoCalGas’ intrastate transmission system for supplies purchased by SoCalGas or its transportation customers from outside of California.
Natural Gas Storage
SoCalGas owns four natural gas storage facilities. These facilities have a combined working gas capacity of 137 Bcf and have over 200 injection, withdrawal and observation wells that provide natural gas storage services for core, noncore and non-end-use customers. SoCalGas’ and SDG&E’s core customers are allocated a portion of SoCalGas’ storage capacity. SoCalGas offers the remaining storage capacity for sale to others, including SDG&E for its non-core customer requirements, through an open bid process. Natural gas withdrawn from storage is important for ensuring service reliability during peak demand periods, including heating needs in the winter, as well as peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility represents 63 percent of SoCalGas’ natural gas storage capacity. SoCalGas discovered a natural gas leak at one of its wells at the Aliso Canyon natural gas storage facility in October 2015, and permanently sealed the well in February 2016. SoCalGas ceased

17


injecting natural gas into the Aliso Canyon natural gas storage facility on October 25, 2015, pursuant to orders from DOGGR and the Governor of California, and SB 380. Limited withdrawals and injections of natural gas at the Aliso Canyon natural gas storage facility were authorized to recommence in 2017. We discuss the Aliso Canyon natural gas leak in Note 15 of the Notes to Consolidated Financial Statements, in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance” and in “Item 1A. Risk Factors.”
Sempra South American Utilities
Sempra South American Utilities develops, owns and operates, or holds interests in electric transmission, distribution and generation infrastructure through its two utilities, Chilquinta Energía in Chile and Luz del Sur in Peru. It also owns interests in two energy-services companies, Tecnored and Tecsur, that provide electric construction and infrastructure services to Chilquinta Energía and Luz del Sur, respectively, as well as third parties. Tecnored also sells electricity to non-regulated customers.
Chilquinta Energía S.A.
Chilquinta Energía, a wholly owned subsidiary of Sempra South American Utilities, is an electric distribution utility serving a population of approximately two million in the region of Valparaíso in central Chile, with a service area covering 4,400 square miles. Chilquinta Energía also serves a population of approximately 130,000 in the communities of Parral and Linares in the south-central region of Maule in Chile. Chilquinta Energía is the third largest distributor of electricity in Chile, with close to a 10-percent share of the market.
Customers and Demand. Chilquinta Energía provides electric services through the transmission and distribution of electricity to the following customer classes:
CHILQUINTA ENERGÍA – ELECTRIC CUSTOMER METERS AND VOLUMES
 
 
 
Customer meter count
 
Volumes
(millions of kWh)
 
 
December 31,
 
Years ended December 31,
 
 
2017
 
2017
2016
2015
Residential
650,133

 
1,136

1,104

1,097

Commercial
44,212

 
1,211

1,178

1,175

Industrial
1,438

 
500

527

520

Street and highway lighting
8,016

 
89

91

95

 
703,799

 
2,936

2,900

2,887

Tolling
14

 
98

90

74

 
Total
703,813

 
3,034

2,990

2,961


In Chile, customers are classified as regulated and non-regulated customers based on installed capacity. Regulated customers are those whose installed capacity is less than 500 kW. Non-regulated customers are those whose installed capacity is greater than 5,000 kW. Customers with installed capacity between 500 kW and 5,000 kW may choose to be classified as regulated or non-regulated. Non-regulated customers that can buy power from other sources, such as directly from the generator, are classified as tolling customers. Both regulated and non-regulated customers pay transmission and distribution tariffs for the transportation of their electricity through the system. There is no risk of stranded costs for Chilquinta Energía because PPAs with generators are not take-or-pay contracts; rather, Chilquinta Energía only purchases power taken by its customers.
Chilquinta Energía’s system average rate (excluding tolling customers) was $0.164, $0.168 and $0.165 per kWh in 2017, 2016 and 2015, respectively.
Demand for electricity depends on the growth and stability of the Chilean economy, customer growth and preferences, prices, policies and environmental regulations driving the substitution of alternative energy products for wood and coal, legislation and energy policy supporting increased electrification of the public and private transportation sector, and the effectiveness and expansion of energy efficiency programs and distributed generation resources.
The price of electricity can be affected by the growth of renewable power generation, the amount of hydroelectric power, the market price of oil and natural gas, and transmission and distribution service tariffs, which may, in turn, also impact demand for electricity.

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Other factors that can affect the demand for electricity include weather and seasonality. Demand for electricity at Chilquinta Energía is higher in the winter months to meet heating load, and tends to decrease during the mild temperatures in the summer months.
Electric Resources. The supply of electric power available to Chilquinta Energía comes from purchased-power contracts currently in place with various suppliers. The supply as of December 31, 2017 was as follows:
CHILQUINTA ENERGÍA – ELECTRIC RESOURCES
 
 
Contract
Net operating
 
 
expiration date
capacity (MW)
% of total
Purchased-power contracts:
 
 
 
Thermal(1)
2023 to 2026
291

62
%
Hydro
2023 to 2036
141

30

Wind/solar
2023 to 2036
32

7

Biomass
2023 to 2036
7

1

Total
 
471

100
%
(1) Contracts with fuel sources that include natural gas, coal or diesel are collectively referred to as thermal.

Power Generation System. The National Electric System is operated and coordinated by the National Electric Coordinator (Coordinador Eléctrico Nacional). This institution is managed by a Directive Council (Consejo Directivo) formed by five members designated through a public tender. This entity coordinates the operation of the nationwide interconnected electric system.
Transmission System and Access. At December 31, 2017, Chilquinta Energía’s electric facilities include 10,227 miles of distribution lines, 352 miles of transmission lines and 49 substations. Chilquinta Energía also owns a 50-percent interest in Eletrans, which operates a 97-mile, double circuit 220-kV transmission line in the Atacama region of northern Chile, and a 46-mile, double circuit 220-kV transmission line in the Los Rios region of southern Chile.
Transmission lines in Chile are either part of the main transmission system (the national system) or the sub-transmission system (the zonal system). Sub-transmission systems, including those owned by Chilquinta Energía, are comprised of infrastructure that is interconnected to the electricity system to supply non-regulated and regulated end-users located in the distribution service area.
We discuss ongoing transmission line projects at Chilquinta Energía’s joint ventures in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”
Competition. Chilquinta Energía faces limited competition from the growth in rooftop solar installations, as electricity prices remain competitive and tariffs compensate self-generators only for the commodity component of the energy delivered to the grid. Presently, there are no public programs or incentives promoting the adoption of distributed energy generation.
In addition, the National Electric Coordinator will be tendering a significant number of projects, divided between extension work and new development work, for sub-transmission systems. The new development projects in these tenders will be opened to independent developers, allowing such developers to compete with incumbent utilities for their construction and operation.
Luz del Sur S.A.A.
Sempra South American Utilities owns 83.6 percent of Luz del Sur, an electric distribution utility that serves a population of approximately 4.9 million in the southern zone of metropolitan Lima, Peru, with a service area covering approximately 1,394 square miles. Luz del Sur delivers approximately one-third of all power used in Peru. The remaining shares of Luz del Sur are held by noncontrolling interests and trade on the Lima Stock Exchange (Bolsa de Valores de Lima) under the symbol LUSURC1. The shares are subject to regulation by the Superintendencia del Mercado de Valores (Superintendency of Securities Market).

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Customers and Demand. Luz del Sur provides electric services through the generation, transmission and distribution of electricity to the following customer classes:
LUZ DEL SUR – ELECTRIC CUSTOMER METERS AND VOLUMES
 
 
 
Customer meter count
 
Volumes
(millions of kWh)
 
 
December 31,
 
Years ended December 31,
 
 
2017
 
2017
2016
2015
Residential
993,784

 
2,930

2,896

2,845

Commercial
98,516

 
2,416

2,647

2,700

Industrial
4,050

 
784

1,021

1,229

Street and highway lighting
5,246

 
206

201

194

Free
143

 
663

622

581

 
1,101,739

 
6,999

7,387

7,549

Tolling
253

 
1,922

1,365

974

 
Total
1,101,992

 
8,921

8,752

8,523


In Peru, customers are classified as regulated and non-regulated customers based on capacity demand. Regulated customers are those whose capacity demand is less than 200 kW and their energy supply is considered public service. Non-regulated customers, which are free and tolling customers, are those whose capacity demand is greater than 2,500 kW. Customers with capacity demand between 200 kW and 2,500 kW may choose to be classified as regulated or non-regulated. Free customers purchase power directly from a utility and pay the utility a fee for generation, transmission (primary and secondary) and distribution services. Tolling customers purchase power from alternate suppliers and pay only a tolling fee to the utility for secondary transmission and distribution services. Utilities in Peru, including Luz del Sur, generally have PPAs with generators to serve their regulated and free customers’ load. Because the power purchased by Luz del Sur from generators is generally based on take-or-pay contracts, Luz del Sur is exposed to the risk of stranded costs associated with capacity charges, as we discuss in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Factors Influencing Future Performance.”
Luz del Sur’s system average rate (excluding free and tolling customers) was $0.130, $0.122 and $0.117 per kWh in 2017, 2016 and 2015, respectively.
Demand for electricity depends on the stability and growth of the Peruvian economy, customer growth and usage preferences, electricity prices, legislation and energy policy supporting increased electrification within our service territory. The price of electricity can be affected by changes in energy policy, volatility of spot market prices, the amount of hydroelectric power, the market price of oil and natural gas, changes in inflation and foreign exchange rates, new technologies and transmission and distribution service tariffs, which may also impact demand for electricity. Other factors that can affect the demand for electricity include weather and seasonality. Demand for electricity at Luz del Sur is higher in the summer months to meet cooling load, and tends to decrease during the colder temperatures in the winter months.
Electric Resources. The supply of electric power available to Luz del Sur comes from purchased-power contracts currently in place with various suppliers, its own electric generation facility or purchases made on an as-needed basis. This supply as of December 31, 2017 was as follows:
LUZ DEL SUR – ELECTRIC RESOURCES
 
 
Contract
Firm contracted
 
 
 
expiration date
capacity (MW)
 
% of total
Owned generation facility, hydro(1)
 
61

 
4
%
Purchased-power contracts:
 
 
 
 
Thermal(2)
2021-2025
413

 
27
 
Hydro
2021-2025
233

 
15
 
Combined thermal/hydro
2019-2025
832

 
54
 
Total
 
1,539

 
100
%

20


(1) 
Santa Teresa has a nameplate capacity of 100 MW with an associated firm capacity estimated at 61 MW
based on guidelines established by the system operator in Peru and historical water flows. Available excess
capacity is sold in the spot market.
(2) 
Contracts with fuel sources that include natural gas, coal or diesel are collectively referred to as thermal.

Power Generation System. The Sistema Eléctrico Interconectado Nacional (SEIN) is the Peruvian national interconnected system. The OSINERGMIN, in addition to setting tariffs, supervises the bidding processes for energy purchases between distribution companies and generators.
The Committee of Economic Operation of the National Interconnected System (Comité de Operación Económica del Sistema Interconectado Nacional) coordinates the operation and dispatch of electricity of the SEIN.
Transmission System and Access. At December 31, 2017, Luz del Sur’s electric facilities consisted of 13,966 miles of distribution lines, 216 miles of transmission lines and 40 substations. Luz del Sur also owns and operates Santa Teresa, a 100-MW hydroelectric power plant located in the Cusco region of Peru.
Transmission lines in Peru are divided into principal and secondary systems. The principal system lines are accessible by all generators and allow the flow of energy through the national grid. The secondary system lines connect principal transmission with the network of distribution companies or connect directly to certain final customers. The transmission company receives tariff revenues and collects tolls based on a charge per unit of electricity.
We discuss ongoing transmission line and substation projects at Luz del Sur in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”
Competition. While electric distribution companies in Peru are considered natural monopolies, users consuming more than 200 kW are free to choose the company of their preference, including Luz del Sur, to provide them with electric power.
Key Noncash Performance Indicators
Key noncash performance indicators for our South American electric distribution utilities’ operations are customer count and consumption and transmission line losses. Additional noncash performance indicators include goals related to safety, environmental considerations, electric reliability, and regulatory compliance.

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Sempra Mexico
Our Sempra Mexico segment includes the operating companies of our subsidiary, IEnova, as well as certain holding companies and risk management activity. IEnova develops, builds and operates energy infrastructure in Mexico, and owns or holds interests in:
natural gas transmission pipelines
LPG and ethane systems
a natural gas distribution utility
electric generation facilities, including wind, solar and a natural gas-fired power plant (presently held for sale)
a terminal for the import of LNG
a terminal for the storage of LPG
marine and inland terminal projects for the receipt, storage and delivery of liquid fuels
marketing operations for the purchase of LNG and the purchase and sale of natural gas
Sempra Energy owns 66.4 percent of IEnova, with the remaining shares held by noncontrolling interests and traded on the Mexican Stock Exchange under the symbol IENOVA. The Mexican National Banking and Securities Commission (Comisión Nacional Bancaria y de Valores, or CNBV), regulates the shares, which are registered with the Mexican National Securities Registry (Registro Nacional de Valores) maintained by the CNBV. We discuss IEnova’s noncontrolling interests and its acquisition and divestiture activities in Notes 1 and 3, respectively, of the Notes to Consolidated Financial Statements.
The following table provides information about Sempra Mexico’s facilities, excluding its Ecogas natural gas distribution facilities, that were operational as of December 31, 2017.
SEMPRA MEXICO OPERATING FACILITIES
 
Name
Length of system (miles)
Compression available (horsepower)
First in service
Pipelines:
 
 
 
  Aguaprieta
8

N/A

2002
  Empalme Lateral
12

N/A

2017
  Ethane
139

N/A

2015
  Los Ramones I
73

123,000

2014
  Los Ramones Norte(1)
281

123,000

2016
  Ojinaga-El Encino
137

N/A

2017
  Rosarito
188

30,000

2002
  Samalayuca
23

N/A

1997
  San Fernando
71

95,670

2003
  San Isidro-Samalayuca
14

46,000

2017
  Sonora:
 
 
 
    Guaymas-El Oro segment
205

N/A

2017
    Sásabe-Guaymas segment
313

N/A

2014
  TDF LPG
118

N/A

2007
  Transportadora de Gas Natural de Baja California
28

8,000

2000
 
 
 
 
Compressor stations:
 
 
 
  Gloria a Dios
 
14,300

2001
  Naco
 
14,340

2001
 
 
 
 
Storage:
 
Storage capacity
First in service
  ECA LNG terminal
 
320,000 cubic meters

2008
  Guadalajara LPG terminal
 
80,000 barrels

2013
 
 
 
 
Generation:
 
Generating capacity (MW)
First in service
  Energía Sierra Juárez wind generation(1)
 
155

2015
  TdM natural gas-fired generation (presently held for sale)
 
625

2003
  Ventika wind generation
 
252

2016
(1) 
Sempra Mexico has a 50-percent interest in each of these facilities and accounts for them as equity method investments. The information presented herein represents the full nameplate capacity.

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Gas Business
Pipelines and Related Assets/Facilities. At December 31, 2017, Sempra Mexico’s assets/facilities consisted of 1,353 miles of natural gas transmission pipelines, 11 compressor stations, 139 miles of ethane pipelines, 118 miles of LPG pipelines and one LPG storage terminal in Mexico. These assets are contracted under long-term, U.S. dollar-based agreements with major industry participants such as the CFE, CENAGAS, PEMEX, Shell, Gazprom, InterGen N.V. and other similar counterparties.
In 2017, our pipeline assets in Mexico had design capacity of approximately 16,501 MMcf per day of natural gas, 204 MMcf per day of ethane gas, 106,000 barrels per day of ethane liquid, 34,000 barrels per day of LPG transmission and 80,000 barrels of LPG storage.
LNG. Sempra Mexico operates its ECA LNG regasification terminal on land it owns in Baja California, Mexico. The ECA LNG regasification terminal is capable of processing 1 Bcf of natural gas per day and generates revenues from reservation and usage fees under terminal capacity agreements and nitrogen injection service agreements with Shell and Gazprom, expiring in 2028, that permit them, together, to use one-half of the terminal’s capacity.
In connection with Sempra LNG & Midstream’s LNG purchase agreement with Tangguh PSC, Sempra Mexico purchases from Sempra LNG & Midstream the LNG delivered to ECA by Tangguh PSC. Sempra Mexico uses the natural gas produced from this LNG and from natural gas purchased in the market or through Sempra LNG & Midstream’s marketing operations to supply a contract for the sale of natural gas to Mexico’s national electric company, the CFE, at prices that are based on the SoCal Border index. If LNG volumes received from Tangguh PSC are not sufficient to satisfy the commitment to the CFE, Sempra Mexico may purchase natural gas from Sempra LNG & Midstream’s natural gas marketing operations.
The LNG business is impacted by worldwide LNG market prices. High LNG prices in markets outside the market in which IEnova’s LNG terminal operates have resulted and could continue to result in lower than expected deliveries of LNG cargoes to the ECA LNG terminal from third parties under existing supply agreements, which could increase costs if IEnova is instead required to obtain LNG in the open market at prevailing prices. Any inability to obtain expected LNG cargoes could also impact IEnova’s ability to maintain the minimum level of LNG required to keep the ECA LNG terminal in operation at the proper temperature. LNG market prices also affect IEnova’s LNG marketing operations, through which IEnova must purchase natural gas in the international market to meet its contractual obligations to deliver natural gas to customers, but which could have an adverse impact on its earnings, which may be mitigated in part by the indemnity payments discussed below.
Sempra Mexico’s LNG marketing operations sell natural gas to the CFE and other customers under supply agreements. Sempra Mexico recognizes the revenue from the sale of natural gas upon transfer of the natural gas via pipelines to the customers at the agreed upon delivery points, and in the case of the CFE, at its thermoelectric power plants.
Sempra LNG & Midstream has an agreement with Sempra Mexico to supply LNG to the ECA LNG terminal. Although the LNG purchase agreement specifies a number of cargoes to be delivered annually, actual cargoes delivered have been significantly lower than the maximum specified under the agreement. As a result, Sempra LNG & Midstream is contractually required to make monthly indemnity payments to Sempra Mexico for failure to deliver the contracted LNG. The revenues from the indemnity payments, along with an amount for profit sharing, allow Sempra Mexico to recover the costs of operating the ECA LNG terminal.
Natural Gas Distribution. Sempra Mexico’s natural gas distribution utility, Ecogas, operates in three separate distribution zones in Mexico with approximately 2,394 miles of pipeline, and had approximately 120,000 customer meters (serving more than 400,000 residential, commercial and industrial consumers) with sales volume of approximately 81 MMcf per day in 2017.
Ecogas relies on affiliates, Sempra LNG & Midstream and SoCalGas, for the supply and transportation of natural gas that it distributes to its customers. If these affiliates fail to perform and IEnova is unable to obtain supplies of natural gas from alternate sources, IEnova could lose customers and sales volume and could also be exposed to commodity price risk and volatility.
Ecogas had been entitled to a 12-year period of exclusivity with respect to each of its three distribution zones in Mexicali, Chihuahua and La Laguna-Durango. As the last of these exclusivity periods expired in 2011, Ecogas could face competition from other distributors of natural gas in all of these distribution zones as other distributors of natural gas are now legally permitted to build natural gas distribution systems and compete with Ecogas for customers.
Power Business
Wind Power Generation. Sempra Mexico develops, invests in and operates renewable energy generation facilities that have long-term PPAs to sell the electricity they generate to its customers, which are generally load serving entities, and industrial and other customers. Load serving entities sell electric service to their end-users and wholesale customers immediately upon receipt of

23


our power delivery, while industrial and other customers consume the electricity to run their facilities. In 2017, Sempra Mexico had contracted capacity of 330 MW for its ownership share of fully operating wind energy generation facilities.
Natural Gas-Fired Generation. TdM is a 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico that generates revenue from selling electricity and/or resource adequacy to the CAISO and to governmental, public utility and wholesale power marketing entities. It also has an EMA with Sempra LNG & Midstream for energy marketing, scheduling and other related services to support its sales of generated power into the California electricity market. Under the EMA, TdM pays fees to Sempra LNG & Midstream for these revenue-generating services. TdM also purchases fuel from Sempra LNG & Midstream. Sempra Mexico records revenue for the sale of power generated by TdM, and records cost of sales for the purchases of natural gas and energy management services provided by Sempra LNG & Midstream.
In February 2016, management approved a plan to market and sell TdM. As a result, we stopped depreciating the plant and classified the plant as held for sale. We continue to actively pursue the sale of TdM, which we expect to be completed in 2018. We discuss TdM further in Notes 3 and 10 of the Notes to Consolidated Financial Statements.
TdM competes daily with other generating plants that supply power into the California electricity market. Several of the wholesale markets supplied by merchant power plants have experienced significant pricing declines due to excess supply. IEnova manages commodity price risk at TdM by optimizing a mix of forward on-peak energy sales, daily and hourly spot market sales of capacity, energy and ancillary services, and longer-term structured transactions, as well as avoiding short positions.
Demand and Competition
The overall demand for natural gas distribution services increases during the winter months. Conversely, in the power business, the overall demand for electricity is greater during the summer months.
IEnova competes with Mexican and foreign companies for certain new energy infrastructure projects in Mexico and some of its competitors (including but not limited to, public or state-operated companies, their subsidiaries and affiliates) may have better access to capital and greater financial and other resources, which could give them a competitive advantage in bidding for such projects. We discuss Sempra Mexico’s demand and competition further below.
Key Noncash Performance Indicators
Key noncash performance indicators for Sempra Mexico include sales volume, plant or facility availability, capacity utilization and, for its distribution operations, customer count and consumption. Additional noncash performance indicators include obtaining and completing (on time and on budget) major projects, compliance with reliability and regulatory standards, and goals related to safety, environmental considerations and regulatory performance.
Sempra Renewables
Sempra Renewables develops, owns and operates, or holds interests in, solar and wind energy generation facilities in the U.S. that have long-term PPAs to sell the electricity and the related green energy attributes they generate to its customers, which are generally load serving entities. Load serving entities sell electric service to their end-users and wholesale customers immediately upon receipt of our power delivery.
The majority of Sempra Renewables’ wind farm assets earn PTCs based on the number of megawatt hours of electricity they generate. A PTC is a federal subsidy that provides an income tax incentive to wind-energy producers at a flat rate for generating clean energy. Because PTCs last for ten years after project completion, any wind turbine that is under construction before the end of 2019 will earn a full decade of PTCs at phased-out rates beginning with construction starting in 2017 through 2019. For each of the years ended December 31, 2017, 2016, and 2015, PTCs represented a large portion of our wind farm earnings, often exceeding earnings from operations.
Certain of Sempra Renewables’ wind and solar power facilities are held by limited liability companies whose members include financial institutions. These financial institutions are noncontrolling tax equity investors to which earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. We discuss these tax equity arrangements in “Variable Interest Entities” and in “Noncontrolling Interests” in Note 1 of the Notes to Consolidated Financial Statements.

24


The following table provides information about the Sempra Renewables wind and solar energy generation facilities that were operational as of December 31, 2017. The generating capacity of these facilities is fully contracted under long-term PPAs for the periods indicated in the table.
SEMPRA RENEWABLES OPERATING FACILITIES
Name
Generating capacity (MW)
 
PPA term in years
 
First in
service(1)
 
Location
Wholly owned facility:
 
 
 
 
 
 
 
Copper Mountain Solar 1
58

 
20

 
2008
 
Boulder City, Nevada
Total
58

 
 
 
 
 
 
Tax equity-owned facilities(2):
 
 
 
 
 
 
 
Apple Blossom Wind
100

 
15

 
2017
 
Huron County, Michigan
Black Oak Getty Wind
78

 
20

 
2016
 
Stearns County, Minnesota
Copper Mountain Solar 4
94

 
20

 
2016
 
Boulder City, Nevada
Great Valley Solar portfolio(3)
100

 
15 to 20

 
2017
 
Fresno County, California
Mesquite Solar 2
100

 
20

 
2016
 
Maricopa County, Arizona
Mesquite Solar 3
150

 
25

 
2016
 
Maricopa County, Arizona
Total
622

 
 
 
 
 
 
Jointly owned facilities(4):
 
 
 
 
 
 
 
Auwahi Wind
11

 
20

 
2012
 
Maui, Hawaii
Broken Bow 2 Wind
38

 
25

 
2014
 
Custer County, Nebraska
Cedar Creek 2 Wind
125

 
25

 
2011
 
New Raymer, Colorado
Flat Ridge 2 Wind
235

 
20 and 25

 
2012
 
Wichita, Kansas
Fowler Ridge 2 Wind
100

 
20

 
2009
 
Benton County, Indiana
Mehoopany Wind
71

 
20

 
2012
 
Wyoming County, Pennsylvania
Total wind
580

 
 
 
 
 
 
 
 
 
 
 
 
 
 
California solar partnership
55

 
25

 
2013
 
Tulare and Kings Counties, California
Copper Mountain Solar 2
75

 
25

 
2012
 
Boulder City, Nevada
Copper Mountain Solar 3
125

 
20

 
2014
 
Boulder City, Nevada
Mesquite Solar 1
75

 
20

 
2011
 
Maricopa County, Arizona
Total solar
330

 
 

 
 
 
 
 
 
 
 
 
 
 
 
Total MW in operation
1,590

 
 

 
 
 
 
(1) 
If placed in service in phases, indicates the year the first phase went into service.
(2) 
Represents facilities that we own through tax equity arrangements. We consolidate these entities and report noncontrolling interests.
(3) 
Total expected generating capacity for Great Valley Solar is 200 MW, of which three phases totaling 100 MW went into service in 2017; we expect the remaining 100-MW phase to be in service in the first half of 2018.
(4) 
Sempra Renewables has a 50-percent interest in each of these facilities and accounts for them as equity method investments. The generating capacity shown herein represents Sempra Renewables’ share only.
Demand and Competition
Generation from Sempra Mexico’s and Sempra Renewables’ renewable energy assets is susceptible to fluctuations in naturally occurring conditions such as wind, inclement weather and hours of sunlight.
Sempra Renewables’ future performance and the demand for renewable energy are impacted by various market factors, most notably state mandated requirements to deliver a portion of total energy load from renewable energy sources. The rules governing these requirements in California are generally known as the RPS Program. In California, certification of a generation project by the CEC as an ERR allows the purchase of output from such generation facility to be counted towards fulfillment of the RPS Program requirements, if such purchase meets the provisions of California SB X1-2. The RPS Program may affect the demand for output from renewables projects developed by Sempra Renewables and Sempra Mexico, particularly the demand from California’s utilities. We expect to receive ERR certification for all our renewable facilities operating in and/or providing power to California, including those at Sempra Mexico, as they become operational. Additionally, the phase out or extension of U.S. federal income tax incentives, primarily ITCs and PTCs, could significantly impact future renewable energy resource availability and investment decisions. Certain provisions of the TCJA could reduce the value of tax benefits generated by our renewable projects and therefore make investments less attractive, as well as reducing the size of the tax equity financing market, which could lead to increased financing costs. These impacts may be offset by a lower overall federal tax rate.
Sempra Renewables primarily competes for wholesale contracts for the generation and sale of electricity through its development of and investments in wind and solar power generation facilities. Sempra Renewables also competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, and other energy service companies for sales of non-

25


contracted renewable energy. The number and type of competitors may vary based on location, generation type and project size. Also, regulatory initiatives designed to enhance energy consumption from renewable resources for regulated utility companies may increase competition from these types of institutions. These utilities may have a cost of capital that differs from most independent renewable power producers and often are able to recover fixed costs through rate mechanisms. This allows them to build, buy and upgrade renewable generation projects without relying exclusively on market clearing prices to recover their investments.
Because Sempra Mexico sells the power that it generates at its Energía Sierra Juárez wind power generation facility into California, it is also impacted by these competitive factors.
Our renewable energy competitors include, among others:
§
  EDF Energy
§
  MidAmerican Energy
§
  First Solar
§
  NextEra Energy Resources
§
  Invenergy
§
  Southern Company
Key Noncash Performance Indicators
Key noncash performance indicators for Sempra Renewables include capacity factors, plant availability and sales volume at our renewable energy facilities. Additional noncash performance indicators include goals related to safety, environmental considerations, and compliance with reliability standards.
Sempra LNG & Midstream
Sempra LNG & Midstream develops, owns and operates, or holds interests in, LNG and natural gas midstream assets and operations in Alabama, Louisiana, Mississippi and Texas, including:
a terminal in the U.S. for the import and export of LNG and sale of natural gas
natural gas pipelines and storage facilities
marketing operations
LNG
Sempra LNG & Midstream and three project partners hold interests in the Cameron LNG JV for the development, construction and operation of a three-train natural gas liquefaction export facility at the existing Cameron LNG, LLC regasification terminal in Hackberry, Louisiana, a project developed and permitted by Sempra LNG & Midstream.
Beginning from the October 1, 2014 joint venture effective date, Cameron LNG, LLC was no longer wholly owned, and Sempra LNG & Midstream began accounting for its 50.2-percent equity interest in the joint venture under the equity method. The joint venture began construction in the second half of 2014 on the natural gas liquefaction export facility using the existing regasification infrastructure contributed by Sempra LNG & Midstream. The joint venture has authorization to export LNG to both FTA and non-FTA countries.
The existing regasification terminal is capable of processing 1.5 Bcf of natural gas per day, and from 2009 through 2017, it generated revenue under a terminal services agreement for approximately 3.75 Bcf of natural gas storage and associated send-out rights of approximately 600 MMcf of natural gas per day. The agreement allowed the customer to pay capacity reservation and usage fees to use the facilities to receive, store and regasify the customer’s LNG. In December 2017, Cameron LNG JV terminated the regasification terminal services agreement, as progress on the construction of the three-train liquefaction project requires that certain terminal infrastructure be taken offline. The revenues associated with the terminal services agreement have been included in the equity earnings generated from Cameron LNG JV.
The three liquefaction trains are designed to a nameplate capacity of 13.9 Mtpa of LNG with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. Cameron LNG JV has 20-year liquefaction and regasification tolling capacity agreements in place with ENGIE S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd., which subscribe the full nameplate capacity of three trains at the facility. In addition, Cameron LNG JV is working on the development of up to two additional trains. We discuss Cameron LNG JV in Note 4 of the Notes to Consolidated Financial Statements and the construction of the first three trains and the potential for an additional two trains in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance” and in “Item 1A. Risk Factors.”
Sempra Energy is also taking steps to explore the development of additional LNG export facilities at Sempra LNG & Midstream’s Port Arthur, Texas property and Sempra Mexico’s ECA regasification facility. We discuss these opportunities in “Item 7.

26


Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance” and in “Item 1A. Risk Factors.”
Demand and Competition. Technological advances associated with shale gas and tight oil production have significantly reduced the need for North American LNG import facilities and increased interest in liquefaction and export opportunities.
At current forward gas prices, U.S. Gulf Coast liquefaction is among the most price competitive potential LNG supply in the world. Brownfield liquefaction is particularly price competitive, resulting from many factors, including:
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;
proximity to ample existing gas transmission pipeline and underground gas storage capacity; and
existing LNG tankage and berths.
Global LNG competition may limit U.S. LNG exports, as international liquefaction projects attempt to match U.S. Gulf Coast LNG production costs and customer contractual rights such as volume and destination flexibility. Host governments for international liquefaction projects are altering fiscal and tax regimes in an effort to make projects in their jurisdictions competitive relative to U.S. projects; however, sustained low oil prices may cause some of the international projects to become unfeasible due to their LNG price formulas’ link to oil prices. It is expected that U.S. LNG exports will increase competition for current and future global natural gas demand, and thereby facilitate development of a global commodity market for natural gas and LNG.
Our LNG liquefaction business’ major domestic and international competitors will include, among others, the following companies and their related LNG affiliates:
§
  BP
§
  Petronas
§
  Cheniere Energy
§
  Qatar Petroleum
§
  Chevron
§
  Royal Dutch Shell
§
  ConocoPhillips
§
  Total
§
  ExxonMobil
§
  Woodside
§
  Kinder Morgan
 
 
Additionally, our Cameron LNG JV partners, affiliates of ENGIE S.A., Mitsubishi Corporation (through a related company jointly established with Nippon Yusen Kabushiki Kaisha), and Mitsui & Co., Ltd., compete globally to market and sell LNG to end users, including gas and electric utilities located in LNG importing countries around the world. By providing liquefaction services, Cameron LNG JV will compete indirectly with liquefaction projects currently operating and those under development in the global LNG market. In addition to the U.S., these competitors are located in the Middle East, Southeast Asia, Africa, South America, Australia and Europe.
Midstream
Sempra LNG & Midstream has 42 Bcf of operational working natural gas storage capacity and a development project as follows:
Bay Gas is a facility located 40 miles north of Mobile, Alabama, that provides underground storage (20 Bcf of operational working natural gas storage capacity) and delivery of natural gas. Sempra LNG & Midstream owns approximately 91 percent of the facility. It is the easternmost salt dome storage facility on the Gulf Coast, with direct service to the Florida market and markets across the Southeast, Mid-Atlantic and Northeast regions.
Mississippi Hub is an underground salt dome with 22 Bcf of operational working natural gas storage capacity located 45 miles southeast of Jackson, Mississippi. It has access to natural gas from shale basins of East Texas and Louisiana, traditional Gulf Coast supplies and LNG, with multiple interconnections to serve the Southeast and Northeast regions.
Liberty Gas Storage, LLC owns a 77-percent interest in LA Storage, a salt cavern development project in Cameron Parish, Louisiana, and ProLiance Transportation LLC owns the remaining 23 percent. The project’s location provides access to several LNG facilities in the area and could be positioned to support LNG export from various liquefaction terminals. Future development will require approval of a new construction permit by the FERC, if anticipated cash flows support further investment. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage pipeline, that is not currently contracted.
Demand and Competition. The natural gas storage business depends on market forecasts of seasonal natural gas prices, and cash provided from operating activities generally is greater during and immediately following the winter heating months. As is

27


prevalent in the industry, Sempra LNG & Midstream customers usually inject natural gas into storage during the summer months (April through October) and usually withdraw natural gas from storage during the winter months (November through March) when customer demand is higher.
Within their respective market areas, Sempra LNG & Midstream’s and Sempra Mexico’s pipeline businesses and Sempra LNG & Midstream’s storage facilities businesses compete with other regulated and unregulated storage facilities and pipelines. They compete primarily on the basis of price (in terms of storage and transportation fees), available capacity and interconnections to downstream markets.
Sempra LNG & Midstream’s competitors include, among others:
§
  Boardwalk Pipeline Partners
§

  Macquarie Infrastructure Partners
§
  Cardinal Gas Storage Partners
§

  Plains All American Pipeline
§
  Columbia Energy
§

  Southern Company Gas
§
  Enbridge
§

  Tellurian
§
  Energy Transfer Partners
§

  TransCanada
§
  Enterprise Products Partners
§

  The Williams Companies
§

  Kinder Morgan
 
 
Sempra Mexico’s competitors include, among others:
§
  Carso Energy
§
  Fermaca
§
  Enagas
§
  Kinder Morgan
§
  ENGIE S.A.
§
  TransCanada
Marketing Operations
Sempra LNG & Midstream provides natural gas marketing, trading and risk management services through the utilization and optimization of contracted natural gas supply, transportation and storage capacity, as well as optimizing its assets in the short-term services market. Additionally, it sells electricity under short-term and long-term contracts and into the spot market and other competitive markets.
Sempra LNG & Midstream’s marketing operations have an LNG purchase agreement with Tangguh PSC for the supply of the equivalent of 500 MMcf of natural gas per day from Tangguh PSC’s Indonesian liquefaction facility with delivery to Sempra Mexico’s ECA LNG receipt terminal at a price based on the SoCal Border index for natural gas. The LNG purchase agreement allows Tangguh PSC to divert deliveries to other global markets in exchange for cash differential payments to Sempra LNG & Midstream. Sempra LNG & Midstream also may enter into short-term supply agreements to purchase LNG to be received, stored and regasified at the terminal for sale to other parties.
In addition to LNG, if deliveries of LNG cargoes are not sufficient, Sempra LNG & Midstream is also contracted to sell natural gas to Sempra Mexico that allows Sempra Mexico to satisfy its obligation under supply agreements with the CFE and other customers, and to supply the TdM power plant. These revenues are adjusted for indemnity payments and profit sharing, as discussed in “Sempra Mexico – Gas Business – LNG” above.
Sempra LNG & Midstream also has an EMA with Sempra Mexico to provide energy marketing, scheduling and other related services to Sempra Mexico’s TdM power plant to support its sales of generated power into the California electricity market. We discuss the EMA in “Sempra Mexico – Power Business – Natural Gas-Fired Generation” above.
Key Noncash Performance Indicators
Key noncash performance indicators at Sempra LNG & Midstream include natural gas sales volume, plant or facility availability and capacity utilization. Additional noncash performance indicators include goals related to safety, environmental considerations and regulatory compliance, and on-time and on-budget completion of development projects.
REGULATION
California State Utility Regulation
The California Utilities are principally regulated at the state level by the CPUC, the CEC and the CARB.

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The CPUC:
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.
The CPUC also oversees and regulates new products and services, including solar and wind energy, bioenergy, alternative energy storage and other forms of renewable energy. In addition, the CPUC’s safety and enforcement role includes inspections, investigations and penalty and citation processes for safety violations.
The CEC publishes electric demand forecasts for the state and for specific service territories. Based on these forecasts, the CEC:
determines the need for additional energy sources and conservation programs;
sponsors alternative-energy research and development projects;
promotes energy conservation programs to reduce demand within the state of California for electricity and natural gas;
maintains a statewide plan of action in case of energy shortages; and
certifies power-plant sites and related facilities within California.
The CEC conducts a 20-year forecast of available supplies and prices for every market sector that consumes natural gas in California. This forecast includes resource evaluation, pipeline capacity needs, natural gas demand and wellhead prices, and costs of transportation and distribution. This analysis is one of many resource materials used to support the California Utilities’ long-term investment decisions.
The state of California requires certain California electric retail sellers, including SDG&E, to deliver a percentage of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by both the CPUC and the CEC, are generally known as the RPS Program. We discuss this requirement as it applies to SDG&E in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”
California AB 32, the California Global Warming Solutions Act of 2006, assigns responsibility to CARB for monitoring and establishing policies for reducing GHG emissions. The bill requires CARB to develop and adopt a comprehensive plan for achieving real, quantifiable and cost-effective GHG emission reductions, including a statewide GHG emissions cap, mandatory reporting rules, and regulatory and market mechanisms to achieve reductions of GHG emissions. CARB is a department within the California Environmental Protection Agency, an organization that reports directly to the Governor’s Office in the Executive Branch of California State Government. Sempra LNG & Midstream and Sempra Mexico are also subject to the rules and regulations of CARB. We provide further discussion of GHG allowances and emissions in Note 1 of the Notes to Consolidated Financial Statements.
The operation and maintenance of SoCalGas’ natural gas storage facilities are regulated by DOGGR, as well as various other state and local agencies. We provide further discussion of DOGGR’s increased regulations in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”
U.S. Utility Regulation
The California Utilities are also regulated at the federal level by the FERC, the NRC, the EPA, the DOE and the DOT.
The FERC regulates the California Utilities’ interstate sale and transportation of natural gas and the application of the uniform systems of accounts. In the case of SDG&E, the FERC also regulates the transmission and wholesale sales of electricity in interstate commerce, transmission access, rates of return on transmission investment, rates of depreciation and electric rates involving sales for resale. The Energy Policy Act governs procedures for requests for transmission service. The FERC approved the California IOUs transfer of operation and control of their transmission facilities to the CAISO in 1998.
The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities in the U.S., including SONGS, in which SDG&E owns a 20-percent interest and which has been permanently retired since 2013. NRC and various state regulations require extensive review of the safety, radiological and environmental aspects of these facilities. We provide further discussion of SONGS matters, including the closure and pending decommissioning of the facility, in Note 13 of the Notes to Consolidated Financial Statements.

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The DOT, through PHMSA, has established regulations regarding engineering standards and operating procedures applicable to the California Utilities’ natural gas transmission and distribution pipelines. The DOT has certified the CPUC to administer oversight and compliance with these regulations for the entities they regulate in California. The PHMSA also is in the process of promulgating regulations applicable to the California Utilities’ natural gas storage facilities. See “Other U.S. Regulation” below and further discussion in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”
Other State and Local Regulation Within the U.S.
The SCAQMD is the air pollution control agency responsible for regulating stationary sources of air pollution in the South Coast Air Basin in Southern California. The district’s territory covers all of Orange County and the urban portions of Los Angeles, San Bernardino and Riverside counties.
SoCalGas has natural gas franchises with the 12 counties and the 223 cities in its service territory. These franchises allow SoCalGas to locate, operate and maintain facilities for the transmission and distribution of natural gas. Most of the franchises have indefinite lives with no expiration date. Some franchises have fixed expiration dates, ranging from 2018 to 2062.
SDG&E has electric franchises with the two counties and the 27 cities in or adjoining its electric service territory; and natural gas franchises with the one county and the 18 cities in its natural gas service territory. These franchises allow SDG&E to locate, operate and maintain facilities for the transmission and distribution of electricity and/or natural gas. Most of the franchises have indefinite lives with no expiration dates. Some natural gas and some electric franchises have fixed expiration dates that range from 2021 to 2035.
Other U.S. Regulation
The FERC regulates certain Sempra Renewables and Sempra LNG & Midstream assets pursuant to the Federal Power Act and Natural Gas Act, which provide for FERC jurisdiction over, among other things, sales of wholesale power in interstate commerce, transportation and storage of natural gas in interstate commerce, and siting and permitting of LNG terminals. In addition, certain Sempra Renewables power generation assets are required under the Federal Power Act to comply with reliability standards developed by the North American Electric Reliability Corporation. Bay Gas’ natural gas storage operations are also regulated by the Alabama Public Service Commission.
Sempra LNG & Midstream’s investment in Cameron LNG JV is subject to regulations of the DOE regarding the export of LNG.
The FERC may regulate rates and terms of service based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be sufficiently competitive, rates may be market-based. FERC-regulated rates at the following businesses are
Sempra Renewables and Sempra LNG & Midstream: market-based for wholesale electricity sales
Sempra LNG & Midstream: cost-based for the transportation of natural gas
Sempra LNG & Midstream: market-based for the storage of natural gas, as well as the purchase and sale of LNG and natural gas
The California Utilities, Sempra LNG & Midstream and businesses that Sempra LNG & Midstream invests in are subject to the DOT rules and regulations regarding pipeline safety. PHMSA, acting through the Office of Pipeline Safety, is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines, including pipelines associated with natural gas storage, and develops regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance, and emergency response of pipeline facilities. The California Utilities, Sempra LNG & Midstream, Sempra Renewables and Sempra Mexico are also subject to regulation by the U.S. Commodity Futures Trading Commission.
Foreign Regulation
Sempra South American Utilities has two utilities in South America that are subject to laws and regulations in the localities and countries in which they operate. These utilities serve primarily regulated customers, and their revenues are based on tariffs that are set by the CNE in Chile and the OSINERGMIN in Peru, as we discuss below in “Ratemaking Mechanisms – Sempra South American Utilities.”
Operations and projects in our Sempra Mexico segment are subject to regulation by the CRE, the Mexican Safety, Energy and Environment Agency (Agencia de Seguridad, Energía y Ambiente), the Mexican Secretary of Energy (Secretaría de Energía) and other labor and environmental agencies of city, state and federal governments in Mexico.

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Licenses and Permits
The California Utilities obtain numerous permits, authorizations and licenses for the transmission and distribution of natural gas and electricity and the operation and construction of related assets, including electric generation and natural gas storage facilities, some of which may require periodic renewal.
Sempra South American Utilities and Sempra Mexico obtain numerous permits, authorizations and licenses for their electric and natural gas distribution, generation and transmission systems from the local governments where the service is provided. The respective energy ministries in Chile or Peru granted the concessions to operate Chilquinta Energía’s and Luz del Sur’s distribution operations for indefinite terms, not requiring renewal. The permits for generation, transportation, storage and distribution operations at Sempra Mexico are generally for 30-year terms, with options for renewal under certain regulatory conditions.
Sempra Mexico and Sempra LNG & Midstream obtain licenses and permits for the construction, operation and expansion of LNG facilities, and the import and export of LNG and natural gas. Sempra Mexico also obtains licenses and permits for the construction and operation of terminals for the receipt, storage and delivery of liquid fuels.
Sempra Renewables obtains permits, authorizations and licenses for the construction and operation of power generation facilities, and for the wholesale distribution of electricity.
Sempra LNG & Midstream obtains permits, authorizations and licenses for the construction and operation of natural gas storage facilities and pipelines, and in connection with participation in the wholesale electricity market.
Most of the permits and licenses associated with construction and operations within the Sempra Renewables and Sempra LNG & Midstream businesses are for periods generally in alignment with the construction cycle or life of the asset and in many cases are greater than 20 years.
RATEMAKING MECHANISMS
California Utilities
General Rate Case Proceedings. A CPUC GRC proceeding is designed to set sufficient base rates to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment. The proceeding generally establishes the test year revenue requirements, which authorizes how much the California Utilities can collect from their customers, and provides for attrition, or annual increases in revenue requirements, for each year following the test year. The CPUC generally conducts a GRC every three years.
Cost of Capital Proceedings. A CPUC cost of capital proceeding determines a utility’s authorized capital structure and authorized return on rate base, which is a weighted-average of the authorized returns on debt, preferred stock, and common equity (referred to as return on equity or ROE), weighted on a basis consistent with the authorized capital structure. The authorized return on rate base approved by the CPUC is the rate that the California Utilities use to establish customer rates to recover costs incurred to finance investments in CPUC-regulated electric distribution and generation, as well as natural gas distribution and transmission assets.
A cost of capital proceeding also addresses the automatic CCM, which applies market-based benchmarks to determine whether an adjustment to the authorized return on rate base is required during the interim years between cost of capital proceedings. The CCM did not operate in 2017, but could operate in 2018 to change the rates effective for January 1, 2019. The market-based benchmark for SDG&E’s and SoCalGas’ CCM is the 12-month average monthly A-rated utility bond index, as published by Moody’s for the 12-month period from October 1st through September 30th (CCM Period) of each calculation year. Remaining unchanged from the last cost of capital proceeding, SDG&E’s and SoCalGas’ CCM benchmark rate was set at 4.24 percent. If at the end of the CCM Period the monthly average benchmark rate falls outside of the established range of 3.24 percent to 5.24 percent, SDG&E’s and SoCalGas’ authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the benchmark rate. In addition, the authorized recovery rate for SDG&E’s and SoCalGas’ cost of debt and preferred stock would be adjusted to their respective actual weighted-average costs, with no change to the authorized capital structure. All three adjustments with the new rate would become effective on January 1st of the following year in which the benchmark range was exceeded.
The CCM only applies during the intervening years between scheduled cost of capital proceedings. In the year the cost of capital proceeding is scheduled, the cost of capital proceeding takes precedence over the CCM and will set new rates for the following year. The next cost of capital proceeding is scheduled to be filed in April 2019 for a January 1, 2020 implementation.
We also discuss the cost of capital and CCM in Note 14 of the Notes to Consolidated Financial Statements.

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Transmission Rate Cases. SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets. The TO4 settlement agreement, approved by the FERC in May 2014 and in effect through December 31, 2018, established a 10.05 percent ROE. The settlement also established 1) a process whereby rates are determined using a base period of historical costs and a forecast of capital investments and 2) a true-up period similar to balancing account treatment that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including its authorized return on investment. SDG&E makes annual information filings on December 1 of each year to update rates for the following calendar year. SDG&E also has the right to file for any ROE incentives that might apply under FERC rules. SDG&E’s debt-to-equity ratio will be set annually based on the actual ratio at the end of each year.
Incentive Mechanisms. The CPUC applies performance-based measures and incentive mechanisms to all California IOUs, under which the California Utilities have earnings potential above authorized CPUC base operating margin if they achieve or exceed specific performance and operating goals. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties.
SDG&E has incentive mechanisms associated with:
operational incentives (electric reliability)
energy efficiency
SoCalGas has incentive mechanisms associated with:
energy efficiency
natural gas procurement
unbundled natural gas storage and system operator hub services
Other Cost-Based Recovery. The CPUC authorizes the California Utilities to collect additional revenue requirements to recover costs that they have been authorized to pass on to customers, including the costs to purchase electricity and natural gas and those associated with administering public purpose, demand response, and customer energy efficiency programs. Actual costs are recovered as the commodity or service is delivered or, to the extent actual amounts vary from forecasts, generally recovered or refunded within a subsequent period based on the nature of the account. Overcollections and undercollections represent differences between cash collected in current rates and amounts due for specified components (including costs, depreciation and return on rate base) probable of recovery from ratepayers. The lagging aspect of overcollections and undercollections impacts cash flows until these respective amounts are trued up with collections from customers.
Because changes in SDG&E’s and SoCalGas’ cost of electricity and/or natural gas is substantially recovered in rates through a balancing account mechanism, changes in these costs are offset in revenues, and therefore do not impact earnings.
We also discuss regulatory matters in Note 14 of the Notes to Consolidated Financial Statements.
Sempra South American Utilities
Chilquinta Energía and Luz del Sur, our electric distribution utilities in South America, recognize revenues based on tariffs that are set by government agencies in their respective countries based on an efficient model distribution company defined by those agencies. The tariffs are based on a model and are intended to cover the costs of the model company. Because the tariffs are not based on the costs of the specific utility, they may not result in full cost recovery. The tariffs are designed to provide for a pass-through to customers of transmission and energy charges, recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on the distributor’s regulated asset base.
Chilquinta Energía’s revenues are based on tariffs that are set by the CNE. The CNE’s review process for authorized distribution and transmission rates generally remains in effect for a period of four years. The CNE reviews rates for four-year periods related to distribution and transmission separately on an alternating basis every two years.
Luz del Sur’s revenues are based on tariffs that are set by the OSINERGMIN. The components of tariffs for Luz del Sur are reviewed and adjusted every four years.
Sempra Mexico
Ecogas’ revenues are derived from service and distribution fees charged to its customers in pesos. The price Ecogas pays to purchase natural gas, which is based on international price indices, is passed through directly to its customers. The service and distribution fees charged by Ecogas are regulated by the CRE, which performs a review of rates every five years and monitors prices charged to end-users. The tariffs operate under a return-on-asset-base model. In the annual tariff adjustment, rates are adjusted to account for inflation or fluctuations in exchange rates, and inflation indexing includes separate U.S. and Mexican cost components, so that U.S. costs can be included in the final distribution rates.

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ENVIRONMENTAL MATTERS
We discuss environmental issues affecting us in Note 15 of the Notes to Consolidated Financial Statements and “Item 1A. Risk Factors.” You should read the following additional information in conjunction with those discussions.
Hazardous Substances
The CPUC’s Hazardous Waste Collaborative mechanism allows California’s IOUs to recover hazardous waste cleanup costs for certain sites, including those related to certain Superfund sites. This mechanism permits the California Utilities to recover in rates 90 percent of hazardous waste cleanup costs and related third-party litigation costs, and 70 percent of the related insurance-litigation expenses. In addition, the California Utilities have the opportunity to retain a percentage of any recoveries from insurance carriers and other third parties to offset the cleanup and associated litigation costs not recovered in rates.
We record estimated liabilities for environmental remediation when amounts are probable and estimable. In addition, we record amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism as regulatory assets.
Air and Water Quality
The electric and natural gas industries are subject to increasingly stringent air quality and GHG standards, such as those established by the CARB and SCAQMD. The California Utilities generally recover in rates the costs to comply with these standards. We discuss GHG standards and credits further in Note 1 of the Notes to Consolidated Financial Statements.
We discuss environmental matters concerning SoCalGas’ Aliso Canyon natural gas storage facility in Note 15 of the Notes to Consolidated Financial Statements, in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance” and in “Item 1A. Risk Factors.”
OTHER MATTERS
Executive Officers of the Registrants

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EXECUTIVE OFFICERS OF SEMPRA ENERGY
 
 
 
Name
Age(1)
Positions held over last five years
Time in position
Debra L. Reed
61
Chairman
December 2012 to present
 
 
Chief Executive Officer
June 2011 to present
 
 
President
March 2017 to present
 
 
 
 
Joseph A. Householder
62
Corporate Group President - Infrastructure Businesses
January 2017 to present
 
 
Executive Vice President and Chief Financial Officer
October 2011 to December 2016
 
 
 
 
Steven D. Davis(2)
62
Corporate Group President - Utilities
January 2017 to present
 
 
Executive Vice President - External Affairs and Corporate Strategy
September 2015 to December 2016
 
 
President and Chief Operating Officer, SDG&E
January 2014 to September 2015
 
 
Senior Vice President - External Affairs
March 2012 to December 2013
 
 
 
 
J. Walker Martin
56
Executive Vice President and Chief Financial Officer
January 2017 to present
 
 
Chairman, SDG&E
November 2015 to December 2016
 
 
President, SDG&E
October 2015 to December 2016
 
 
Chief Executive Officer, SDG&E
January 2014 to December 2016
 
 
President and Chief Executive Officer, Sempra U.S. Gas & Power
October 2011 to December 2013
 
 
 
 
Martha B. Wyrsch
60
Executive Vice President and General Counsel
September 2013 to present
 
 
 
 
Dennis V. Arriola
57
Executive Vice President - Corporate Strategy and External Affairs
January 2017 to present
 
 
Chairman, SoCalGas
November 2015 to December 2016
 
 
Chief Executive Officer, SoCalGas
March 2014 to December 2016
 
 
President, SoCalGas
August 2012 to September 2016
 
 
Chief Operating Officer, SoCalGas
August 2012 to January 2014
 
 
 
 
Trevor I. Mihalik
51
Senior Vice President
December 2013 to present
 
 
Controller and Chief Accounting Officer
July 2012 to present
 
 
 
 
G. Joyce Rowland
63
Senior Vice President, Chief Human Resources Officer and Chief Administrative Officer
September 2014 to present
 
 
Senior Vice President - Human Resources, Diversity and Inclusion
May 2010 to September 2014
(1) 
Ages are as of February 27, 2018.
(2) 
Mr. Davis will retire as of March 1, 2018.

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EXECUTIVE OFFICERS OF SDG&E
 
 
 
Name
Age(1)
Positions held over last five years
Time in position
Scott D. Drury
52
President
January 2017 to present
 
 
Chief Energy Supply Officer
June 2015 to December 2016
 
 
Vice President - Human Resources, Diversity and Inclusion
March 2011 to June 2015
 
 
 
 
J. Chris Baker(2)
58
Chief Information Officer
June 2015 to present
 
 
Senior Vice President and Chief Information Technology Officer
January 2014 to June 2015
 
 
Senior Vice President - Strategic Planning and Technology
September 2012 to January 2014
 
 
 
 
Lee Schavrien(3)
63
Chief Regulatory Officer
March 2017 to present
 
 
Chief Administrative Officer
June 2015 to March 2017
 
 
Senior Vice President of Regulatory Affairs and Operations Support
February 2015 to June 2015
 
 
Senior Vice President - Finance, Regulatory and Legislative Affairs
April 2010 to February 2015
 
 
 
 
Caroline A. Winn
54
Chief Operating Officer
January 2017 to present
 
 
Chief Energy Delivery Officer
June 2015 to December 2016
 
 
Vice President - Customer Services
April 2010 to June 2015
 
 
 
 
Bruce A. Folkmann
50
Vice President, Controller, Chief Financial Officer, Chief Accounting Officer and Treasurer
March 2015 to present
 
 
Vice President and Chief Financial Officer, Sempra U.S. Gas & Power
July 2013 to March 2015
 
 
Vice President and Controller, Sempra U.S. Gas & Power
August 2012 to September 2013
 
 
 
 
Randall L. Clark
48
Chief Human Resources and Administrative Officer
March 2017 to present
 
 
Vice President - Human Resources, Diversity and Inclusion
October 2015 to March 2017
 
 
Vice President - Human Resources Services, Sempra Energy
September 2014 to October 2015
 
 
Vice President - Compliance and Governance, Sempra Energy
January 2014 to September 2014
 
 
Vice President - Corporate Responsibility, Sempra Energy
March 2012 to January 2014
(1) 
Ages are as of February 27, 2018.
(2) 
Mr. Baker will retire as of May 1, 2018.
(3) 
Mr. Schavrien will retire as of April 1, 2018.

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EXECUTIVE OFFICERS OF SOCALGAS
 
 
 
Name
Age(1)
Positions held over last five years
Time in position
Patricia K. Wagner
55
Chief Executive Officer
January 2017 to present
 
 
Executive Vice President, Sempra Energy
September 2016 to December 2016
 
 
President and Chief Executive Officer, Sempra U.S. Gas & Power
January 2014 to September 2016
 
 
Vice President of Audit Services, Sempra Energy
February 2012 to December 2013
 
 
 
 
J. Bret Lane
58
President
September 2016 to present
 
 
Chief Operating Officer
January 2014 to present
 
 
Senior Vice President - Gas Operations and System Integrity, SDG&E and SoCalGas
August 2012 to January 2014
 
 
 
 
J. Chris Baker(2)
58
Chief Information Officer
June 2015 to present
 
 
Senior Vice President and Chief Information Technology Officer
January 2014 to June 2015
 
 
Senior Vice President - Strategic Planning and Technology
September 2012 to January 2014
 
 
 
 
Lee Schavrien(3)
63
Chief Regulatory Officer
March 2017 to present
 
 
Chief Administrative Officer
June 2015 to March 2017
 
 
Senior Vice President of Regulatory Affairs and Operations Support
February 2015 to June 2015
 
 
Senior Vice President - Finance, Regulatory and Legislative Affairs
April 2010 to February 2015
 
 
 
 
Sharon L. Tomkins
52
Vice President and General Counsel
August 2014 to present
 
 
Assistant General Counsel
April 2010 to August 2014
 
 
 
 
Bruce A. Folkmann
50
Vice President, Controller, Chief Financial Officer, Chief Accounting Officer and Treasurer
March 2015 to present
 
 
Vice President and Chief Financial Officer, Sempra U.S. Gas & Power
July 2013 to March 2015
 
 
Vice President and Controller, Sempra U.S. Gas & Power
August 2012 to September 2013
 
 
 
 
Hal Snyder(4)
57
Chief Human Resources and Administrative Officer
March 2017 to present
 
 
Vice President - Human Resources, Diversity and Inclusion
November 2012 to March 2017
(1) 
Ages are as of February 27, 2018.
(2) 
Mr. Baker will retire as of May 1, 2018.
(3) 
Mr. Schavrien will retire as of April 1, 2018.
(4) 
Mr. Snyder will retire as of June 1, 2018.
Employees of the Registrants
The table below shows the number of employees for each of our registrants at December 31, 2017. Employees represented by labor unions are covered under various collective bargaining agreements that generally cover wages, benefits, working conditions, and other terms and conditions of employment.
NUMBER OF EMPLOYEES
 
 
 
 
 
 
Number of employees
 
% of employees covered under collective bargaining agreements
 
% of employees covered under collective bargaining agreements expiring within one year
 
Sempra Energy Consolidated(1)
16,046

 
43
%
 
33
%
 
SDG&E(1)
4,116

 
30
%
 
%
 
SoCalGas
7,546

 
61
%
 
61
%
 
(1) 
Excludes employees of variable interest entities as defined by U.S. GAAP.

COMPANY WEBSITES

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Company website addresses are
Sempra Energy www.sempra.com
SDG&E www.sdge.com
SoCalGas www.socalgas.com
We make available free of charge on the Sempra Energy website, and for SDG&E and SoCalGas, via a hyperlink on their websites, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. The charters of the audit, compensation and corporate governance committees of the Sempra Energy board of directors, Sempra Energy’s corporate governance guidelines, and Sempra Energy’s code of business conduct and ethics for directors and officers (which also applies to directors and officers of SDG&E and SoCalGas) are posted on Sempra Energy’s website.
Printed copies of these materials may be obtained by writing to our Corporate Secretary at Sempra Energy, 488 8th Avenue, San Diego, CA 92101-7123.
The SEC also maintains a website that contains reports, proxy and information statements and other information we file with the SEC at www.sec.gov. Copies of these reports, proxy and information statements and other information may also be obtained, after paying a duplicating fee, by electronic request at certified@sec.gov, or by writing the SEC’s Public Reference Room, 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330.
The information on the websites of Sempra Energy, SDG&E and SoCalGas is not part of this report or any other report that we file with or furnish to the SEC, and is not incorporated herein by reference.
 
 
 
 
 
ITEM 1A. RISK FACTORS
When evaluating our company and its subsidiaries, you should consider carefully the following risk factors and all other information contained in this report. These risk factors could materially adversely affect our actual results and cause such results to differ materially from those expressed in any forward-looking statements made by us or on our behalf. We may also be materially harmed by risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of the following occurs, our businesses, cash flows, results of operations, financial condition and/or prospects could be materially negatively impacted. In addition, the trading prices of our securities and those of our subsidiaries could substantially decline due to the occurrence of any of these risks. These risk factors should be read in conjunction with the other detailed information concerning our company set forth in, or attached as an exhibit to, this annual report on Form 10-K, including, without limitation, the information set forth in the Notes to Consolidated Financial Statements and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” In this section, when we state that a risk or uncertainty may, could or will have a “material adverse effect” on us, or may, could or will “materially adversely affect” us, we mean that the risk or uncertainty may, could or will, as the case may be, have a material adverse effect on our businesses, cash flows, results of operations, financial condition, prospects and/or the trading prices of our securities or those of our subsidiaries.
Risks Related to Sempra Energy
Sempra Energy’s cash flows, ability to pay dividends and ability to meet its debt obligations largely depend on the performance of its subsidiaries and joint ventures and the ability to utilize the cash flows from those subsidiaries and joint ventures.
We are a holding company and substantially all of our assets are owned by our subsidiaries. Our ability to pay dividends and to meet our debt and other obligations depends almost entirely on cash flows from our subsidiaries and joint ventures and other entities in which we have invested and, in the short term, our ability to raise capital from external sources. In the long term, cash flows from our subsidiaries and joint ventures and other entities in which we have invested depend on their ability to generate operating cash flows in excess of their own expenditures, common and preferred stock dividends, and debt or other obligations. In addition, the subsidiaries are separate and distinct legal entities that are not obligated to pay dividends or make loans or distributions to us, whether to enable us to pay principal and interest on our debt securities, our other obligations or dividends on our common stock or our preferred stock, and could be precluded from paying any such dividends or making any such loans or distributions under certain circumstances, including, without limitation, as a result of legislation, regulation, court order, contractual restrictions or in times of financial distress.

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A significant portion of our worldwide cash reserves are generated by, and therefore held in, foreign jurisdictions. As a result of the TCJA enacted in December 2017, the cumulative undistributed earnings of our foreign entities were deemed repatriated and subjected to a one-time U.S. federal income tax. Based on current assumptions, when we repatriate these foreign earnings to the U.S. in 2018 or later, they will not be subject to additional U.S. federal income taxes. However, some foreign jurisdictions and U.S. states impose taxes on dividends repatriated to their U.S. parent, which will reduce the cash available to us.
The TCJA may materially adversely affect our financial condition, results of operations and cash flows, the value of investments in our common stock, preferred stock and debt securities, and our credit ratings.
The TCJA has significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations by, among other things, reducing the U.S. corporate income tax rate, altering the expensing of capital expenditures, limiting interest deductions, adopting elements of a territorial tax system, assessing a one-time deemed repatriation tax on cumulative undistributed earnings of U.S.-owned foreign entities at the time of enactment, and introducing certain anti-base erosion provisions. The legislation is unclear in certain respects and will require interpretations and implementing regulations by the U.S. Department of the Treasury, as well as state tax authorities, and the legislation could be subject to potential amendments and technical corrections, any of which could lessen or increase certain adverse impacts of the legislation. In addition, the regulatory treatment of the impacts of this legislation will be subject to the discretion of the FERC and state public utility commissions.
We recorded a noncash income tax expense of $870 million in the fourth quarter of 2017 for the effects of the enactment of the TCJA. We recorded the effects using our best estimates and the information available to us through the date the financial statements were issued. However, our analysis of this legislation is ongoing, and the effects recorded are provisional. As permitted by and in accordance with guidance issued by the SEC, we may adjust our provisional estimates in reporting periods throughout 2018 as we complete our analysis and as more information becomes available, which could result in a material change in our provisional estimates. We discuss the events and information that may result in adjustments to our provisional estimates in Note 6 of the Notes to Consolidated Financial Statements and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.”
Although it is unclear when or how capital markets, credit rating agencies, the FERC or state public utility commissions may respond to the TCJA, we do expect that certain financial metrics used by credit rating agencies, such as our funds from operations-to-debt percentage, will be negatively impacted as a result of an anticipated decrease in required income tax reimbursement payments to us from our domestic utility subsidiaries due to the decrease in the U.S. statutory corporate income tax rate. Certain provisions of the TCJA, such as 100-percent expensing of capital expenditures and impacts on utilization of our NOLs, may influence how we fund capital expenditures, the timing of capital expenditures and possible redeployment of capital through sales or monetization of assets, the timing of repatriation of foreign earnings and the use of equity financing to reduce our future use of debt, although there can be no assurance that these strategies will reduce any potential adverse impact from these provisions of the TCJA. In addition, although we are not currently expecting the deductibility of our interest costs to affect future earnings based on our method of allocation across our businesses, the interest deduction limitation under the TCJA is subject to potential additional guidance or interpretation from the U.S. Department of the Treasury, and there can be no assurance that any such additional guidance will not impact our current assessment.
It is also uncertain how credit rating agencies will treat the impacts of this legislation in their credit rating metrics, and whether additional avenues will evolve for companies to manage the adverse aspects of this legislation. We believe that these strategies, to the extent available and if successfully applied, could lessen the negative impacts on certain credit metrics, such as our funds from operations-to-debt percentage, although there can be no assurance in this regard.
If we are unable to successfully take actions to manage the potentially adverse impacts of the TCJA, or if additional interpretations, regulations, amendments or technical corrections exacerbate any adverse impacts of the legislation, it could have a material adverse effect on our financial condition, results of operations and cash flows and on the value of investments in our common stock, preferred stock and debt securities, and could result in credit rating agencies placing our credit ratings on negative outlook or downgrading our credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us to issue debt securities and certain other types of financing and could increase borrowing costs under our credit facilities.
We discuss the effects of the TCJA further in Note 6 of the Notes to Consolidated Financial Statements and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.”
Certain credit rating agencies may downgrade our credit ratings or place those ratings on negative outlook, which may adversely affect the market price of our common stock, preferred stock and debt securities.
On December 20, 2017, Moody’s placed Sempra Energy’s credit ratings on negative outlook. Moody’s indicated that this action was triggered by us having entered into a comprehensive stipulation with the Staff of the PUCT and other key stakeholders with

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respect to our Joint Application with Oncor to the PUCT for regulatory approval of the Merger, which Moody’s described as a significant milestone in our attaining regulatory approval for the Merger. In addition, Moody’s indicated that a downgrade of our credit ratings over the 12 to 18 months after December 20, 2017 is likely if they anticipate that our consolidated credit metrics will remain weak, relative to our current credit rating, beyond 2019, specifically if our consolidated ratio of cash flow from operations before changes in working capital to debt remains below 18 percent (assuming successful completion of the Merger) for an extended period of time. Moody’s also indicated that a downgrade could also be considered if there is a further delay in the completion of our Cameron LNG project. S&P has indicated that it could downgrade its rating of Sempra Energy’s senior unsecured debt securities within 12 months following October 9, 2017 if we do not complete the Merger or if the aggregate indebtedness of our subsidiaries continues to exceed 50 percent of our consolidated debt. Moody’s also issued a public comment on December 20, 2017 regarding recent wildfires in northern California and Ventura County, California indicating that the December 6, 2017 decision issued by the CPUC denying SDG&E’s request to recover approximately $379 million of pretax costs associated with the 2007 wildfires (based on the CPUC’s finding that SDG&E did not reasonably operate the facilities involved in the wildfires) is credit negative for SDG&E, for Sempra Energy and for other California utilities seeking to recover costs from wildfires. We discuss the 2007 wildfires further in Note 15 of the Notes to Consolidated Financial Statements.
Moody’s further indicated that it may reassess its view of the California regulatory framework if it determines that the credit supportiveness of California’s regulatory environment has weakened (including as a result of the CPUC’s discretion in denying recovery of wildfire costs), which would also be credit negative and could lead to a downgrade of the credit ratings of California IOUs, including SDG&E, or those ratings being placed on negative outlook. Also, as described in the preceding risk factor, the TCJA could materially adversely affect our credit ratings. The negative outlook by Moody’s, any downgrade of our credit ratings by S&P, Fitch Ratings or Moody’s, or any additional negative outlook on our credit ratings may adversely affect the market price of our common stock, preferred stock and debt securities, and could make it more costly for us to issue debt securities, to borrow under our credit facilities and to raise certain other types of financing. As a result, any additional negative outlook on Sempra Energy, or any downgrade of Sempra Energy’s credit ratings by S&P, Fitch Ratings or Moody’s could be a credit negative for SDG&E or SoCalGas, or both, and result in a downgrade of the credit ratings of SDG&E or SoCalGas, or both. The negative outlook or downgrade of Sempra Energy’s credit ratings by S&P, Fitch Ratings or Moody’s, or any additional negative outlook on Sempra Energy’s credit ratings may adversely affect the market price of SoCalGas’ preferred stock, and both SDG&E’s and SoCalGas’ debt securities, and could make it more costly for SDG&E and SoCalGas to issue debt securities, to borrow under their credit facilities and to raise other types of financing.
Conditions in the financial markets and economic conditions generally may materially adversely affect us.
Our businesses are capital intensive and we rely significantly on long-term debt to fund a portion of our capital expenditures and repay outstanding debt, and on short-term borrowings to fund a portion of day-to-day business operations.
Limitations on the availability of credit and increases in interest rates or credit spreads may materially adversely affect our businesses, cash flows, results of operations, financial condition and/or prospects, as well as our ability to meet contractual and other commitments. In difficult credit market environments, we may find it necessary to fund our operations and capital expenditures at a higher cost or we may be unable to raise as much funding as we need to support new or ongoing business activities. This could cause us to reduce capital expenditures and could increase our cost of servicing debt, both of which could significantly reduce our short-term and long-term profitability.
The availability and cost of credit for our businesses may be greatly affected by credit ratings. If SoCalGas or SDG&E were to have their credit ratings downgraded, their cash flows, results of operations and financial condition could be materially adversely affected, and any downgrades of Sempra Energy’s credit ratings could materially adversely affect the cash flows and results of operations of Sempra Energy. If the credit ratings of Sempra Energy or any of its subsidiaries were downgraded, especially below investment grade, financing costs and the principal amount of borrowings would likely increase due to the additional risk of our debt and because certain counterparties may require collateral in the form of cash, a letter of credit or other forms of security for new and existing transactions. Such amounts may be material and could adversely affect our cash flows, results of operations and financial condition. We discuss our credit ratings further in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and also above under “ Certain credit rating agencies may downgrade our credit ratings or place those ratings on negative outlook, which may adversely affect the market price of our common stock, preferred stock and debt securities.”
Sempra Energy has substantial investments in Mexico and South America which expose us to foreign currency, inflation, legal, tax, economic, geo-political and management oversight risk.
We have significant foreign operations in Mexico and South America. Our foreign operations pose complex management, foreign currency, inflation, legal, tax and economic risks. Certain of these risks differ from and potentially may be greater than those associated with our domestic businesses. All of our international businesses are sensitive to geo-political uncertainties, and our non-utility international businesses are sensitive to changes in the priorities and budgets of international customers, all of which

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may be driven by changes in their environments and potentially volatile worldwide economic conditions, and various regional and local economic and political factors, risks and uncertainties, as well as U.S. foreign policy. Foreign currency exchange and inflation rates and fluctuations in those rates may have an impact on our revenue, costs or cash flows from our international operations, which could materially adversely affect our financial performance. Our currency exposures are to the Mexican, Peruvian and Chilean currencies. Our Mexican subsidiaries have U.S. dollar-denominated monetary assets and liabilities that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities, which are significant, denominated in the Mexican peso that must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. Our primary objective in reducing foreign currency risk is to preserve the economic value of our foreign investments and to reduce earnings volatility that would otherwise occur due to exchange rate fluctuations. We may attempt to offset material cross-currency transactions and earnings exposure through various means, including financial instruments and short-term investments. Because we generally do not hedge our net investments in foreign countries, we are susceptible to volatility in OCI caused by exchange rate fluctuations, primarily related to our South American subsidiaries, whose functional currency is not the U.S. dollar. We generally do not hedge our deferred income tax assets and liabilities, which makes us susceptible to volatility in income tax expense. We discuss our foreign currency exposure at our Mexican subsidiaries in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Mexico developed a legal framework for the regulation of the hydrocarbons and electric power sectors based on a package of constitutional amendments approved by the Mexican Congress in December 2013 and implementing legislation enacted in 2014 and the issuance of new regulations thereunder. We have made significant investments in Mexico based on this legal framework and should the legal framework be modified or withdrawn, it may significantly reduce the value of our existing investments, reduce investment opportunities, and impact our decision to make further investments in Mexico.
The current U.S. administration indicated its intention to renegotiate trade agreements, such as NAFTA, and implement U.S. immigration policy changes by reviewing various options, including tariffs, for funding new Mexico-U.S. border security infrastructure. Such actions could result in changes in the Mexican, U.S. and other markets. In addition, if this occurs, the Mexican government could implement retaliatory actions, such as the imposition of restrictions or import fees on Mexican imports of natural gas from the U.S. or imports and exports of electricity to and from the U.S. Any of these actions by either or both governments could adversely affect imports and exports between Mexico and the U.S. and negatively impact the U.S. and Mexican economies and the companies with whom we conduct business in Mexico, which could materially adversely affect our business, financial condition, results of operations, cash flows, or prospects.
Risks Related to All Sempra Energy Subsidiaries
Severe weather conditions, natural disasters, accidents, equipment failures, explosions or acts of terrorism could materially adversely affect our businesses, financial condition, results of operations, cash flows and/or prospects.
Like other major industrial facilities, ours may be damaged by severe weather conditions, natural disasters such as earthquakes, hurricanes, tsunamis, floods, mudslides and fires, accidents, equipment failures, explosions or acts of terrorism. Because we are in the business of using, storing, transporting and disposing of highly flammable and explosive materials, as well as radioactive materials, and operating highly energized equipment, the risks such incidents may pose to our facilities and infrastructure, as well as the risks to the surrounding communities, are substantially greater than the risks such incidents may pose to a typical business. The facilities and infrastructure that we own or in which we have interests that may be subject to such incidents include, but are not limited to:
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 liquid fuels, LNG and LPG terminals and storage;
nuclear fuel and nuclear waste storage facilities; and
nuclear power facilities (currently being decommissioned).
Such incidents could result in severe business disruptions, prolonged power outages, property damage, injuries or loss of life, significant decreases in revenues and earnings, and/or significant additional costs to us. Such incidents that do not directly affect our facilities may impact our business partners, supply chains and transportation, which could negatively impact construction projects and our ability to provide natural gas and electricity to our customers. Any such incident could have a material adverse effect on our businesses, financial condition, results of operations, cash flows and/or prospects.

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Depending on the nature and location of the facilities and infrastructure affected, any such incident also could cause catastrophic fires; natural gas, natural gas odorant, propane or ethane leaks; releases of other greenhouse gases; radioactive releases; explosions, spills or other significant damage to natural resources or property belonging to third parties; personal injuries, health impacts or fatalities; or present a nuisance to impacted communities. Any of these consequences could lead to significant claims against us. In some cases, we may be liable for damages even though we are not at fault, such as in cases where the doctrine of inverse condemnation applies. We discuss how the application of this doctrine in California has impacted SDG&E’s ability to recover certain costs associated with the 2007 wildfires in SDG&E’s territory and the proceedings related thereto in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Factors Influencing Future Performance,” in Note 15 of the Notes to Consolidated Financial Statements and below under “Risks Related to the California Utilities Insurance coverage for future wildfires may be unobtainable, prohibitively expensive, or insufficient to cover losses we may incur, and we may be unable to recover costs in excess of insurance through regulatory mechanisms.” Insurance coverage may significantly increase in cost or become prohibitively expensive, may be disputed by the insurers, or may become unavailable for certain of these risks or at sufficient levels, and any insurance proceeds we receive may be insufficient to cover our losses or liabilities due to the existence of limitations, exclusions, high deductibles, failure to comply with procedural requirements, and other factors, which could materially adversely affect our businesses, financial condition, results of operations, cash flows and/or prospects. In addition, any inability to recover uninsured costs associated with wildfires, or the perception that such costs may not be recoverable, could materially adversely affect the trading prices of our common stock, preferred stock and debt securities.
Severe weather conditions may also impact our businesses, including our international operations. Frequent drought conditions and unseasonably warm temperatures have increased the degree and prevalence of wildfires in California including in SDG&E’s and SoCalGas’ service territories, which could place third party property and our electric and natural gas infrastructure in jeopardy and reduce the availability of hydroelectric generators, which could result in temporary power shortages in SDG&E’s and SoCalGas’ service territories. In addition, severe weather conditions could result in delays and/or cost increases to our capital projects.
Additionally, severe rainstorms and associated high winds, as well as flooding and mudslides where vegetation has been destroyed as result of human modification or wildfires, along the coastal areas in our service territories could damage our electric and natural gas infrastructure, resulting in increased expenses, including higher maintenance and repair costs, and interruptions in electricity and natural gas delivery services. As a result, these events can have significant financial consequences, including regulatory penalties and disallowances if the California Utilities or our utilities in Mexico or South America encounter difficulties in restoring service to their customers on a timely basis. Further, the cost of storm restoration efforts may not be fully recoverable through the regulatory process. Any such events could have a material adverse effect on our businesses, financial condition, results of operations and cash flows.
Our businesses are subject to complex government regulations and tax requirements and may be materially adversely affected by changes in these regulations or requirements or in their interpretation or implementation.
In recent years, the regulatory environment that applies to the electric power and natural gas industries has undergone significant changes, on the federal, state and local levels. These changes have affected the nature of these industries and the manner in which their participants conduct their businesses. These changes are ongoing, and we cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on our businesses. Moreover, existing regulations, laws and tariffs may be revised or reinterpreted, and new regulations, laws and tariffs may be adopted or become applicable to us and our facilities. Special tariffs may also be imposed on components used in our businesses that could increase costs.
Our businesses are subject to increasingly complex accounting and tax requirements, and the regulations, laws and tariffs that affect us may change in response to economic or political conditions. Compliance with these requirements could increase our operating costs. In addition to the TCJA described above, any new tax legislation, regulations or other interpretations in the U.S. and other countries in which we operate could materially adversely affect our tax expense and/or tax balances, and changes in tax policies could materially adversely impact our business. Changes in regulations, laws and tariffs and how they are implemented and interpreted may have a material adverse effect on our businesses, cash flows, financial condition, results of operations and/or prospects.
Our operations are subject to rules relating to transactions among the California Utilities and other Sempra Energy businesses. These rules are commonly referred to as “affiliate rules,” which primarily impact commodity and commodity-related transactions. These businesses could be materially adversely affected by changes in these rules or to their interpretations, or by additional CPUC or FERC rules that further restrict our ability to sell electricity or natural gas to, or to trade with, the California Utilities and with each other. Affiliate rules also restrict these businesses from entering into any such transactions with the California

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Utilities. Any such restrictions on or approval requirements for transactions among affiliates could materially adversely affect the LNG terminals, natural gas pipelines, electric generation facilities, or other operations of our subsidiaries, which could have a material adverse effect on our businesses, results of operations and/or prospects.
Our businesses require numerous permits, licenses, franchise agreements, and other governmental approvals from various federal, state, local and foreign governmental agencies; any failure to obtain or maintain required permits, licenses or approvals could cause our sales to materially decline and/or our costs to materially increase, and otherwise materially adversely affect our businesses, cash flows, financial condition, results of operations and/or prospects.
All of our existing and planned development projects require multiple approvals. The acquisition, construction, ownership and operation of marine and inland liquid fuels, LNG and LPG terminals and storage; natural gas pipelines and distribution and storage facilities; electric generation, transmission and distribution facilities; and propane and ethane systems require numerous permits, licenses, franchise agreements, certificates and other approvals from federal, state, local and foreign governmental agencies. Once received, approvals may be subject to litigation, and projects may be delayed or approvals reversed or modified in litigation. In addition, permits, licenses, franchise agreements, certificates, and other approvals may be modified, rescinded or fail to be extended by one or more of the governmental agencies and authorities that oversee our businesses. SoCalGas’ franchise agreements with Los Angeles County and the City of Los Angeles, where the Aliso Canyon natural gas storage facility is located, are due to expire in 2018 and 2019, respectively. If there is a delay in obtaining required regulatory approvals or failure to obtain or maintain required approvals or to comply with applicable laws or regulations, we may be precluded from constructing or operating facilities, or we may be forced to incur additional costs. Further, accidents beyond our control may cause us to violate the terms of conditional use permits, causing delays in projects. Any such delay or failure to obtain or maintain necessary permits, licenses, certificates and other approvals could cause our sales to materially decline, and/or our costs to materially increase, and otherwise materially adversely affect our businesses, cash flows, financial condition, results of operations and/or prospects.
Our businesses have significant environmental compliance costs, and future environmental compliance costs could have a material adverse effect on our cash flows and results of operations.
Our businesses are subject to extensive federal, state, local and foreign statutes, rules and regulations and mandates relating to environmental protection, including, air quality, water quality and usage, wastewater discharge, solid waste management, hazardous waste disposal and remediation, conservation of natural resources, wetlands and wildlife, renewable energy resources, climate change and GHG emissions. We are required to obtain numerous governmental permits, licenses, certificates and other approvals to construct and operate our businesses. Additionally, to comply with these legal requirements, we must spend significant amounts on environmental monitoring, pollution control equipment, mitigation costs and emissions fees. The California Utilities may be materially adversely affected if these additional costs for projects are not recoverable in rates. In addition, we may be ultimately responsible for all on-site liabilities associated with the environmental condition of our marine and inland liquid fuels, LNG and LPG terminals and storage; natural gas transmission, distribution and storage facilities; electric generation, transmission and distribution facilities; and other energy projects and properties; regardless of when the liabilities arose and whether they are known or unknown, which exposes us to risks arising from contamination at our former or existing facilities or with respect to offsite waste disposal sites that have been used in our operations. In the case of our California and other regulated utilities, some of these costs may not be recoverable in rates. Our facilities, including those in our joint ventures, are subject to laws and regulations protecting migratory birds, which have been the subject of increased enforcement activity with respect to wind farms. Failure to comply with applicable environmental laws, regulations and permits may subject our businesses to substantial penalties and fines and/or significant curtailments of our operations, which could materially adversely affect our cash flows and/or results of operations.
Increasing international, national, regional and state-level environmental concerns as well as related new or proposed legislation and regulation may have substantial negative effects on our operations, operating costs, and the scope and economics of proposed expansions, which could have a material adverse effect on our results of operations, cash flows and/or prospects. In particular, state-level laws and regulations, as well as proposed state, national and international legislation and regulation relating to the control and reduction of GHG emissions, may materially limit or otherwise materially adversely affect our operations. The implementation of recent and proposed California legislation and regulation may materially adversely affect our non-utility businesses by imposing, among other things, additional costs associated with emission limits, controls and the possible requirement of carbon taxes or the purchase of emissions credits. Similarly, California SB 350 requires all load-serving entities, including SDG&E, to file integrated resource plans that will ultimately enable the electric sector to achieve reductions in GHG emissions of 40 percent compared to 1990 levels by 2030. Our California Utilities may be materially adversely affected if these additional costs are not recoverable in rates. Even if recoverable, the effects of existing and proposed GHG emission reduction standards may cause rates to increase to levels that substantially reduce customer demand and growth and may have a material adverse effect on the California Utilities’ cash flows. SDG&E may also be subject to significant penalties and fines if certain mandated renewable energy goals are not met.

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In addition, existing and future laws, orders and regulations regarding mercury, nitrogen and sulfur oxides, particulates, methane or other emissions could result in requirements for additional monitoring, pollution monitoring and control equipment, safety practices or emission fees, taxes or penalties that could materially adversely affect our results of operations and/or cash flows. Moreover, existing rules and regulations may be interpreted or revised in ways that may materially adversely affect our results of operations and/or cash flows.
We provide further discussion of these matters in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 15 of the Notes to Consolidated Financial Statements.
Our businesses, results of operations, financial condition and/or cash flows may be materially adversely affected by the outcome of litigation against us.
Sempra Energy and its subsidiaries are defendants in numerous lawsuits and arbitration proceedings. We have spent, and continue to spend, substantial amounts of money and time defending these lawsuits and proceedings, and in related investigations and regulatory proceedings. We discuss pending proceedings in Note 15 of the Notes to Consolidated Financial Statements and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The uncertainties inherent in lawsuits, arbitrations and other legal proceedings make it difficult to estimate with any degree of certainty the costs and effects of resolving these matters. In addition, juries have demonstrated a willingness to grant large awards, including punitive damages, in personal injury, product liability, property damage and other claims. Accordingly, actual costs incurred may differ materially from insured or reserved amounts and may not be recoverable in whole or in part by insurance or in rates from our customers, which in each case could materially adversely affect our businesses, cash flows, results of operations and/or financial condition.
We cannot and do not attempt to fully hedge our assets or contract positions against changes in commodity prices. In addition, for those contract positions that are hedged, our hedging procedures may not mitigate our risk as planned.
To reduce financial exposure related to commodity price fluctuations, we may enter into contracts to hedge our known or anticipated purchase and sale commitments, inventories of natural gas and LNG, natural gas storage and pipeline capacity and electric generation capacity. As part of this strategy, we may use forward contracts, physical purchase and sales contracts, futures, financial swaps, and options. We do not hedge the entire exposure to market price volatility of our assets or our contract positions, and the coverage will vary over time. To the extent we have unhedged positions, or if our hedging strategies do not work as planned, fluctuating commodity prices could have a material adverse effect on our results of operations, cash flows and/or financial condition. Certain of the contracts we use for hedging purposes are subject to fair value accounting. Such accounting may result in gains or losses in earnings for those contracts. In certain cases, these gains or losses may not reflect the associated losses or gains of the underlying position being hedged.
Risk management procedures may not prevent losses.
Although we have in place risk management and control systems that use advanced methodologies to quantify and manage risk, these systems may not prevent material losses. Risk management procedures may not always be followed as intended by our businesses or may not work as planned. In addition, daily value-at-risk and loss limits are based on historic price movements. If prices significantly or persistently deviate from historic prices, the limits may not protect us from significant losses. As a result of these and other factors, there is no assurance that our risk management procedures will prevent losses that would materially adversely affect our results of operations, cash flows and/or financial condition.
The operation of our facilities depends on good labor relations with our employees.
Several of our businesses have entered into and have in place collective bargaining agreements with different labor unions. Our collective bargaining agreements are generally negotiated on a company-by-company basis. Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our businesses, results of operations and/or cash flows.
New business technologies implemented by us or developed by others present a risk for increased attacks on our information systems and the integrity of our energy grid and our natural gas pipeline and storage infrastructure.
In addition to general information and cyber risks that all Fortune 500 corporations face (e.g. malware, malicious intent by insiders and inadvertent disclosure of sensitive information), the utility industry faces evolving cybersecurity risks associated with protecting sensitive and confidential customer information, Smart Grid infrastructure, and natural gas pipeline and storage infrastructure. Deployment of new business technologies represents a new and large-scale opportunity for attacks on our information systems and confidential customer information, as well as on the integrity of the energy grid and the natural gas infrastructure. While our computer systems have been, and will likely continue to be, subjected to computer viruses or other malware, unauthorized access attempts, and cyber- or phishing-attacks, to date we have not detected a material breach of

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cybersecurity. Addressing these risks is the subject of significant ongoing activities across Sempra Energy’s businesses, but we cannot assure that a successful attack has not occurred and will not occur. An attack on our information systems, the integrity of the energy grid, our natural gas, ethane, or propane pipeline and storage infrastructure or one of our facilities, or unauthorized access to confidential customer information, could result in energy delivery service failures, financial loss, violations of privacy laws, customer dissatisfaction and litigation, any of which, in turn, could have a material adverse effect on our businesses, cash flows, financial condition, results of operations and/or prospects.
In the ordinary course of business, Sempra Energy and its subsidiaries collect and retain sensitive information, including personal identification information about customers and employees, customer energy usage and other information. The theft, damage or improper disclosure of sensitive electronic data can subject us to penalties for violation of applicable privacy laws, subject us to claims from third parties, require compliance with notification and monitoring regulations, and harm our reputation.
Further, as seen with recent cyber-attacks around the world, the goal of a cyber-attack may be primarily to inflict large-scale harm on a company and the places where it operates. Any such cyber-attack could cause widespread disruptions to our operating, financial and administrative systems, including the destruction of critical information and programming that could materially adversely affect our business operations and the integrity of the power grid, negatively impact our ability to produce accurate and timely financial statements or comply with ongoing disclosure obligations or other regulatory requirements, and/or release confidential information about our company and our customers, employees and other constituents, any of which could lead to sanctions or negatively affect the general perception of our business in the financial markets and which could have a material adverse effect on our businesses, cash flows, financial condition, results of operations and/or prospects.
Our businesses will need to continue to adapt to technological change which may cause us to incur significant expenditures to adapt to these changes and which efforts may not be successful or such expenditures may not be recovered.
Emerging technologies may be superior to, or may not be compatible with, some of our existing technologies, investments and infrastructure, and may require us to make significant expenditures to remain competitive, or may result in the obsolescence of certain of our operating assets or the operating assets of our investees. Our future success will depend, in part, on our ability and our investment partners’ abilities to anticipate and successfully adapt to technological changes, to offer services that meet customer demands and evolving industry standards and to recover all, or a significant portion of, any unrecovered investment in obsolete assets. If we incur significant expenditures in adapting to technological changes, fail to adapt to significant technological changes, fail to obtain access to important new technologies, fail to recover a significant portion of any remaining investment in obsolete assets, or if implemented technology fails to operate as intended, our businesses, operating results and financial condition could be materially and adversely affected. Examples of technological changes that could negatively impact our businesses include
Sempra Utilities – Technologies that could change the utilization of natural gas distribution and electric generation, transmission and distribution assets, including:
the expanded cost-effective utilization of distributed generation (e.g., rooftop solar and community solar projects), and
energy storage technology.
Sempra Infrastructure
At Sempra Renewables, technological advances in distributed and local power generation and energy storage could reduce the demand for large-scale renewable electricity generation. Sempra Renewables’ customers’ ability to perform under long-term agreements could be impacted by changes in utility rate structures and advances in distributed and local power generation.
At Sempra LNG & Midstream, technological advances could reduce the demand for natural gas. These technologies include cost-effective batteries for renewable electricity generation, economic improvements to gas-to-liquids conversion processes, and advances in alternative fuels and other alternative energy sources.
 Risks Related to the California Utilities
The California Utilities are subject to extensive regulation by state, federal and local legislative and regulatory authorities, which may materially adversely affect us.
The CPUC regulates the California Utilities’ rates, except SDG&E’s electric transmission rates which are regulated by the FERC. The CPUC also regulates the California Utilities’:
conditions of service;
capital structure;
rates of return;

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rates of depreciation;
long-term resource procurement; and
sales of securities.
The CPUC conducts various reviews and audits of utility performance, safety standards and practices, compliance with CPUC regulations and standards, affiliate relationships and other matters. These reviews and audits may result in disallowances, fines and penalties that could materially adversely affect our financial condition, results of operations and/or cash flows. SoCalGas and SDG&E may be subject to penalties or fines related to their operation of natural gas pipelines and storage and, for SDG&E, electric operations, under regulations concerning natural gas pipeline safety and citation programs concerning both gas and electric safety, which could have a material adverse effect on their results of operations, financial condition and/or cash flows. We discuss various CPUC proceedings relating to the California Utilities’ rates, costs, incentive mechanisms, and performance-based regulation in Notes 13, 14 and 15 of the Notes to Consolidated Financial Statements and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The CPUC periodically approves the California Utilities’ rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investment. Delays by the CPUC on decisions authorizing recovery, after-the-fact reasonableness reviews with unclear standards or authorizations for less than full recovery may adversely affect the working capital, cash flows and financial condition of each of the California Utilities. If the California Utilities receive an adverse CPUC decision and/or actual capital expenditures and/or operating costs were to exceed the amounts approved by the CPUC, our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected. Reductions in key benchmark interest rates may trigger automatic adjustment mechanisms which would reduce the California Utilities’ authorized rates of return, changes in which could materially adversely affect their results of operations, financial condition, cash flows and/or prospects.
SoCalGas and SDG&E have significantly invested and continue to invest in major programs, such as PSEP, under an approved CPUC decision tree framework. However, the total investment to date is substantially subject to CPUC reasonableness review. Although we believe these costs have been prudently incurred, the standards applied by the CPUC could result in the disallowance of certain of these historical costs, which could adversely affect SDG&E’s, SoCalGas’ and Sempra Energy’s results of operations, financial condition and cash flows.
The CPUC now incorporates a risk-based decision-making framework in its review of GRC applications for major natural gas and electric utilities in California. We cannot estimate whether its application in the 2019 GRC or future GRC applications will result in full recovery of costs. We discuss this further in Note 14 of the Notes to Consolidated Financial Statements.
In California, there are laws that establish rules governing, among other subjects, communications between CPUC officials, CPUC staff and regulated utilities. Rules and processes around ex parte communications could result in delayed decisions, increased investigations, enforcement actions and penalties. In addition, the CPUC or other parties may initiate investigations of past communications between public utilities and CPUC officials and staff that could result in reopening completed proceedings for reconsideration.
The FERC regulates electric transmission rates, the transmission and wholesale sales of electricity in interstate commerce, transmission access, the rates of return on investments in electric transmission assets, and other similar matters involving SDG&E.
The California Utilities may be materially adversely affected by new legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies. In addition, existing legislation or regulations may be revised or reinterpreted. New, revised or reinterpreted legislation, regulations, decisions, orders or interpretations could change how the California Utilities operate, could affect their ability to recover various costs through rates or adjustment mechanisms, or could require them to incur substantial additional expenses.
The construction and expansion of the California Utilities’ natural gas pipelines, SoCalGas’ storage facilities, and SDG&E’s electric transmission and distribution facilities require numerous permits, licenses, rights-of-way and other approvals from federal, state and local governmental agencies, including approvals and renewals of rights-of-way over Native American tribal land held in trust by the federal government. Successfully maintaining or renewing any or all of these approvals could result in higher costs or, in the event one or more of these approvals were to expire, could require us to remove the associated assets from service, construct new assets intended to bypass the impacted area, or both, and our ability to recover higher costs associated with these events cannot be assured. If there are delays in obtaining these approvals, failure to obtain or maintain these approvals, difficulties in renewing rights-of-way and other property rights, or failure to comply with applicable laws or regulations, the California Utilities’ businesses, cash flows, results of operations, financial condition and/or prospects could be adversely affected.

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Successfully coordinating and completing expansion and construction projects requires good execution from our employees and contractors, cooperation of third parties and the absence of litigation and regulatory delay. In the event that one or more of these projects is delayed or experiences significant cost overruns, this could have a material adverse effect on the California Utilities. The California Utilities may invest a significant amount of money in a major capital project prior to receiving regulatory approval. If the project does not receive regulatory approval, if the regulatory approval is conditioned on major changes, or if management decides not to proceed with the project, they may be unable to recover any or all amounts invested in that project, which could materially adversely affect their financial condition, results of operations, cash flows and/or prospects.
Our California Utilities are also affected by the activities of organizations such as TURN, Utility Consumers’ Action Network, Sierra Club and other stakeholder, advocacy and activist groups. Operations that may be influenced by these groups include
the rates charged to our customers;
our ability to site and construct new facilities;
our ability to purchase or construct generating facilities;
our ability to shut down power for safety reasons, including potentially dangerous wildfire conditions;
general safety;
accounting and income tax matters, including changes in tax law;
transactions between affiliates;
the installation of environmental emission controls equipment;
our ability to decommission generating and other facilities and recover the remaining carrying value of such facilities and related costs;
our ability to recover costs incurred in connection with nuclear decommissioning activities from trust funds established to pay for such costs;
the amount of certain sources of energy we must use, such as renewable sources; limits on the amount of certain energy sources we can use, such as natural gas; and programs to encourage reductions in energy usage by customers; and
the amount of costs associated with these and other operations that may be recovered from customers.
SoCalGas has incurred and may continue to incur significant costs and expenses related to remediating the natural gas leak at its Aliso Canyon natural gas storage facility and to mitigate local community and environmental impacts from the leak, some or a substantial portion of which may not be recoverable through insurance, and SoCalGas also may incur significant liabilities for damages, restitution, fines, penalties and other costs, and GHG mitigation activities as a result of this incident, some or a significant portion of which may not be recoverable through insurance.
In October 2015, SoCalGas discovered a leak at one of its injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility (the Leak), located in the northern part of the San Fernando Valley in Los Angeles County, California. The Aliso Canyon natural gas storage facility has been operated by SoCalGas since 1972. SS25 is one of more than 100 injection-and-withdrawal wells at the storage facility. SoCalGas worked closely with several of the world’s leading experts to stop the Leak, and in February 2016, DOGGR confirmed that the well was permanently sealed.
Local Community Mitigation Efforts
Pursuant to a stipulation and order by the LA Superior Court, SoCalGas provided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed, at significant cost to SoCalGas. Following the permanent sealing of the well and the completion of the DPH’s indoor testing of certain homes in the Porter Ranch community, which concluded that indoor conditions did not present a long-term health risk and that it was safe for residents to return home, the LA Superior Court issued an order in May 2016 ruling that currently relocated residents be given the choice to request residence cleaning prior to returning home, with such cleaning to be performed according to the DPH’s proposed protocol and at SoCalGas’ expense. SoCalGas completed the cleaning program, and the relocation program ended in July 2016.
In May 2016, the DPH also issued a directive that SoCalGas professionally clean (in accordance with the proposed protocol prepared by the DPH) the homes of all residents located within the Porter Ranch Neighborhood Council boundary, or who participated in the relocation program, or who are located within a five-mile radius of the Aliso Canyon natural gas storage facility and have experienced symptoms from the Leak (the Directive). SoCalGas disputes the Directive, contending that it is invalid and unenforceable, and has filed a petition for writ of mandate to set aside the Directive.
The costs incurred to remediate and stop the Leak and to mitigate local community impacts have been significant and may increase, and we may be subject to potentially significant damages, restitution, and civil, administrative and criminal fines, penalties and other costs. To the extent any of these costs are not covered by insurance (including any costs in excess of

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applicable policy limits), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
Insurance and Estimated Costs
Excluding directors’ and officers’ liability insurance, we have four kinds of insurance policies that together provide between $1.2 billion and $1.4 billion in insurance coverage, depending on the nature of the claims. These policies are subject to various policy limits, exclusions and conditions. We intend to pursue the full extent of our insurance coverage for the costs we have incurred or may incur. Through December 31, 2017, we have received $469 million of insurance proceeds for portions of control-of-well expenses, lost gas and temporary relocation costs. There can be no assurance that we will be successful in obtaining additional insurance recovery for costs related to the Leak under the applicable policies, and to the extent we are not successful in obtaining additional recovery or these costs exceed the amount of our coverage, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial conditions and results of operations.
At December 31, 2017, SoCalGas estimates that its costs related to the Leak are $913 million, which includes $887 million of costs recovered or probable of recovery from insurance. This estimate may rise significantly as more information becomes available. In addition, costs not included in the cost estimate of $913 million could be material. As described in “Governmental Investigations and Civil and Criminal Litigation” below, the actions against us seek compensatory and punitive damages, restitution, and civil, administrative and criminal fines, penalties and other costs, which except for the amounts paid or estimated to settle certain actions, are not included in the $913 million cost estimate as it is not possible at this time to predict the outcome of these actions or reasonably estimate the amount of damages, restitution or civil, administrative or criminal fines, penalties or other costs. The recorded amounts above also do not include costs to clean additional homes pursuant to the Directive, future legal costs to defend litigation, and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate. Furthermore, the cost estimate of $913 million does not include certain other costs expensed by Sempra Energy through December 31, 2017 associated with defending shareholder derivative lawsuits. There can be no assurance that we will be successful in obtaining insurance coverage for these costs under the applicable policies, and to the extent we are not successful in obtaining coverage or these costs exceed the amount of our coverage, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
Governmental Investigations and Civil and Criminal Litigation
Various governmental agencies, including DOGGR, DPH, SCAQMD, CARB, Los Angeles Regional Water Quality Control Board, California Division of Occupational Safety and Health, CPUC, PHMSA, EPA, Los Angeles County District Attorney’s Office and California Attorney General’s Office, have investigated or are investigating this incident. Other federal agencies (e.g., the DOE and U.S. Department of the Interior) investigated the incident as part of a joint interagency task force. In January 2016, DOGGR and the CPUC selected Blade Energy Partners to conduct, under their supervision, an independent analysis of the technical root cause of the Leak, to be funded by SoCalGas. The timing of completion of the root cause analysis is under the control of Blade Energy Partners, DOGGR and the CPUC.
As of February 22, 2018, 373 lawsuits, including over 45,000 plaintiffs, are pending in the LA Superior Court against SoCalGas, some of which have also named Sempra Energy.
These various lawsuits have been coordinated before a single court and will be managed under a Second Amended Master Complaint for Individual Actions, and two consolidated class action complaints. In addition, a federal securities class action alleging violation of the federal securities laws has been filed against Sempra Energy and certain of its officers and directors in the SDCA. Five shareholder derivative actions alleging breach of fiduciary duties have been filed against certain officers and directors of Sempra Energy and/or SoCalGas, four of which were joined in a Consolidated Shareholder Derivative Complaint in August 2017. Three complaints have also been filed by public entities, including the California Attorney General and the County of Los Angeles. These complaints seek various remedies, including injunctive relief, abatement of the public nuisance, civil penalties, payment of the cost of a longitudinal health study, and money damages, as well as punitive damages and attorneys’ fees. Additional litigation may be filed against us in the future related to the Leak or our responses thereto. For a more detailed description of the governmental investigations and civil and criminal lawsuits brought against us, see Note 15 of the Notes to Consolidated Financial Statements.
The costs of defending against the civil and criminal lawsuits, cooperating with the various investigations, and any damages, restitution, and civil, administrative and criminal fines, penalties and other costs, if awarded or imposed, as well as the costs of mitigating the actual natural gas released, could be significant and to the extent not covered by insurance (including any costs in excess of applicable policy limits), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

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Regulatory Proceedings
In February 2017, the CPUC opened a proceeding pursuant to SB 380 to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region. The order establishing the scope of the proceeding expressly excludes issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Leak.
Section 455.5 of the California Public Utilities Code, among other things, directs regulated utilities to notify the CPUC if all or any portion of a major facility has been out of service for nine consecutive months. Although SoCalGas does not believe the Aliso Canyon natural gas storage facility or any portion of that facility was out of service for nine consecutive months, SoCalGas provided notification out of an abundance of caution to demonstrate its commitment to regulatory compliance and transparency, and because obtaining authorization to resume injection operations at the facility required more time than initially contemplated. In response, and as required by section 455.5, the CPUC issued an OII to address whether the Aliso Canyon natural gas storage facility or any portion of that facility was out of service for nine consecutive months within the meaning of section 455.5, and if so, whether the CPUC should disallow costs for such period from SoCalGas’ rates. Under section 455.5, hearings on the investigation are to be held, if necessary, in conjunction with SoCalGas’ 2019 GRC proceeding. If the CPUC determines that all or any portion of the facility was out of service for nine consecutive months, the amount of any refund to ratepayers and the inability to earn a return on those assets could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
Governmental Orders and Additional Regulation
In December 2015, SoCalGas made a commitment to mitigate the actual natural gas released from the Leak and has been working on a plan to accomplish the mitigation. In March 2016, the CARB issued its recommended approach to achieve full mitigation of the emissions from the Leak, which includes recommendations that:
reductions in short-lived climate pollutants and other greenhouse gases be at least equivalent to the amount of the emissions from the Leak,
a 20-year global warming potential be used in deriving the amount of reductions required (rather than the 100-year term the CARB and other state and federal agencies use in regulating emissions), and
all of the mitigation occur in California over the next five to ten years without the use of allowances or offsets.
In October 2016, CARB issued its final report concluding that the incident resulted in total emissions from 90,350 to 108,950 metric tons of methane, and asserting that SoCalGas should mitigate 109,000 metric tons of methane to fully mitigate the greenhouse gas impacts of the Leak. Although we have not agreed with CARB’s estimate of methane released, we continue to work with CARB on developing a mitigation plan.
PHMSA, DOGGR, SCAQMD, EPA and CARB have each commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. DOGGR has issued new draft regulations for all storage fields in California, and in 2016, the California Legislature enacted four separate bills providing for additional regulation of natural gas storage facilities. Additional hearings in the California Legislature, as well as with various other federal and state regulatory agencies, may be scheduled, and additional laws, orders, rules and regulations may be adopted.
Higher operating costs and additional capital expenditures incurred by SoCalGas as a result of new laws, orders, rules and regulations arising out of this incident or our responses thereto could be significant and may not be recoverable through insurance or in customer rates, and SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations may be materially adversely affected by any such new laws, orders, rules and regulations.
Natural Gas Storage Operations and Reliability
Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and heating needs in the winter. The Aliso Canyon natural gas storage facility, with a storage capacity of 86 Bcf (which represents 63 percent of SoCalGas’ natural gas storage inventory capacity), is the largest SoCalGas storage facility and an important element of SoCalGas’ delivery system. Beginning October 24, 2015, pursuant to orders by DOGGR and the Governor of the State of California, and SB 380, SoCalGas suspended injection of natural gas into the Aliso Canyon natural gas storage facility. Limited withdrawals of natural gas from the Aliso Canyon natural gas storage facility were made in 2017 to augment natural gas supplies during critical demand periods. In July 2017, DOGGR issued an order lifting the prohibition on injection at Aliso Canyon, subject to certain operational requirements, and SoCalGas resumed limited injections.
If the Aliso Canyon natural gas storage facility were to be taken out of service for any meaningful period of time, it could result in an impairment of the facility, significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At December 31, 2017, the Aliso Canyon natural gas storage facility

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has a net book value of $644 million, including $252 million of construction work in progress for the project to construct a new compressor station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, and SoCalGas’ and Sempra Energy’s results of operations, cash flows and financial condition may be materially adversely affected.
Additional Information
We discuss Aliso Canyon natural gas storage facility matters further in Note 15 of the Notes to Consolidated Financial Statements and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”
Natural gas pipeline safety assessments may not be fully or adequately recovered in rates.
Pending the outcome of various regulatory agency evaluations of natural gas pipeline safety regulations, practices and procedures, Sempra Energy, including the California Utilities, may incur incremental expense and capital investment associated with their natural gas pipeline operations and investments. The California Utilities filed implementation plans with the CPUC to test or replace natural gas transmission pipelines located in populated areas that either have not been pressure tested or lack sufficient documentation of a pressure test, to enhance existing valve infrastructure and to retrofit pipelines to allow for the use of in-line inspection technology, referred to as SoCalGas’ and SDG&E’s PSEP.
In June 2014, the CPUC issued a final decision approving the utilities’ plan for implementing PSEP, and established criteria to determine the amounts related to PSEP that may be recovered from ratepayers and the processes for recovery of such amounts, including providing that such costs are subject to a reasonableness review. In the future, certain PSEP costs may be subject to recovery as determined by separate regulatory filings with the CPUC, including GRC filings.
Various PSEP-related proceedings are regularly pending before the CPUC regarding the California Utilities’ reasonableness review and cost recovery requests, which are often challenged by intervening parties. These proceedings are described in more detail in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.” In the future, consumer advocacy groups may similarly challenge the California Utilities’ petitions for recovery and recommend disallowances in whole or in part with respect to applications to recover PSEP costs.
From 2011 through 2017, SoCalGas and SDG&E have invested approximately $1.3 billion and $355 million, respectively, in PSEP, with substantial additional expenditures planned. As of December 31, 2017, SoCalGas has received approval for recovery of $33 million. If the CPUC denies or significantly delays rate recovery for PSEP and other gas pipeline safety costs incurred by SoCalGas and SDG&E, it could materially adversely affect the respective company’s cash flows, financial condition, results of operations and prospects.
The California Utilities are subject to increasingly stringent safety standards and the potential for significant penalties if regulators deem either SDG&E or SoCalGas to be out of compliance.
California SB 291 requires the CPUC to develop and maintain a safety enforcement program that includes procedures for monitoring, data tracking and analysis, and investigations, and delegates citation authority to CPUC staff personnel under the direction of the CPUC Executive Director. In exercising this citation authority, the CPUC staff is to take into account voluntary reporting of potential violations, voluntary resolution efforts undertaken, prior history of violations, the gravity of the violation, and the degree of culpability. The CPUC previously implemented both electric and gas safety enforcement programs whereby electric and gas utilities may be cited by CPUC staff for violations of the CPUC’s safety requirements or applicable federal standards.
Under each enforcement program, each day of an ongoing violation may be counted as an additional offense. The maximum penalty is $50,000 per offense. CPUC staff has authority to issue citations up to an administrative limit of $8 million per citation under either program and such citations may be appealed to the CPUC. Although citations issued under these enforcement programs do include an administrative limit, penalties issued by the CPUC can exceed this limit, having exceeded $1.5 billion in one instance for an unrelated third party.
If the CPUC or its staff determine that either of SDG&E’s or SoCalGas’ operations and practices are not in compliance with applicable safety standards and operating procedures, the corrective or mitigation actions required to be in conformance, if not sufficiently funded in customer rates, and any penalties imposed, could materially adversely affect that company’s cash flows, financial condition, results of operations and prospects.

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The failure by the CPUC to continue reforms of SDG&E’s rate structure, including the implementation of a more significant fixed charge, could have a material adverse effect on its business, cash flows, financial condition, results of operations and/or prospects.
The current electric rate structure in California is primarily based on consumption volume, which places an undue burden on residential customers with higher electric use while subsidizing lower use customers. As higher electric use residential customers switch to self-generation or obtain local off-the-grid sources of power, such as rooftop solar, the burden on the remaining higher electric use customers increases, which in turn encourages more self-generation, further increasing rate pressure on existing customers. In July 2015, the CPUC adopted a decision that establishes comprehensive reform and a framework for rates that are more transparent, fair and sustainable. The decision provides for a minimum monthly bill, fewer rate tiers and a gradual reduction in the differences between the tiered rates, directs the utilities to pursue expanded TOU rates, and implemented a super-user electric surcharge in 2017 for usage that exceeds average customer usage by approximately 400 percent within each climate zone. The decision is being implemented over a five-year period from 2015 to 2020, and should result in significant relief for higher-use customers that do not exceed the super-user threshold and a rate structure that better aligns rates with actual costs to serve customers. The decision also establishes a process for utilities to seek implementation of a fixed charge for residential customers in 2020 (but it also sets certain conditions for the implementation of a fixed charge), after the initial reforms are implemented. The establishment of a fixed charge for residential customers may become more critical to help ensure rates are fair for all customers as distributed energy resources could generally reduce delivered volumes and increase fixed costs.
If the CPUC fails to continue to reform SDG&E’s rate structure to maintain reasonable, cost-based electric rates that are competitive with alternative sources of power and adequate to maintain the reliability of the electric transmission and distribution system, such failure could have a material adverse effect on SDG&E’s business, cash flows, financial condition, results of operations and/or prospects.
Meaningful NEM reform must continue to progress to ensure that SDG&E is authorized to recover its costs in providing services to NEM customers while minimizing the cost shift (or subsidy) being borne by non-solar customers.
Due to current rate structures and state policies, customers who self-generate their own electricity using eligible renewable resources (primarily solar installations) currently do not pay their proportionate cost of maintaining and operating the electric transmission and distribution system, subject to certain limitations, while they still receive electricity from the system when their self-generation is inadequate to meet their electricity needs. The proportionate costs not paid by NEM customers are therefore subsidized by consumers not participating in NEM. In addition, the continuing increase of self-generated solar, other forms of self-generation and other local off-the-grid sources of power adversely impacts the reliability of the electric transmission and distribution system.
Appropriate NEM reforms are necessary to help ensure that SDG&E is authorized to recover, from NEM customers, the costs incurred in providing grid and energy services, as well as mandated legislative and regulatory public policy programs. SDG&E believes this design would be preferable to recovering these costs from customers not participating in NEM. If NEM self-generating installations were to increase substantially between 2016 and when more significant reforms take effect in 2019 or later, as described below, the rate structure adopted by the CPUC could have a material adverse effect on SDG&E’s business, cash flows, financial condition, results of operations and/or prospects.
In July 2014, the CPUC initiated a rulemaking proceeding to develop a successor tariff to the state’s existing NEM program pursuant to the provisions of AB 327. The NEM program was originally established in 1995 and is an electric billing tariff mechanism designed to promote the installation of on-site renewable generation. Under NEM, qualifying customer-generators receive a full retail rate for the energy they generate that is fed back to the utility’s power grid. This occurs during times when the customer’s generation exceeds their own energy usage. In addition, if a NEM customer generates any electricity over the annual measurement period that exceeds its annual consumption, they receive compensation at a rate equal to a wholesale energy price.
In January 2016, the CPUC adopted a decision making modest changes to the NEM program, which require NEM customers to pay some costs that would otherwise be borne by non-NEM customers and moves new NEM customers to TOU rates. Together with a reduction in tiered rate differentials and the potential implementation of a fixed charge component in 2020, these changes to the NEM program begin a process of reducing the cost burden on non-NEM customers, but SDG&E believes that further reforms are necessary and appropriate. SDG&E implemented the adopted successor NEM tariff in July 2016, after reaching the 617-MW cap established for the prior NEM program.
The electricity industry is undergoing significant change, including increased deployment of distributed energy resources, technological advancements, and political and regulatory developments.
Electric utilities in California are experiencing increasing deployment of distributed energy resources, such as solar, energy storage, energy efficiency and demand response technologies. This growth will eventually require modernization of the electric

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distribution grid to, among other things, accommodate two-way flows of electricity and increase the grid’s capacity to interconnect distributed energy resources. The CPUC is conducting proceedings to: evaluate various demonstration projects and pilots; implement changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of distributed energy resources; consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by distributed energy resources, and if feasible, what, if any, compensation would be appropriate; and clarify the role of the electric distribution grid operator. These proceedings may result in new regulations, policies and/or operational changes that could materially adversely affect SDG&E’s and Sempra Energy’s businesses, cash flows, financial condition, results of operations and/or prospects.
SDG&E provides bundled electric procurement service through various resources that are typically procured on a long-term basis. While SDG&E provides such procurement service for most of its customer load, customers do have the ability to receive procurement service from a load serving entity other than SDG&E, through programs such as DA and CCA. DA is currently closed, but utility customers could receive procurement through CCA, if the customer’s local jurisdiction (city) offers such a program. Several local political jurisdictions, including the City of San Diego and a few other municipalities are considering the formation of a CCA, which, if implemented, could result in the departure of more than half of SDG&E’s bundled load. For example, Solana Beach (representing less than one percent of SDG&E’s customer accounts) has elected to begin CCA service in 2018. When customers are served by another load serving entity, SDG&E no longer serves this departing load and the associated costs of the utility’s procured resources could be borne by its remaining bundled procurement customers. State law requires that customers opting to have a CCA procure their electricity must absorb the cost of above-market electricity procurement commitments already made by SDG&E on their behalf, though appropriate mechanisms to ensure that such costs are properly absorbed are not yet in place. If mechanisms to ensure compliance with state law are not in place at the time of these potentially significant reductions in SDG&E’s served load, remaining bundled customers of SDG&E could potentially experience large increases in rates for commodity costs under commitments made on behalf of these CCA customers prior to their departure, which may not be fully recoverable in rates by SDG&E. If legislative, regulatory or legal action were taken to prevent the timely recovery of these procurement costs or if mechanisms are not in place to ensure compliance with state law, the unrecovered costs could have a material adverse effect on SDG&E’s and Sempra Energy’s cash flows, financial condition and results of operations.
Furthermore, California legislators and stakeholder, advocacy and activist groups have expressed a desire to further limit or eliminate reliance on natural gas as an energy source by advocating increased use of renewable energy and electrification in lieu of the use of natural gas. A substantial reduction or the elimination of natural gas as an energy source in California, could have a material adverse effect on SDG&E’s, SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
Insurance coverage for future wildfires may be unobtainable, prohibitively expensive, or insufficient to cover losses we may incur, and we may be unable to recover costs in excess of insurance through regulatory mechanisms.
We have experienced increased costs and difficulties in obtaining insurance coverage for wildfires that could arise from the California Utilities’ operations, particularly SDG&E’s operations. In addition, the insurance that has been obtained for wildfire liabilities may not be sufficient to cover all losses that we may incur. Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates. For example, California courts have invoked the doctrine of inverse condemnation for wildfire damages, whereby if a utility company’s facilities, such as its electric distribution and transmission lines, are determined to be the cause of one or more fires, the utility could be liable for damages, as well as attorneys’ fees, without having been found negligent. As a result of the strict liability standard applied to wildfires, recent losses recorded by insurance companies, and the risk of an increase of wildfires (several catastrophic wildfires occurred in California in late 2017) for reasons such as drought conditions, insurance for wildfire liabilities may not be available or may be available only at rates that are prohibitively expensive. In addition, even if insurance for wildfire liabilities is available, it may not be available in such amounts as are necessary to cover potential losses. A loss which is not fully insured or cannot be recovered in customer rates could materially adversely affect Sempra Energy’s and the affected California Utility’s financial condition, cash flows and results of operations. In addition, we are unable to predict whether we would be allowed to recover in rates the increased costs of insurance or the costs of any uninsured losses.
SDG&E incurred CPUC-related costs to resolve 2007 wildfire claims in excess of its liability insurance coverage and amounts recovered from third parties. In December 2012, the CPUC issued a final decision allowing SDG&E to maintain an authorized memorandum account, enabling SDG&E to file applications with the CPUC requesting recovery of amounts properly recorded in the memorandum account, subject to reasonableness review, at a later date. In September 2015, SDG&E filed an application with the CPUC seeking authority to recover such costs in rates over a six- to ten-year period. On December 6, 2017, the CPUC issued a final decision denying SDG&E’s request to recover the 2007 wildfire costs submitted in our application. If SDG&E is unsuccessful in its efforts to reverse the final decision through the rehearing and appeals process, the 2007 wildfire costs or costs associated with any future wildfires may not be recoverable. In addition, pending legislation may prohibit recovery of any uninsured wildfire costs in cases of inverse condemnation where California utilities are strictly liable. The failure to recover for

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the 2007 wildfires or future wildfires could materially adversely affect Sempra Energy’s and the affected California Utility’s financial condition, cash flows and results of operations.
We discuss these cost recovery proceedings in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance” and in Note 15 of the Notes to Consolidated Financial Statements.
SDG&E may incur substantial costs and liabilities as a result of its partial ownership of a nuclear facility that is being decommissioned.
SDG&E has a 20-percent ownership interest in SONGS, formerly a 2,150-MW nuclear generating facility near San Clemente, California, that is in the process of being decommissioned by Edison, the majority owner of SONGS. SONGS is subject to the jurisdiction of the NRC and the CPUC. On June 6, 2013, Edison notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property, and each owner is responsible for financing its share of expenses and capital expenditures, including decommissioning activities. Although the facility is being decommissioned, SDG&E’s ownership interest in SONGS continues to subject it to the risks of owning a partial interest in a nuclear generation facility, which include
the potential that a natural disaster such as an earthquake or tsunami could cause a catastrophic failure of the safety systems in place that are designed to prevent the release of radioactive material. If such a failure were to occur, a substantial amount of radiation could be released and 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.
In addition, SDG&E maintains nuclear decommissioning trusts for the purpose of providing funds to decommission SONGS. Trust assets have been generally invested in equity and debt securities, which are subject to significant market fluctuations. A decline in the market value of trust assets or an adverse change in the law regarding funding requirements for decommissioning trusts could increase the funding requirements for these trusts, which in each case may not be fully recoverable in rates. Furthermore, CPUC approval is required in order to make withdrawals from these trusts. CPUC approval for certain expenditures may be denied by the CPUC altogether if the CPUC determines that the expenditures are unreasonable. Finally, decommissioning may be materially more expensive than we currently anticipate and therefore decommissioning costs may exceed the amounts in the trust funds. Rate recovery for overruns would require CPUC approval, which may not occur.
Interpretations of tax regulations could impact access to nuclear decommissioning trust funds for reimbursement of spent nuclear fuel management costs. Depending on how the IRS or the U.S. Department of Treasury ultimately interprets or alters regulations addressing the taxation of a qualified nuclear decommissioning trust, SDG&E may be restricted from withdrawing amounts from its qualified decommissioning trusts to pay for spent fuel management while Edison and SDG&E are seeking, or plan to seek, recovery of spent fuel management costs in litigation against, or in settlements with, the DOE. In December 2016, the IRS and the U.S. Department of Treasury issued proposed regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified fund. These proposed regulations will be effective prospectively once they are finalized. SDG&E is waiting for the adoption of, or additional refinement to, the proposed regulations before determining whether the proposed regulations will allow SDG&E to access the NDT funds for reimbursement or payment of the spent fuel management costs that were or will be incurred in 2016 and subsequent years. Until the DOE litigation is resolved, and/or IRS regulations regarding spent fuel management costs are confirmed to apply, SDG&E expects to continue to pay for its share of such spent fuel management costs. If SDG&E is unable to obtain timely access to the trusts for these costs, SDG&E’s cash flows could be negatively impacted.
In November 2014, the CPUC approved the Amended Settlement Agreement that resolved the investigation into the steam generator replacement project that ultimately led to the shut-down of SONGS. Various petitions have since been filed to reopen the settlement. In December 2016, the CPUC issued a ruling directing parties to the SONGS OII to determine whether an agreement could be reached to modify the Amended Settlement Agreement previously approved by the CPUC, to resolve allegations that unreported ex parte communications between Edison and the CPUC resulted in an unfair advantage at the time the settlement agreement was negotiated. In October 2017, the CPUC issued a ruling with respect to the proceeding establishing a process to bring the proceeding to a conclusion and in November 2017, the CPUC held a status conference. In January 2018, the CPUC issued a ruling that further clarified the scope of future evidentiary hearings. This ruling establishes a status conference and includes a preliminary schedule for additional testimony, hearings and briefings. On January 30, 2018, SDG&E, Edison, TURN,

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ORA and other intervenors entered into a Revised Settlement Agreement. On the same date, the parties filed a Joint Motion for Adoption of the Settlement Agreement with the CPUC. If approved by the CPUC, the Revised Settlement Agreement will resolve all issues under consideration in the SONGS OII and will modify the Amended Settlement Agreement. On February 1, 2018, the parties filed a motion to stay the proceedings in the OII pending the CPUC’s consideration of the Revised Settlement Agreement. On February 6, 2018, the CPUC issued a ruling granting the parties’ motion to stay the proceedings and establishing a tentative procedural schedule with public participation hearings in April and July, evidentiary hearings in April and May and briefing in June of 2018.
The timing of a decision from the CPUC on the Joint Motion for Adoption of the Settlement Agreement is uncertain. We cannot assure that the Revised Settlement Agreement will be adopted or that the Amended Settlement Agreement will not be modified or set aside as a result of this OII proceeding.
In connection with the Revised Settlement Agreement, and in exchange for the release of certain SONGS-related claims, SDG&E and Edison entered into an agreement (the Utility Shareholder Agreement) in which Edison has agreed to pay SDG&E the amounts that SDG&E would have received in rates under the Amended Settlement Agreement, but will not receive upon implementation of the Revised Settlement Agreement. The Utility Shareholder Agreement is not subject to the approval of the CPUC. However, it is not effective unless and until the CPUC approves the Revised Settlement Agreement.
We provide additional detail in Note 13 of the Notes to Consolidated Financial Statements.
The occurrence of any of these events could result in a substantial reduction in our expected recovery and have a material adverse effect on SDG&E’s and Sempra Energy’s businesses, cash flows, financial condition, results of operations and/or prospects.
 Risks Related to our Sempra South American Utilities and Sempra Infrastructure Businesses
Our businesses are exposed to market risks, including fluctuations in commodity prices, and our businesses, financial condition, results of operations, cash flows and/or prospects may be materially adversely affected by these risks. Energy-related commodity prices impact LNG liquefaction and regasification, the transport and storage of natural gas, and power generation from renewable and conventional sources, among other businesses that we operate and invest in.
We buy energy-related commodities from time to time, for LNG terminals or power plants to satisfy contractual obligations with customers, in regional markets and other competitive markets in which we compete. Our revenues and results of operations could be materially adversely affected if the prevailing market prices for natural gas, LNG, electricity or other commodities that we buy change in a direction or manner not anticipated and for which we had not provided adequately through purchase or sale commitments or other hedging transactions. In particular, North American natural gas prices, when in decline, negatively impact profitability at Sempra LNG & Midstream.
Unanticipated changes in market prices for energy-related commodities result from multiple factors, including:
weather conditions
seasonality
changes in supply and demand
transmission or transportation constraints or inefficiencies
availability of competitively priced alternative energy sources
commodity production levels
actions by oil and natural gas producing nations or organizations affecting the global supply of crude oil and natural gas
federal, state and foreign energy and environmental regulation and legislation
natural disasters, wars, embargoes and other catastrophic events
expropriation of assets by foreign countries
The FERC has jurisdiction over wholesale power and transmission rates, independent system operators, and other entities that control transmission facilities or that administer wholesale power sales in some of the markets in which we operate. The FERC may impose additional price limitations, bidding rules and other mechanisms, or terminate existing price limitations from time to time. Any such action by the FERC may result in prices for electricity changing in an unanticipated direction or manner and, as a result, may have a material adverse effect on our businesses, cash flows, results of operations and/or prospects.
When our businesses enter into fixed-price long-term contracts to provide services or commodities, they are exposed to inflationary pressures such as rising commodity prices and interest rate risks.

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Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream generally endeavor to secure long-term contracts with customers for services and commodities to optimize the use of their facilities, reduce volatility in earnings, and support the construction of new infrastructure. However, if these contracts are at fixed prices, the profitability of the contract may be materially adversely affected by inflationary pressures, including rising operational costs, costs of labor, materials, equipment and commodities, and rising interest rates that affect financing costs. We may try to mitigate these risks by using variable pricing tied to market indices, anticipating an escalation in costs when bidding on projects, providing for cost escalation, providing for direct pass-through of operating costs or entering into hedges. However, these measures, if implemented, may not ensure that the increase in revenues they provide will fully offset increases in operating expenses and/or financing costs. The failure to fully or substantially offset these increases could have a material adverse effect on our financial condition, cash flows and/or results of operations.
Business development activities may not be successful and projects under construction may not commence operation as scheduled, be completed within budget or operate at expected levels, which could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.
The acquisition, development, construction and expansion of marine and inland liquid fuels, LNG and LPG terminals and storage; natural gas, propane and ethane pipelines and storage facilities; electric generation, transmission and distribution facilities; and other energy infrastructure projects involve numerous risks. We may be required to spend significant sums for preliminary engineering, permitting, fuel supply, resource exploration, legal, and other expenses before we can determine whether a project is feasible, economically attractive, or capable of being built.
Success in developing a particular project is contingent upon, among other things:
negotiation of satisfactory EPC agreements
negotiation of supply and natural gas sales agreements or firm capacity service agreements
timely receipt of required governmental permits, licenses, authorizations, and rights-of-way and maintenance or extension of these authorizations
timely implementation and satisfactory completion of construction
obtaining adequate and reasonably priced financing for the project
Successful completion of a particular project may be materially adversely affected by, among other factors:
unforeseen engineering problems
construction delays and contractor performance shortfalls
work stoppages
failure to obtain, maintain or extend required governmental permits, licenses, authorizations, and rights-of-way
equipment unavailability or delay and cost increases
adverse weather conditions
environmental and geological conditions
litigation
unsettled property rights
If we are unable to complete a development project or if we have substantial delays or cost overruns, this could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.
The operation of existing and future facilities also involves many risks, including the breakdown or failure of electric generation, transmission and distribution facilities, or regasification, liquefaction and storage facilities or other equipment or processes, labor disputes, fuel interruption, environmental contamination and operating performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, regasification, liquefaction, storage, transmission and distribution systems. The occurrence of any of these events could lead to our facilities being idled for an extended period of time or our facilities operating well below expected capacity levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Such occurrences could materially adversely affect our businesses, financial condition, cash flows, results of operations and/or prospects.
The design, development and construction of the Cameron LNG liquefaction facility involves numerous risks and uncertainties.
With respect to our project to add LNG export capability at the Cameron LNG facility, Cameron LNG JV is building an LNG export facility consisting of three liquefaction trains designed to a total nameplate capacity of 13.9 Mtpa of LNG with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. The estimated construction, financing and other project

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costs for the facility are within the project budget adopted at the time of our final investment decision. If these costs increase above the budget adopted at the time of our final investment decision, we may have to contribute additional cash. The majority of the investment in the liquefaction project is project-financed and the balance provided by the project partners. Any failure by the project partners to make their required investments on a timely basis could result in project delays and could materially adversely affect the development of the project. In addition, Sempra Energy has guaranteed a maximum of up to $3.9 billion related to the project financing and financing-related agreements. These guarantees terminate upon Cameron LNG JV achieving “financial completion” of the initial three-train liquefaction project, including all three trains achieving commercial operation and meeting certain operational performance tests. We anticipate that the guarantees will be terminated approximately nine months after all three trains achieve commercial operation. If, due to the joint venture’s failure to satisfy the financial completion criteria, we are required to repay some or all of the $3.9 billion under our guarantees, any such repayments could have a material adverse effect on our business, results of operations, cash flows, financial condition, and/or prospects.
Large-scale construction projects like the design, development and construction of the Cameron LNG JV liquefaction facility involve numerous risks and uncertainties, including among others, the potential for unforeseen engineering challenges, substantial construction delays and increased costs. Cameron LNG JV has a turnkey EPC contract, and if the contractor becomes unwilling or unable to perform according to the terms and timetable of the EPC contract, the project could face substantial construction delays and potentially significantly increased costs. If the contractor’s delays or failures are serious enough to cause the contractor to default under the EPC contract, such default could result in Cameron LNG JV’s engagement of a substitute contractor. In October 2016, the EPC contractor indicated that the Cameron LNG project would not achieve its originally scheduled dates for completion and subsequently provided project schedules reflecting further delays to the Cameron LNG project. The delays will result in the anticipated earnings and associated cash flows from the Cameron LNG JV project coming in later than originally anticipated. In December 2017, Cameron LNG JV entered into a settlement agreement with the EPC contractor to settle the contractor’s claims (including those resulting from Hurricane Harvey) that it was owed additional compensation beyond the original contract price and that it was entitled to schedule extensions under the contract. Based on a number of factors, we continue to believe it is reasonable to expect that all three LNG trains will be producing LNG in 2019, though there can be no assurance that this project will not be further delayed. These factors, among others, include the terms of the settlement agreement, the project schedules received from the EPC contractor, Cameron LNG JV’s own review of the project schedules, the assumptions underlying such schedules, the EPC contractor’s progress to date, the remaining work left to be performed, and the inherent risks in constructing and testing facilities such as Cameron LNG. The inability to complete the project in accordance with the current schedule, cost overruns, and the other risks described above could have a material adverse effect on our business, results of operations, cash flows, financial condition, credit ratings and/or prospects. For additional discussion of the Cameron LNG JV and of these risks and other risks relating to the development of the Cameron LNG JV liquefaction project that could adversely affect our future performance, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Factors Influencing Future Performance.”
We face many challenges to develop and complete our contemplated LNG export facilities.
In addition to the three-train Cameron LNG liquefaction facility described above, we are looking at several other LNG export terminal development opportunities, including a greenfield project in Port Arthur, Texas, a brownfield project at our existing ECA regasification facility in Baja California, Mexico and an expansion of up to two additional liquefaction trains to the Cameron liquefaction facility. Each of these contemplated projects faces numerous risks and must overcome significant hurdles before we can proceed with construction. Common to all of these projects is the risk that global oil prices and their associated current and forward projections could reduce the demand for natural gas in some sectors and cause a corresponding reduction in projected global demand for LNG. This could result in increased competition among those working on projects in an environment of declining LNG demand, such as the Sempra Energy-sponsored export initiatives. Such reduction in natural gas demand could also occur from higher penetration of alternative fuels in new power generation, which could also lead to increased competition among the LNG suppliers for the declining LNG demand. At certain moderate levels, oil prices could also make LNG projects in other parts of the world still feasible and competitive with LNG projects from North America, thus increasing supply and the competition for the available LNG demand. A decline in natural gas prices outside the U.S. (which in many foreign countries are based on the price of crude oil) may also materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing).
In February 2018, Sempra LNG & Midstream entered into a project development agreement for the joint development of the proposed Port Arthur LNG liquefaction project with an affiliate of Woodside Petroleum Ltd., which replaced a prior agreement between the parties. The project development agreement specifies how the parties will share costs, and continues a framework for the parties to work jointly on permitting, design, engineering, commercial and marketing activities associated with developing the Port Arthur LNG liquefaction project. In June 2017, Sempra LNG & Midstream, Woodside Petroleum Ltd. and Korea Gas Corporation signed a memorandum of understanding that provides a framework for cooperation and joint discussion by the parties

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regarding key aspects of the potential development of the Port Arthur LNG project, including engineering and construction work, O&M activities, feed gas sourcing, offtake of LNG and the potential for Korea Gas Corporation to purchase LNG from, and become an equity participant in, the Port Arthur LNG project. The memorandum of understanding does not commit any party to buy or sell LNG or otherwise participate in the Port Arthur liquefaction LNG project. Also, in May 2015, Sempra LNG & Midstream, IEnova and a subsidiary of PEMEX entered into a project development agreement for the joint development of the proposed liquefaction project at IEnova’s existing ECA regasification facility in Mexico. The agreement specifies how the parties share costs, and establishes a framework for the parties to work jointly on permitting, design, engineering, and commercial activities associated with developing the potential liquefaction project. PEMEX’s cost-sharing obligations under this agreement ended on December 31, 2017. Any decisions by the parties to proceed with binding agreements with respect to the formation of these potential joint ventures and the potential development of these projects will require, among other things, obtaining customer commitments to purchase LNG, completion of project assessments and achieving other necessary internal and external approvals of each party. In addition, all of our proposed projects are subject to a number of risks and uncertainties, including the receipt of a number of permits and approvals; finding suitable partners and customers; obtaining financing and incentives; negotiating and completing suitable commercial agreements, including joint venture agreements, tolling capacity agreements or natural gas supply and LNG sales agreements and construction contracts; and reaching a final investment decision.
Expansion of the Cameron LNG liquefaction facility beyond the first three trains is subject to certain restrictions and conditions under the joint venture project financing agreements, including among others, timing restrictions on expansion of the project unless appropriate prior consent is obtained from the project lenders. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all of the partners, including with respect to the equity investment obligation of each partner. One of the partners indicated to Sempra Energy and the other partners that it does not intend to invest additional capital in Cameron LNG JV with respect to the expansion. As a result, discussions among the partners have occurred, and we are considering a variety of options to attempt to move the expansion project forward. These activities have contributed to delays in developing firm pricing information and securing customer commitments, and there can be no assurance that these issues will be resolved in a timely manner, which could materially and adversely impact the near-term marketing of this project and ability to secure customer commitments. In light of these developments, we are unable to predict whether or when we and/or Cameron LNG JV might be able to move forward on expansion of the Cameron LNG liquefaction facility beyond the first three trains.
Furthermore, there are a number of potential new projects under construction or in the process of development by various project developers in North America, in addition to ours, and given the projected global demand for LNG, the vast majority of these projects likely will not be completed. With respect to our Port Arthur, Texas project, this is a greenfield site, and therefore it may not have the advantages often associated with brownfield sites. The ECA facility in Mexico is subject to on-going land disputes that could make project financing difficult as well as finding suitable partners and customers. In addition, while we have completed the regulatory process for an LNG export facility in the U.S., the regulatory process in Mexico and the overlay of U.S. regulations for natural gas exports to an LNG export facility in Mexico are not well developed. There can be no assurance that such a facility could be permitted and constructed without facing significant legal challenges and uncertainties, which in turn could make project financing, as well as finding suitable partners and customers, difficult. Finally, ECA has profitable long-term regasification contracts for 100 percent of the facility, making the decision to pursue a new liquefaction facility dependent in part on whether the investment in a new liquefaction facility would, over the long term, be more beneficial than continuing to supply regasification services under our existing contracts.
There can be no assurance that our contemplated LNG export facilities will be completed, and our inability to complete one or more of our contemplated LNG export facilities could have a material adverse effect on our future cash flows, results of operations and prospects.
We discuss these projects further in “Item 1. Business” and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could reduce or eliminate LNG export opportunities and demand.
Several states have adopted or are considering adopting regulations to impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict the performance of or prohibit the well drilling in general and/or hydraulic fracturing in particular. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies, including the EPA and the Bureau of Land Management of the U.S. Department of the Interior, have asserted regulatory authority over certain hydraulic fracturing activities. In addition, the U.S. Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require

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disclosure of the chemicals used in the hydraulic fracturing process. There are also certain governmental reviews that have been conducted or are underway on deep shale and other formation completion and production practices, including hydraulic fracturing. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate or even ban such activities. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.
We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, natural gas prices in North America could rise, which in turn could materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing). Increased regulation or difficulty in permitting of hydraulic fracturing, and any corresponding increase in domestic natural gas prices, could materially adversely affect demand for LNG exports and our ability to develop commercially viable LNG export facilities beyond the three train Cameron LNG facility currently under construction.
Increased competition and changes in trade policies could materially adversely affect us.
The markets in which we operate are characterized by numerous strong and capable competitors, many of whom have extensive and diversified developmental and/or operating experience (including both domestic and international) and financial resources similar to or greater than ours. Further, in recent years, the natural gas pipeline, storage and LNG market segments have been characterized by strong and increasing competition both with respect to winning new development projects and acquiring existing assets. In Mexico, despite the commissioning of many new energy infrastructure projects by the CFE and other governmental agencies in connection with energy reforms, competition for recent pipeline projects has been intense with numerous bidders competing aggressively for these projects. There can be no assurance that we will be successful in bidding for new development opportunities in the U.S., Mexico or South America. In addition, as noted above, there are a number of potential new LNG liquefaction projects under construction or in the process of being developed by various project developers in North America, including our contemplated new projects, and given the projected global demand for LNG, it is likely that most of these projects will not be completed. Finally, as existing contracts expire at our natural gas storage assets in the Gulf Coast region, we compete with other facilities for storage customers that could continue to support the existing carrying value of these assets, and for anchor customers that could support development of new capacity. These competitive factors could have a material adverse effect on our business, results of operations, cash flows and/or prospects.
In addition, the current U.S. Administration has indicated its intention to renegotiate trade agreements, such as NAFTA. A shift in U.S. trade policies could materially adversely affect our LNG development opportunities, as well as opportunities for trade between Mexico and the U.S.
We may elect not to, or may not be able to, enter into, extend or replace expiring long-term supply and sales agreements or long-term firm capacity agreements for our projects, which would subject our revenues to increased volatility and our businesses to increased competition. Such long-term contracts, once entered into, increase our credit risk if our counterparties fail to perform or become unable to meet their contractual obligations on a timely basis due to bankruptcy, insolvency, or otherwise.
The ECA LNG facility has long-term capacity agreements with a limited number of counterparties. Under these agreements, customers pay capacity reservation and usage fees to receive, store and regasify the customers’ LNG. We also may enter into short-term and/or long-term supply agreements to purchase LNG to be received, stored and regasified for sale to other parties. The long-term supply agreement contracts are expected to reduce our exposure to changes in natural gas prices through corresponding natural gas sales agreements or by tying LNG supply prices to prevailing natural gas market price indices. If the counterparties, customers or suppliers to one or more of the key agreements for the ECA LNG facility were to fail to perform or become unable to meet their contractual obligations on a timely basis, it could have a material adverse effect on our results of operations, cash flows and/or prospects.
For the three-train liquefaction facility currently under construction, Cameron LNG JV has 20-year liquefaction and regasification tolling capacity agreements in place with ENGIE S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co. Ltd., that subscribe for the full nameplate capacity of the facility. If the counterparties to these tolling agreements were to fail to perform or become unable to meet their contractual obligations to Cameron LNG JV on a timely basis, it could have a material adverse effect on our results of operations, cash flows and/or prospects.
Sempra Mexico’s and Sempra LNG & Midstream’s ability to enter into or replace existing long-term firm capacity agreements for their natural gas pipeline operations are dependent on demand for and supply of LNG and/or natural gas from their transportation customers, which may include our LNG facilities. A significant sustained decrease in demand for and supply of LNG and/or

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natural gas from such customers could have a material adverse effect on our businesses, results of operations, cash flows and/or prospects.
Our natural gas storage assets include operational and development assets at Bay Gas in Alabama and Mississippi Hub in Mississippi, as well as our development project, LA Storage in Louisiana. LA Storage could be positioned to support LNG export from the Cameron LNG JV terminal and other liquefaction projects, if anticipated cash flows support further investment. However, changes in the U.S. natural gas market could also lead to diminished natural gas storage values. Historically, the value of natural gas storage services has positively correlated with the difference between the seasonal prices of natural gas, among other factors. In general, over the past several years, seasonal differences in natural gas prices have declined, which have contributed to lower prices for storage services. As our legacy (higher rate) sales contracts mature at our Bay Gas and Mississippi Hub facilities, replacement sales contract rates have been and could continue to be lower than has historically been the case. Lower sales revenues may not be offset by cost reductions, which could lead to depressed asset values. Future investment in Bay Gas, Mississippi Hub and LA Storage will depend on market demand and estimates of long-term storage values. Our LA Storage development project construction permit expired in June 2017 and future development will require approval of a new construction permit by the FERC. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage Pipeline, that is not contracted. Market conditions could result in the need to perform recovery testing of our recorded asset values. In the event such values are not recoverable, we would consider the fair value of these assets relative to their carrying value. To the extent the carrying value is in excess of the fair value, we would record a noncash impairment charge. The carrying value of our long-lived natural gas storage assets at December 31, 2017 was $1.5 billion. A significant impairment charge related to our natural gas storage assets would have a material adverse effect on our results of operations in the period in which it is recorded.
The electric generation and wholesale power sales industries are highly competitive. As more plants are built and competitive pressures increase, wholesale electricity prices may become more volatile. Without the benefit of long-term power sales agreements, our revenues may be subject to increased price volatility, and we may be unable to sell the power that Sempra Renewables’ and Sempra Mexico’s facilities are capable of producing or to sell it at favorable prices, which could materially adversely affect our results of operations, cash flows and/or prospects.
We provide information about these matters in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Our businesses depend on counterparties, business partners, customers, and suppliers performing in accordance with their agreements. If they fail to perform, we could incur substantial expenses and business disruptions and be exposed to commodity price risk and volatility, which could materially adversely affect our businesses, financial condition, cash flows, results of operations and/or prospects.
Our businesses, and the businesses that we invest in, are exposed to the risk that counterparties, business partners, customers, and suppliers that owe money or commodities as a result of market transactions or other long-term agreements or arrangements will not perform their obligations in accordance with such agreements or arrangements. Should they fail to perform, we may be required to enter into alternative arrangements or to honor the underlying commitment at then-current market prices. In such an event, we may incur additional losses to the extent of amounts already paid to such counterparties or suppliers. In addition, many such agreements are important for the conduct and growth of our businesses. The failure of any of the parties to perform in accordance with these agreements could materially adversely affect our businesses, results of operations, cash flows, financial condition and/or prospects. Finally, we often extend credit to counterparties and customers. While we perform significant credit analyses prior to extending credit, we are exposed to the risk that we may not be able to collect amounts owed to us.
Sempra Mexico’s and Sempra LNG & Midstream’s obligations and those of their suppliers for LNG supplies are contractually subject to (1) suspension or termination for “force majeure” events beyond the control of the parties; and (2) substantial limitations of remedies for other failures to perform, including limitations on damages to amounts that could be substantially less than those necessary to provide full recovery of costs for breach of the agreements, which in either event could have a material adverse effect on our results of operations, cash flows, financial condition and/or prospects.
Our businesses are subject to various legal actions challenging our property rights and permits.
We are engaged in disputes regarding our title to the properties adjacent to and properties where our ECA LNG terminal in Mexico is located, as we discuss in Note 15 of the Notes to Consolidated Financial Statements. In the event that we are unable to defend and retain title to the properties on which our ECA LNG terminal is located, we could lose our rights to occupy and use such properties and the related terminal, which could result in breaches of one or more permits or contracts that we have entered into with respect to such terminal. In addition, our ability to convert the ECA LNG terminal into an export facility may be hindered by these disputes, and they could make project financing such a facility and finding suitable partners and customers very

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difficult. If we are unable to occupy and use such properties and the related terminal, it could have a material adverse effect on our businesses, financial condition, results of operations, cash flows and/or prospects.
We rely on transportation assets and services, much of which we do not own or control, to deliver electricity and natural gas.
We depend on electric transmission lines, natural gas pipelines, and other transportation facilities owned and operated by third parties to:
deliver the electricity and natural gas we sell to wholesale markets,
supply natural gas to our gas storage and electric generation facilities, and
provide retail energy services to customers.
Sempra Mexico and Sempra LNG & Midstream also depend on natural gas pipelines to interconnect with their ultimate source or customers of the commodities they are transporting. Sempra Mexico and Sempra LNG & Midstream also rely on specialized ships to transport LNG to their facilities and on natural gas pipelines to transport natural gas for customers of the facilities. Sempra Renewables, Sempra South American Utilities and Sempra Mexico rely on transmission lines to sell electricity to their customers. If transportation is disrupted, or if capacity is inadequate, we may be unable to sell and deliver our commodities, electricity and other services to some or all of our customers. As a result, we may be responsible for damages incurred by our customers, such as the additional cost of acquiring alternative electricity, natural gas supplies and LNG at then-current spot market rates, which could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.
Our international businesses are exposed to different local, regulatory and business risks and challenges.
In Mexico, we own or have interests in natural gas distribution and transportation, LPG storage and transportation facilities, ethane transportation, electricity generation, and LNG and liquid fuels marine and inland terminals. In Peru and Chile, we own or have interests in electricity generation, transmission and distribution facilities and operations. Developing infrastructure projects, owning energy assets, and operating businesses in foreign jurisdictions subject us to significant security, political, legal, regulatory and financial risks that vary by country, including:
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
governance by and decisions of local regulatory bodies, including setting of rates and tariffs that may be earned by our businesses
adverse changes in market conditions and inadequate enforcement of regulations
high rates of inflation
volatility in exchange rates between the U.S. dollar and currencies of the countries in which we operate, as we discuss below
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
changes in government policies or personnel
trade restrictions
limitations on U.S. company ownership in foreign countries
permitting and regulatory compliance
changes in labor supply and labor relations
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 and other foreign jurisdictions
expropriation of assets
destruction of property or assets
adverse changes in the stability of the governments in the countries in which we operate
general political, social, economic and business conditions
compliance with the Foreign Corrupt Practices Act and similar laws
valuation of goodwill
theft of assets
Our international businesses also are subject to foreign currency risks. These risks arise from both volatility in foreign currency exchange and inflation rates and devaluations of foreign currencies. In such cases, an appreciation of the U.S. dollar against a local currency could materially reduce the amount of cash and income received from those foreign subsidiaries. We may or may

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not choose to hedge these risks, and any hedges entered into may or may not be effective. Fluctuations in foreign currency exchange and inflation rates may result in significantly increased taxes in foreign countries and materially adversely affect our cash flows, financial condition, results of operations and/or prospects.
We discuss litigation related to Sempra Mexico’s international energy projects in Note 15 of the Notes to Consolidated Financial Statements.
Risks Related to the Pending Acquisition of Energy Future Holdings Corp.
In this “Risk Factors” section, we sometimes refer to Sempra Energy, after